World Oil - Modern Sandface Completion Practices Handbook

Modern Sandface Completion Practices H A N D B O O K

First Edition William K. Ott, P.E. and Joe D. Woods A Supplement to World Oil

Publication of the World Oil Modern Sandface Completion Practices Handbook was made possible by the support of the following sponsors: Premier Sponsors:

Sponsors:

Baker Oil Tools

Borden Chemical, Inc., Oilfield Products Division

BJ Services Company

Cabot Specialty Fluids, Inc.

Core Laboratories

Carbo Ceramics Inc.

Halliburton Energy Services

Champion Technologies, Special Products Division

Reslink

con-slot Screens International GMBH

Schlumberger

Greig Filters, Inc.

Weatherford International Ltd.

Grupo Royso, C.A. M-I L.L.C. Norton Proppants, Inc. Red Wing Perforating Services L.L.C. Smith Services, a Business Unit of Smith International, Inc. STREN Company TBC-Brinadd Thru-Tubing Systems, Inc. Tucan Petroleum Services, C.A. Well Flow International

About the cover: Various methods for controlling sand production in open- and cased- hole completions are shown. Illustration was adapted from one appearing in BP’s Frontiers magazine, December 2001.

World Oil

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Modern Sandface Completion Practices HANDBOOK

A treatise on reliable techniques to complete unconsolidated sandstone reservoirs at the sandface (the physical interface between the formation and the wellbore), using sand management and sand control methods.

William K. Ott, P.E., and Joe D. Woods

Published by World Oil magazine Gulf Publishing Company Houston, Texas

ABOUT THE AUTHORS

WILLIAM K. (BILL) OTT, P.E., is an independent petroleum consultant based in Houston, Texas, and founder of Well Completion Technology, an international engineering consulting and petroleum industry training firm that was established in 1986. Before consulting and teaching, Mr. Ott was division engineer for Halliburton’s Far East region based in Singapore. Previously he was a research field coordinator for Halliburton in Duncan, Oklahoma. Mr. Ott received his BS Degree in chemical engineering from the University of Missouri (1972). He is a registered professional engineer in Texas, and a 25-year member of SPE. He works regularly with and on wells requiring sand control, principally in East Asia and South America. He has conducted technical petroleum industry courses worldwide and written numerous technical papers relating to well completion and workover operations. Mr. Ott teaches a Sand Control Technology course several times each year in the U.S., Canada, Southeast Asia and South America. He can be reached via e-mail at: [email protected]. JOE D. WOODS is a Houston-based freelance writer and marketing consultant. He is founder of International Pinpoint, a marketing and advertising consulting firm specializing in the petroleum industry. For twelve years, Mr. Woods was director of marketing for Gulf Publishing Company. Mr. Woods has over 28 years of diversified experience in the oil and gas industry. Previously he was vice president of marketing for GEO International Corp., a multi-division NYSE-listed oil field services firm, which grew rapidly in the late 1970s and early 1980s. He also held key marketing-related positions with Halliburton Company in Duncan, Oklahoma, and Houston, Texas. In the mid-1970s, he was instrumental in developing curriculum for the Modern Well Completion Practices School at the Halliburton Energy Institute. Prior to that he was a marketing specialist with Texas Instruments. He has written and produced hundreds of hours of employee and customer training materials in the petroleum and electronic industries. Mr. Woods has held memberships in AMA, BMA and PRSA, and has been an associate member of SPE and a corporate representative member of SEG. A Distinguished Student at Texas A&M University, he received his Bachelor's degree from the University of North Texas (1972). Mr. Woods can be reached via e-mail at: [email protected].

ii

Acknowledgments More than 20 companies sponsored the preparation of this handbook. The authors greatly appreciate this sponsorship, and the technical and editorial assistance of these companies and numerous individuals. Without their cooperation and the release of their data, the publication of this handbook would not have been possible. In part, this work is a summary of technology already published by hundreds of others. That collective effort is greatly respected, and it is hoped that the references cited are some measure of permanent recognition.

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World Oil Modern Sandface Completion Practices Handbook First Edition US$95.00 per single copy To order additional copies of this handbook or for educational and volume discounts, contact the publisher at the address below.

Copyright © 2003 by Gulf Publishing Company, Houston, Texas. All rights reserved. Printed in the United States of America. This handbook, or parts thereof, may not be reproduced in any form without permission of the publisher.

Gulf Publishing Company P.O. Box 2608 Houston, Texas 77252 Phone: 713.529.4301 www.gulfpub.com

Gulf Publishing Company and the authors have used their best efforts in collecting and preparing material for inclusion in this handbook, but do not warrant that the information herein is complete or accurate. Errors and omissions, typographical, clerical and otherwise, can occur and this possibility exists in respect to anything contained in this work. Gulf Publishing Company and the authors do not assume, and hereby disclaim, any liability to any person for any loss or damage caused by errors or omissions related to this handbook whether such errors or omissions result from negligence, accident or any other cause. This applies to product and service information, trademark information, directory listings, as well as all other matter contained herein.

iii

PREFACE

The business of completing oil and gas wells in unconsolidated sandstone reservoirs is continually changing with new challenges, new methods and new technologies. Sand, when produced with hydrocarbons and water from many wells, represents a costly problem for operators. Cost effective solutions for controlling sand production are many, ranging from stand-alone screens to conventional gravel packs to high rate water packs to frac packs and more. Most often operators elect to employ various sand exclusion techniques when completing a well. In some areas, it may be more economical to employ sand management techniques in an effort to minimize or delay expected problems such as formation erosion, sand fill, production interruptions or even eventual wellbore collapse. The true success or failure of a sand control application must always be measured against three related criteria: • Stopping the movement and production of sand • Maintaining maximum well productivity • Paying for treatment costs and realizing a satisfactory return on investment within a reasonable period of time. This handbook provides reliable techniques, updates industry methods and presents valuable new technologies used to complete unconsolidated sandstone reservoirs. Numerous illustrations complement the text, and there is an extensive list of references. The techniques and equipment described have been field-proven in thousands of oil and gas wells around the world. Operators must know when to apply the different solutions. This book has been prepared in an effort to provide the knowledge required for choosing the optimum solution.

iv

CONTENTS

Chapter One

Chapter Two

1 1 3 5 7 9 10 10

Causes and Effects of Sand Production Understanding the Reservoir Productivity, Formation Damage and Flow Efficiency Sand Management Techniques Justification for Sand Control Types of Sand Control Drilling, Cementing and Completion Considerations

13

Open-Hole Sandface Completions

13

38

Drill-In Fluids Fluid Loss Completion Considerations Filter-Cake Removal Stand-Alone Screens Slotted Liners Conventional, Prepacked and Premium Screens Stand-Alone Completion Assemblies Gravel Packing Gravel-Pack Sand Sizing and Substitutes Slotted Liner and Screen Design Gravel-Pack Methods Alternate Pathway Screen Option Open-Hole Frac Packing

43

Cased-Hole Sandface Completions

43

Completion Fluids Use of Completion Fluids Selection Criteria Fluid Loss Control Debris Removal and Mysteries Displacement Procedures Pump Rates and Pressure Calculations Fluid Filtration Filtration Guidelines Relationship between Completion and Filtration Filter Level Quality Completion Fluid Filter Types Filtration Quality Control Perforating Gun Design and Deployment Techniques Detonation Methods Well/Reservoir Characteristics Perforation Clean Out Special Perforating Techniques Perforating Summary Stand-Alone Screens

18

24

Chapter Three

Controlling Sand-Related Production Problems

49 51

59

70

v

71

81

97

Chapter Four

103

Surface Operations and Equipment

103

Surface Equipment and Techniques Mixing and Blending Equipment Pumping Equipment Proppant Handling Offshore Equipment Monitoring and Control Monitoring and Control Equipment Design and Simulation Evaluation Techniques Gravel-Pack Evaluation HRWP and Frac-Pack Evaluation

105 109

Chapter Five

Gravel Packing Perforation Prepacking Water Packs Slurry Packs Well Productivity Carrier Fluid Selection Field Evaluation Gravel-Pack Methods One-Trip Perforate and Pack System Frac Packing Comparison of Frac Packs and Gravel Packs Comparison of Frac Packs and HRWPs Hydraulic Fracturing Concepts, Geometry and Rock Mechanics Frac Fluids and Proppants Pretreatment Testing Frac-Pack Methods/Applications Gravel-Packing Method Selection

113

Alternative Practices and Special Techniques

113

Rigless Sand Control Techniques Chemical Methods Mechanical Methods Specialty Tools and Techniques Wireline Gravel Pack VibraPak Multilaterals Rod Pump and ESP Sand Control Techniques

118

Chapter Six

125

Next Generation Completion Technologies

Appendix One Appendix Two Appendix Three

127 129 131 133 139

Gravel/Proppant Graphic and Illustration Credits/Sources Contributor Profiles and Acknowledgments Service/Supplier Directory Index

vi

CHAPTER ONE

Controlling Sand-Related Production Problems Causes and Effects of Sand Production • Understanding the Reservoir Productivity, Formation Damage and Flow Efficiency • Sand Management Techniques Justification for Sand Control • Types of Sand Control • Drilling, Cementing and Completion Considerations s the value of non-renewable hydrocarbon reserves and the costs of remedial work increase, a renewed emphasis is being placed on proper well completion techniques. Maximum reliability and productivity are essential. These objectives are difficult to attain in unconsolidated sand formations, which are always subject to structural failure. The sand production mechanism is exceedingly complex and is influenced by every completion operation. This handbook will summarize the major problems encountered in unconsolidated sands, as well as current techniques and technologies employed in sandface completions. The techniques and equipment described have been field-proven in thousands of oil and gas wells. Sand flow—and the multitude of inconveniences, production losses, and serious well damage it can cause—is discussed with a view toward understanding fundamental causes and implementing early preventive measures.

A

Causes and Effects of Sand Production In highly unconsolidated formations, the production of formation fluids will probably be associated with the production of formation sand. In some situations, small quantities of formation sand can be produced with no significant adverse effects; however, in most cases, sand production leads to reduced productivity and/or excessive maintenance to both downhole and surface equipment. Sufficient sand production may also cause premature failure of the wellbore and well equipment. Nature of Sand Production Conditions that can cause sand production and the probable condition of the formation outside of the casing after

sand is produced can be determined by the factors that affect the beginning of sand production. These factors must describe both the nature of the formation material and also the forces that cause the formation structure to fail. Strength of sandstone is controlled by: • Amount and type of cementation material holding the individual grains together • Frictional forces between grains • Fluid pressure within the pores of the rock • Capillary pressure forces Several researchers have investigated the type of failure that is likely to occur in sandstone. Work at Exxon1 indicates that the nature of a failed perforation tunnel is indicative of a shear failure that will occur when the compressive strength of the rock is exceeded. In addition, the Exxon work indicates that in weakly consolidated sandstones, a void is frequently created behind the casing. Exxon concluded that the formation’s compressive strength should be a good indicator of sand production potential, and that sand production will probably cause a void behind the casing that can be filled with gravel pack sand during a gravel packing operation. The mechanical failure of unconsolidated rock surrounding a perforation is analogous to the failure of a loose material surrounding a tunnel in soft earth. Terzaghi described the mechanism for load transfer surrounding a tunnel in such a situation2 in 1943. As the material over the tunnel yields, the stress originally held in the yielded material is relieved and transferred to the more rigid material surrounding the tunnel. However, a portion of the original stresses is supported by intergranular friction above the tunnel. To a certain extent, the arching concepts used in tunneling apply to the

unconsolidated rock surrounding a perforation. After some sand is produced from around a perforation tunnel, an arch is formed that has sufficient strength to support the weight of the surrounding material. Under certain conditions, the production of a limited amount of formation sand can be tolerated to allow an arch to develop, after which the production of formation sand ceases.3 Figure 1.1 illustrates the concept of a stable arch around a perforation; however, the stability of the arch is complicated by the fact that the state of stress surrounding the perforation is constantly changing due to changes in flow rate, reservoir pressure, producing water cut, etc.

Fluid inflow Cement

Perforation tunnel

Sand grains under triaxial loading Fluid inflow

Fig. 1.1. Geometry of stable arch surrounding a perforation

Effects of Sand Production The effects of sand production are nearly always detrimental to the short and/or long-term productivity of a well. Although some wells routinely experience manageable sand production, these wells are the exception, not the rule. In most cases, attempting to manage the effects of severe sand produc1

Modern Sandface Completion Practices

tion over the life of the well is not an economically attractive or a prudent operating alternative. Accumulation in surface squipment. If the production velocity is great enough to carry sand up the tubing, the sand may become trapped in the separator, heater treater, or production pipeline. If a large enough volume of sand becomes trapped in one of these areas, cleaning will be required to allow for efficient production of the well. To restore production, the well must be shut-in, the surface equipment opened, and the sand manually removed. In addition to the clean out cost, the cost of the deferred production must be considered. If a separator is partially filled with sand, the capacity of the separator to handle oil, gas and water is reduced. For example, one cubic foot of sand in an oil/water separator with a two-minute residence time will cause the separator to handle 128 fewer barrels of liquid per day. If the ratio of oil to water entering the separator is one to one (i.e., 50% water cut), the separator will deliver 64 fewer barrels of salable oil per day. At US$18/bbl, this adds up to US$420,480 worth of oil per year that is not moving through the separator. Accumulation downhole. If the production velocity is not great enough to carry sand to the surface, the sand may bridge-off in the tubing or fall and begin to fill the inside of the wellbore or casing. Eventually, the producing interval may be completely covered with sand. In either case, the production rate will decline until the well becomes sanded-up and production ceases. In situations like this, remedial operations are required to clean out the well and restore production. One clean-out technique is to run a bailer on the end of slick line to remove the sand from the wellbore. Since the bailer removes only a small volume of sand at a time, multiple slick line runs are necessary to clean out the well. Another clean-out operation involves running a smaller diameter tubing string or coiled tubing down into the production tubing to agitate the sand and lift it out of the well by circulating fluid. The inner string is lowered while circulating the sand out of the well. This 2

operation must be performed cautiously to avoid the possibility of sticking the inner string inside the production tubing. If the production of sand is continuous, the clean-out operations may be required on a routine basis, as often as monthly or even weekly. This will result in lost production and increased well maintenance cost. Erosion of downhole and surface equipment. In highly productive wells, fluids flowing at high velocity and carrying sand can produce excessive erosion of both downhole and surface equipment leading to frequent maintenance to replace the damaged equipment. If the erosion is severe or occurs over a sufficient length of time, complete failure of surface and/or downhole equipment may occur, resulting in critical safety and environmental problems as well as deferred production. For some equipment failures, a rigassisted workover may be required to repair the damage. Collapse of the formation. Large volumes of sand may be carried out of the formation with produced fluid. If the rate of sand production is great enough and continues for a sufficient period of time, an empty area or void can develop behind the casing and can continue to grow larger as more sand is produced. When the void becomes large enough, the overlying shale or formation sand above the void may collapse into the void due to a lack of material to provide support. When this collapse occurs, the sand grains rearrange themselves to create a lower permeability than originally existed. This will be especially true for formation sand with a high clay content or wide range of grain sizes. For formation sand with a narrow grain-size distribution and/or very little clay, the rearrangement of formation sand will cause a change in permeability that may be less obvious. In the case of overlying shale collapsing, complete loss of productivity is probable. In most cases, continued long-term production of formation sand will usually decrease the well’s productivity and ultimate recovery. The collapse of the formation is particularly important if the formation material fills or partially fills the perforation tunnels. Even a small amount of

formation material filling the perforation tunnels will lead to a significant increase in pressure drop across the formation near the wellbore for a given flow rate. Causes of Sand Production The solid material produced from a well can consist of both formation fines (usually not considered part of the formation’s mechanical framework) and load bearing solids. The production of fines cannot normally be prevented and is actually beneficial. Fines moving freely through the formation or an installed gravel pack are preferable to plugging of the formation or gravel pack. The critical factor to assessing the risk of sand production is whether or not the production of load-bearing particles can be maintained below an acceptable level at anticipated flow rates and producing conditions. The factors that influence the tendency of a well to produce sand are the: • Degree of formation consolidation • Reduction in pore pressure throughout the life of the well • Production rate • Reservoir fluid viscosity • Increase of water production throughout the life of the well These factors can be categorized into rock strength effects and fluid flow effects. Each of these factors and their role in the prevention or initiation of sand production is discussed in the remainder of this chapter. Degree of consolidation. The ability to maintain open perforation tunnels is closely tied to the cementation of the sand grains around the tunnels. The cementation of sandstone is typically a secondary geological process and, as a general rule, older sediments tend to be more consolidated than newer sediments. This indicates that sand production is normally a problem when producing from shallow, geologically younger Tertiary sedimentary formations. Such formations are typically located in the Gulf of Mexico, California, Nigeria, French West Africa, Venezuela, Trinidad, Egypt, Italy, China, Malaysia, Brunei and Indonesia, among others. Young Tertiary formations often have little matrix material (cementation

Chapter One Controlling Sand-Related Production Problems

material) bonding the sand grains together. These formations are generally referred to as being poorly consolidated or unconsolidated. A mechanical characteristic of rock that is related to the degree of consolidation is called compressive strength. Poorly consolidated sandstone formations usually have a compressive strength that is less than 1,000 psi. Additionally, degrading the matrix material, which would allow sand production, may change even well consolidated sandstone formations. This can be the result of acidizing treatments or high temperature, steam flood techniques. Reduction of pore pressure. As mentioned previously, the pressure in the reservoir supports some of the weight of the overlying rock. As the reservoir pressure is depleted throughout the producing life of a well, some of the support for the overlying rock is removed. Lowering the reservoir pressure creates an increasing amount of stress on the formation sand itself. At some point, the formation sand grains may break loose from the matrix, or may be crushed, creating fines that are produced along with the well fluids. Compaction of the reservoir rock due to a reduction in pore pressure can result in surface subsidence. For example, the Ekofisk central platform in the North Sea is reported to have sunk 10 ft in its first 10 years of existence due to subsidence. Production rate. The production of reservoir fluids creates pressure differential and frictional drag forces that can combine to exceed the formation compressive strength. This indicates that there is a critical flow rate for most wells below which pressure differential and frictional drag forces are not great enough to exceed the formation compressive strength and cause sand production. The critical flow rate of a well may be determined by slowly increasing the production rate until sand production is detected. One technique used to minimize the production of sand is to choke the flow rate down to the critical flow rate where sand production does not occur or occurs at an acceptable level. In many cases, this flow rate is significantly below the acceptable production rate for the well.

Reservoir fluid viscosity. The frictional drag force exerted on the formation sand grains is created by the flow of reservoir fluid. This frictional drag force is directly related to the velocity of fluid flow and the viscosity of the reservoir fluid being produced. High reservoir fluid viscosity will apply a greater frictional drag force to the formation sand grains than will a reservoir fluid with a low viscosity. The influence of viscous drag causes sand to be produced from heavy oil reservoirs that contain low-gravity, high-viscosity oils even at low-flow velocities. Increasing water production. Sand production may increase or begin as water begins to be produced or as water cut increases. Two possibilities may explain many of these occurrences. First, for a typical water-wet sandstone formation, some grain-to-grain cohesiveness is provided by the surface tension of the connate water surrounding each sand grain. At the onset of water production, the connate water tends to cohere to the produced water, resulting in a reduction of the surface tension forces and subsequent reduction in the grain-to-grain cohesiveness. Water production has been shown to severely limit the stability of the sand arch around a perforation resulting in the initiation of sand production.4 A second mechanism, by which water production affects sand production, is related to the effects of relative permeability. As the water cut increases, the relative permeability to oil decreases. This results in an increasing pressure differential being required to produce oil at the same rate. An increase in pressure differential near the wellbore creates a greater shear force across the formation sand grains. Once again, the higher stresses can lead to instability of the sand arch around each perforation (Fig. 1.1) yielding subsequent sand production.

Understanding the Reservoir By understanding the reservoir, it may be possible to predict whether a well will produce fluids without producing sand or predicting that some type of sand control will be required. In spite of the fact that there are a number of analytical techniques and guidelines devel-

oped to assist in determining if sand control is necessary, no technique has proven to be universally acceptable or completely accurate. In some geographic regions, guidelines and rulesof-thumb apply that have little validity in other areas of the world. At the current time, predicting whether a formation will or will not produce sand is not an exact science and more refinement is needed. Until better prediction techniques are available, the best way of determining the need for sand control in a particular well is to perform an extended production test with a conventional completion and observe if sand production occurs. Of course, any reservoir data should be correlated with available open-hole logs and formation core sample data as they form the foundation for understanding any reservoir. Formation Strength The general procedure followed by most operators considering whether or not sand control is required, is to determine the hardness of the formation rock (i.e., the rock’s compressive strength). Since the rock’s compressive strength has the same units as the pressure drawdown in the reservoir, the two parameters can be compared on a one-to-one basis and drawdown limits for specific wells can be determined. Research performed at Exxon5 in the early 1970s shows that there is a relationship between the compressive strength and the incidence of rock failure. These studies show that the rock failed and began to produce sand when the drawdown pressure is 1.7 times the compressive strength. As an example, formation sand with a compressive strength of 1,000 psi would not fail or begin to produce sand until the drawdown was about 1,700 psi. The testing described was performed in the equipment illustrated in Figure 1.2 and an example of rock sample failure is shown in Figure 1.3. The correlation of the data from the research is shown in Figure 1.4. Other operators use Brinnell hardness of the rock as an indicator of whether to apply sand control. Actually, the Brinnell hardness of the rock is related to the compressive strength but is not as convenient to use since the 3

Modern Sandface Completion Practices

travel time. Short travel times, (for example, 50 microseconds) are indicative of low porosity and hard, dense rock; while long travel times (for example, 95 microseconds or higher) are associated with softer, lower density, higher porosity rock. A common technique used for determining if sand control is required in a given geologic area is to correlate incidences of sand production with sonic log readings. This establishes a quick and basic approach to the need for sand control. However, the technique can be unreliable and is not strictly applicable in geologic areas other than the one in which it was developed.

Confining pressure Oil reservoir

Hand pump

Ring nut End plug Piston Frac sand Unconsolidated sample Consolidated sample

Formation Properties Log

Perforation

Certain well logs, in addition to the sonic log, are indicators of porosity and formation hardness. For a particular formation, a low-density reading from a density log is indicative of a high porosity. Also, neutron logs are primarily an indicator of porosity. Additionally, several wireline-logging companies offer a formation properties log.6 This log performs a calculation using the results of the sonic, density, and neutron logs to determine the likelihood of whether a formation will or will not produce formation material at certain levels of pressure drawdown. The calculation identifies which intervals are stronger and which are weaker and more prone to produce formation material. While the formation properties log has been used by some companies for over 25 years, the consensus is that it is usually conservative in its predictions on the need for sand control.

Drain pan Fluid reservoir

Pump

Pressure gauge

Fig. 1.2. Rock failure test equipment with pressure drawdown

3,500 3,000 Compressive strength, psi

Slope = 0.6 2,500 2,000 1,500 1,000 500 0 0

2,000 4,000 Pressure drop at failure, psi

6,000

Early results Fig. 1.4. Correlation from sand production initiation testing

units of hardness are dimensionless and cannot be related to drawdown as easily as compressive strength. Sonic Log

Completion of test Fig. 1.3. Cavity formation in rock during drawdown failure testing 4

The sonic log can be used as a way to determine the sand production potential of wells. The sonic log records the time required for sound waves to travel through the formation in microseconds. The porosity is related to the sonic

Porosity The porosity of a formation can be used as a guideline for the need for sand control. If the formation porosity is higher than 30%, the probability of a requirement for sand control is higher. Conversely, if the porosity is less than 20%, the need for sand control will probably be less. The porosity range between 20% to 30% is where uncertainty usually exists. Intuitively, porosity is related to the degree of cementation present in a formation; thus, the basis for this technique is understandable. Porosity information can be derived from well logs and/or laboratory core analysis.

Chapter One Controlling Sand-Related Production Problems

Drawdown

Multiphase Flow

The pressure drawdown associated with production may be an indicator of potential formation sand production. No sand production may occur with low-pressure drawdown around the well, whereas excessive drawdown can cause formation material to be produced at unacceptable levels. The amount of pressure drawdown is normally associated with the formation permeability and the viscosity of the produced fluids. Low-viscosity fluids, such as gas, experience small drawdown pressures as opposed to the drawdown that would be associated with a 1,000 cp fluid produced from the same interval. Hence, higher sand production is usually associated with viscous fluids.

The initiation of multiphase fluid flow, primarily water and oil, can also cause sand production. Many cases can be cited where wells produced sand free until water production began, but produced unacceptable amounts of formation material subsequent to the onset of produced water. The reasons for the increased sand production are caused by two primary phenomena: the movement of water-wet fines and relative permeability effects. Most formation fines are water wet and, as a consequence, are immobile when a hydrocarbon phase is the sole produced fluid because hydrocarbons occupy the majority of the pore space. However, when the water saturation is increased to the point that it also becomes mobile, the formation fines begin the move with the wetting phase (water) which creates localized plugging in the pore throats of the porous media. Additionally, when two-phase flow occurs, increased pressure drawdown is experienced as a consequence of relative permeability and increases the pressure drop around the well by as much as a factor of four to five. The result of fines migration, plugging, and reduced relative permeability around the well increases the drawdown to the point that it may exceed the strength of the formation. The consequences may be excessive sand production.

Finite Element Analysis Probably the most sophisticated approach to understanding the reservoir and predicting sand production is the use of geomechanical numerical models developed to analyze fluid flow through the reservoir in relation to the formation strength. The effects of formation stress associated with fluid flow in the immediate region around the wellbore are simultaneously computed with finite element analysis. While this approach is by far the most rigorous, it requires an accurate knowledge of the formation’s strength both in the elastic and plastic regions where the formation begins to fail. Both of these input data are difficult to determine with a high degree of accuracy under actual downhole conditions and that is the major difficulty with this approach. The finite element analysis method is good from the viewpoint of comparing one interval with another. However, the absolute values calculated may not represent actual formation behavior. Time Dependence Whether time has an effect on the production of formation sand is sometimes considered to be an issue. However, there is no data that suggests that time alone is a factor. There have been undocumented claims that produced fluids could possibly dissolve the formation’s natural cementing materials, but no data is available to substantiate these claims.

Productivity, Formation Damage Damage and Flow Efficiency The issue of productivity is especially important in wells requiring sand control. Gravel-packed wells are particularly sensitive to problems of extremely poor productivity if improper completion techniques are used. On the other hand, the implementation of recognized best practices can result in very acceptable productivity from gravel-packed and nongravel-packed wells. Radial Flow The flow of fluids toward a well is governed by the principles of fluid flow through porous media. Darcy’s Law states that the flow of fluids through porous material is controlled by the pressure gradient from the virgin formation to the wellbore, the viscosity of the

Reservoir thickness

Fig. 1.5. Radial flow geometry

flowing fluid and the area available for flow in the formation. The constant of proportionality between pressure drop and flow rate is called permeability. The permeability of a formation is a measure of the available flow area within a given cross-sectional area of porous material. In a linear flow situation, the flow area is constant, and therefore the pressure drop required to induce a given flow rate is constant. However, fluids flowing toward a well do not represent a linear flow situation and are usually modeled more accurately as radial flow. Under radial flow conditions, the area available for flow continuously decreases as the fluid gets nearer to the wellbore, as illustrated in Figure 1.5. As the flowing fluid approaches the wellbore, the decreasing area available for flow causes an increasing velocity of flow, with a corresponding increase in pressure drop. The equation below is Darcy’s Law for radial flow expressed in oil field units. This equation can be used to examine the pressure changes surrounding a flowing well. pi = pe −

141.2 qBoµ  re  ln  kh  ri 

Where: pi = pressure at point of interest (psi) pe = pressure at drainage radius of well (psi) q = production rate (STB/d) Bo = formation volume factor of produced oil (reservoir bbl/STB) µ = viscosity of produced fluids (cp) k = formation permeability (md) h = thickness of the reservoir (ft) re = drainage radius of well (ft) ri = radial distance from wellbore to the point of interest (ft) 5

Modern Sandface Completion Practices

2,700 2,600 Formation permeability - 200 md Production rate = 5,000 STB/d Oil viscosity - 1.02

Pressure, psi

2,500 2,400 2,300 2,200 2,100 2,000 0

200

400 600 Radial distance, ft

800

1,000

3,000 Formation permeability - 200 md Production rate = 5,000 STB/d Oil viscosity - 1.02

2,900 2,800

Near Wellbore Flow Restrictions

Pressure, psi

2,700 Reservoir pressure = 2,700 psi

2,600 2,500 2,400 2,300 2,200 2,100 2,000 0

200

400 600 Radial distance, ft

800

1,000

Fig.1.6. Calculated pressure distribution around a 200-md oil well

3,000

Pressure, psi

2,500

Damage zone thickness No damage 6 inches 1 foot 2 feet 5 feet

2,000 1,500 1,000

Formation permeability - 1,000 md Production rate = 10,000 STB/d Damaged zone permeability - 100md

500 0 0

1

2

3

4 5 6 7 Radial distance, ft

8

9

∆p skin =

3,000

Pressure, psi

2,500 Damage zone Permeability 100 md 50 md 25 md

1,500 1,000

Formation permeability - 1,000 md Production rate = 10,000 STB/d Damaged zone thickness - 2 ft

500 0 0

1

2

3

4 5 6 7 Radial distance, ft

8

9

10

Fig. 1.8. Effect of damage severity on magnitude of pressure drop increase

The results of using this formula are illustrated in the graphs of Figure 1.6 for an oil well with a 200 md formation permeability that is flowing at 5,000 STB/d. The graph on the bottom is a detail plot of the top graph. It shows that 6

Because most of the pressure drop takes place in the area very near the wellbore, this same area is where any additional restrictions to flow have the most detrimental effect. Two factors that affect the increase of this pressure drop are the amount of the permeability impairment, which is measured as a permeability reduction, and the radial thickness of the impaired or damaged area. Using the equation7 below to calculate the additional pressure drop associated with a near wellbore flow restriction, Figure 1.7 illustrates the additional pressure drop that is created by reducing the permeability surrounding a wellbore from 1,000 md to 100 md. The different curves on this figure represent increasing radial distances of permeability damage ranging from 6 in. to 5 ft.

10

Fig. 1.7. Additional pressure with increasing depth of damage

2,000

the total pressure drop is equal to the reservoir pressure (approximately 2,700 psi), minus the pressure at the wellbore (approximately 2,070 psi), giving a total pressure loss across the area near the wellbore of 630 psi. Notice that almost half of the 630 psi of total pressure drop occurs within the 10 ft nearest the wellbore, and that more than 100 psi of pressure drop occurs within a 1-ft radius of the wellbore.

 r  141.2 qBoµ  k − 1 ln s   kh  ks   rw 

Where: ∆pskin = pressure drop through damaged zone (psi) q = production rate (STB/d) Bo = formation volume factor of produced oil (reservoir bbl/STB) µ = viscosity of produced fluids (cp) k = formation permeability (md) ks = damaged zone permeability (md) h = thickness of the reservoir (ft) rs = radius of damage (ft) rw = radius of wellbore (ft) This plot indicates that, as expected, the total system pressure drop increases with increasing depth of damage. However, the plot also illustrates that the

majority of the increase in pressure drop is within a foot or so of the wellbore. The other factor that determines the magnitude of damage is the permeability of the damaged zone. Figure 1.8 indicates the pressure drop increase associated with a damaged zone which has a radial depth of 2 ft. The damaged zone consists of material with a permeability of 100 md, 50 md and 25 md, which is equivalent to 10%, 5% and 2.5% of the permeability of the virgin formation. Comparison of Figure 1.7 and Figure 1.8 indicates that severe permeability impairment near the wellbore is much more detrimental than is moderate damage deep into the formation. The importance of severe permeability impairment can be shown by a calculation of the damaged productivity of a well expressed as a ratio of the undamaged productivity. This ratio is calculated as a function of the radial thickness of the damaged zone and the degree of permeability reduction by the following equation:8 Js = Jo

r  ks log e  ko  rw  r  k r  log s  + s log e   rw  ko  rs 

Where: Js = productivity index of damaged well (BOPD/psi drawdown) Jo = productivity index of undamaged well (BOPD/psi drawdown) ks = permeability of damaged zone (md) ko = permeability of undamaged zone (md) re = drainage radius of well (ft) rw = wellbore radius (ft) rs = damaged zone radius (md) Figure 1.9 shows the results when this equation is plotted against the damaged zone radius for different degrees of damage. This figure further supports the critical influence of permeability reductions very close to the wellbore. The permeability impairment surrounding a well is called skin factor, which is a dimensionless representation of the additional pressure drop across the near wellbore formation associated with the flowing of fluids through a near wellbore damaged zone.

Chapter One Controlling Sand-Related Production Problems

s=

0.00708 kh ∆Pskin qµBo

Where: s

=productivity skin factor k =formation permeability (md) h = interval thickness (ft) ∆pskin= pressure drop through damaged zone (psi) q =production rate (STB/d) µ =viscosity of produced fluids (cp) Bo =formation volume factor of produced oil (reservoir bbl/STB) If the calculated skin number is positive, there is an increased pressure drop around the well and the well is considered to be damaged. On the other hand, if a negative skin is calculated, there is a zone of increased permeability present, typical of a stimulated well. Skin factors can range from about -6 to any positive number. Skin factors from +25 to +50 in high permeability formations are not uncommon. The effect of formation damage can be approximated through the concept of flow efficiency. This is a measure of the relative percentage of the theoretical flow rate that can actually flow through a formation. The following equation presents an approximate method for calculating flow efficiency.   re    ln    rw    qs   8   FE = 100  = 100 ≈ 100    s + 8  qo   re    s + ln    rw   

Where: FE = flow efficiency (%) qs = flow rate from damaged well (STB/d) qo = hypothetical flow rate from undamaged well (STB/d) re = drainage radius of well (ft) rw = wellbore radius (ft) s = productivity skin factor The approximation of 8 for the term ln(re /rw) results from the fact that the natural log of a large number divided by a small number is approximately 8.

Based on this equation, a well with a skin of +20 will have a flow efficiency of only about 28%. Skin factor is only a relative measure of an additional pressure drop in the flowing system. Skin factor does not distinguish between a near-wellbore, severely damaged zone and a deeper, moderately damaged zone. Formation Damage Mechanisms Skin is strictly a measure of an excess pressure drop in the producing formation as fluids flow into a well. This excess pressure drop can occur from any one or several of a wide variety of causes. Various damage mechanisms can be classified into the following general categories: • drilling mud, cement and completion fluid filtrate invasion • solids invasion • perforating damage • fines migration • formation compaction • swelling clays • asphaltene/paraffin deposition • scale precipitation • emulsions • reservoir compaction • relative permeability effects • effects of stimulation treatments The critical factor from a well completion standpoint is to limit, where possible, the creation of damage (especially severe plugging in the near wellbore area). This means avoiding plugging of the perforations in a cased-hole completion and avoiding plugging of the formation face in an open-hole completion. Methods to avoid plugging will be described later. Beyond taking steps to eliminate severe permeability reduction in the near wellbore area, the next step in a completion is to obtain the best possible communication of the wellbore with the virgin formation.

Sand Management Techniques Sand Management is an operating concept where traditional sand control means are not normally applied and production is managed through monitoring and control of well pressures, fluid rates and sand influx. In the recent past, Sand Management in conventional oil and gas production has been implemented on a large number of wells in

1.0 Productivity after damage/undamaged productivity

The following equation9 illustrates how the dimensionless skin factor relates to this increased pressure drop.

Productivity after damage/ undamagedproductivity

0.9

0.5 re = 660 ft

Damaged zone ks

0.8

ko

rw = 0.33 ft

0.7

0.2

0.6 0.5 0.1 0.4 0.02

0.05

0.3 0

10 2 4 6 8 Depth of damaged zone, (rS-rW) inches

12

Fig. 1.9. Productivity loss caused by formation damage

the North Sea and elsewhere. In almost all cases it has proven to be workable, and has led to the generation of highly favorable well skins because of selfcleanup associated with the episodic sand bursts that take place. These low skins have, in turn, led to higher productivity indexes (PIs), and each of the wells where sand management has been successful has displayed increased oil or gas production rates. Furthermore, expensive sand control devices are avoided and the feasibility of possible future well interventions is guaranteed. However, there is also risk that sand production might exceed expectations at a less than favorable production rate. In such cases, a perhaps costly workover would be necessary to install some type of sand control method (Table 1.2). Historical Steps in Preventing Sand Production Risk Classical sand control techniques (such as gravel packing, wire-wrapped screens, frac pack, chemical consolidation, expandable screens, etc.) are based on a sand exclusion philosophy: absolutely no sand in the production facilities can be tolerated. Alternatively, in the absence of means of totally excluding sand influx, the traditional approach is to reduce the production rate to minimize the amount of entering sand. The decision to exclude or control sand is based on a sand prediction analysis. This has led to development of various techniques to predict the onset of sand production. As a result, sand influx is usually viewed as a factor that limits the production rate (and thereby

7

Modern Sandface Completion Practices

Sand Control Method

Major Short-Comings

Chemical consolidation

Screens, slotted liners, special filters (including expandable screens)

Inside-casing gravel packing

Open-hole gravel packing

Propped fracturing, including frac packing, gas propellant fracturing, and use of resin coated sand

Selective perforating

Oriented perforating

Production rate control

• Some permeability reduction • Placement and reliability issues • Short intervals only • Lack of zonal isolation • High placement & workover costs • Longevity of devices • Plugging and screen collapse • Screen erosion • Potential damage during installation • PIs reduction • Placement and workovers difficult • High cost of installation • Positive skin development • PIs reduction • Complexity of operation • Necessity for extensive under-reaming in most cases • Costs of installation • Permeability recovery • Risks of tip-screenout during installation • Directional control and tortuosity issues (in inclined wells) • Fracture containment control • Proppant flow-back on production • Problematic in relatively homogneous formations • Need for formation strength data • Reduces inflow area • Necessity for full stress mapping • Theoretical analysis required • Perforation tool orientation needed • Limited field validation available • Erosion of facilities • Sand monitoring required • Separation and disposal required • Potential for lost production

Table 1.1. Critique of different sand prevention methods Environment

Bad

??? Good

Gas or condensate  HP/HT  Sub-surface wellhead !!!! Depletion drive reservoir !!! Horizontal well !! Injection wells !! Separator functioning ! Low PIs Asphalt/scale precipitation Heavy oil

$ $$ $$$$

=hazardous !=of concern $=profitable

Table 1.2. Sanding impact in various well environments

8

the cash-flow) through the induced production limitations set by installed sand control methods, production losses due to failures and workovers, and induced production restrictions arising from low maximum sand-free rate limits. However, sand influx is related to the mechanical failure and dilation of the formation rock and the removal of failed or damaged material. Clearly, the permeability in the wellbore vicinity is increased with respect to the intact formation. This has been verified in a case where well test data show that negative skin values often develop as a result of a cleaning of the near-wellbore formation of sand.10

Sand Management Philosophy Table 1.1 is a critique of different methods used for dealing with sand production: generally, sand control represents high-cost, low-risk solutions. Sand Management leads to low-cost solutions, but it also involves active risk management.11 Risk management requires reliable analysis of the Sand Life Cycle, starting with predicting formation conditions conducive to sanding, and ending with ultimate disposal of the produced material at the surface. These techniques are based on: • An extensive field data acquisition campaign • Theoretical modeling of the involved physical processes • Active monitoring and follow-up on production data • Well testing to optimize production rates Also, the techniques will help the production engineer in: • Completion design optimization • Risk assessment throughout the well’s production life. Phases in the Sand Life Cycle include sand detachment, sand transport, sand erosion and surface sand deposition. Quantification of Sand Production Risk Traditionally, sanding risk is perceived as the risk of reaching the operative conditions at which sand begins to enter into the wellbore. It is implicitly assumed that sand will eventually cause unbearable problems and that no effective action can be taken to cope with it except to avoid the sand inflow. Sand Management extends this concept by assuming that sand production is not always unacceptable, economically or for safety. Table 1.2 lists different cases and suggests a classification with respect to the risks, and also to the benefits.12 Well Monitoring for Reliable Sand Management Sand monitoring. Sand monitoring is a critical aspect of Sand Management. Current sand monitoring methods may be classified as: • Volumetric methods: • Sand traps may be installed, usually

Chapter One Controlling Sand-Related Production Problems

at tees or bends, to capture sand. Sand is measured by disassembling the sand trap, thus it is not a real-time method. Such techniques have not proven effective, because the majority of the produced sand is normally not captured (North Sea experience indicates a recovery of 1% to 10%). • Fluid sampling after the primary separator represents an alternative, including centrifugation for water and sand cuts. This is the so-called Bottom Sediment and Water measurement (BS&W) done during appraisal well testing or during normal production. However, much sand usually remains in the primary separator and the method sensitivity can not be guaranteed. • Another idea consists in dismounting the sand separator, jetting it clean from all sand, and quantifying all produced solids. This has been used quite extensively in the Adriatic Sea on gas wells.13 However, it is limited in terms of accuracy (see point above) and practicality (i.e., the time and manpower required to dismount, jet, and remount the separator). • A new method used on some North Sea platforms applies an in-line sand cyclone. Sand is effectively separated from produced fluids and stored in a tank. Load cells or other devices on the tank allow a measure of sand accumulation in real time. • Acoustic transducers installed in the flow system include: • An impact probe installed in the flow line to detect sand grain impacts. • An acoustic collar that captures information about the impact of the sand grains against the wall of the pipe or the choke throat. • Erosion monitoring on steel goods or special tab erosion: • Ultrasonic gauges are clamped to the external surface of the pipe. They send out an ultrasonic pulse to measure thickness. The method is sensitive to noise from other sources. • Weight-loss coupons made of the same or similar material as the pipe being monitored are installed and periodically retrieved and weighed. They provide only discrete monitoring and are unsuitable for subsea installations. • Electrical resistance probes which measure accumulated erosion as an

increase of electrical resistance (Ohm’s law) on a known cross section. Calibration and temperature changes are of concern. • Electrochemical probes that determine erosion rate through measurement of the linear polarization resistance between electrodes through a conductive electrolyte flowing inside the pipe may be used. The method is suitable only for conductive liquids such as water or oil systems with high water cuts. Sand detector data interpretation. Sand detector technology has improved greatly in the recent past, in particular, in improved signal-filtering techniques, rapid acquisition and better analysis. However, the lack of downhole sand monitoring systems introduces errors in terms of the time lag between downhole and surface (or subsea) sand production. Well Management Optimization with Sanding Risks With a reliable Sand Management analysis it is possible to define safe limits within which production rates should be kept. This information allows designing and managing the well so as to extend these limits and even to increase well productivity. Some examples are given below. Rate exclusion. Reduction in production rate will reduce drag forces and drawdown to provide reduced risk of sand production. The procedure is to slowly increase rate until sand production begins to increase, and then, sequentially reduce flow rate until the sand production declines to an acceptable level. The object is to establish a maximum flow rate in conjunction with the stable-arch concept, which was described previously in this Chapter. Selective perforating practices. In heterogeneous formations, strength variations among different lithologies may be substantial; avoiding perforating the weakest intervals may lead to higher critical drawdown values. Once formation characteristics are known, perforating strategies can be evaluated. If possible, only high strength intervals can be perforated. For high rate wells this will require a high shot density to prevent

additional pressure drop and associated sand production. However, high shot density can lead to perforation interaction, which also promotes sand production. Selecting the appropriate compromise is the key to success. Perforating for sand prevention. It has been suggested that the best technique to limit sand production is to minimize entry hole diameter, and space the perforations far enough apart to prevent failed-zone interactions. With standard phasing this leads to low shot density, which tends to promote failure through higher flow velocities. Phasing can be optimized to provide the least amount of interaction with greatest shot density. If stress state is known, orienting shots within about 25° of the optimum direction can provide improved stability. Also, perforating into breakouts should be avoided. Orientated perforating. Laboratory tests in the past have indicated that the mechanical stability of perforation cavities depends on perforation direction relative to the in situ stress field.14 This led to the idea of oriented perforating to minimize the shear stresses acting at the wall of the perforation cavities. The method uses 180° phasing, which may affect the perforation density. This is, however, seldom a problem, as weak sandstone formations are normally quite permeable and do not require large drawdown. Some uncertainty must be accounted for in gun orientation, but computations demonstrate that the sensitivity to this is not very high. Figure 1.10 shows the large gain, in terms of increased critical drawdown, of proper perforation orientation and the sensitivity of gun orientation. Even at great uncertainties on the order of 20°, benefits are still pronounced. Another argument for 180° phased, orientated perforating is the reduced probability of the perforations being oriented in the worst direction, which by itself reduces the sand production risk.11

Justification for Sand Control Operational problems related to sand production vary from expensive sandhandling problems to complete loss of a productive zone or the possibility of 9

Modern Sandface Completion Practices

Norwegian sector HPHT well vertical well case 450 400

No depletion 200 bar depletion 400 bar depletion 600 bar depletion

Critical draw down, bar

350 300 250 200 150

100 50 bar drawdown line

50 0 0

10

20

30

40

50

60

70

80

90

Perforation direction, degrees relative to maximum horizontal stress direction Fig. 1.10. Effect of oriented perforations on critical drawdown

loss of well control due to an eroded surface production control equipment. Sand Disposal Sand disposal is a common problem in fields producing from unconsolidated sands. Even wells with successful sand control measures will produce small quantities of sand. While an acceptable rate of sand production may be as high as 0.1% by volume, this is a considerable amount of sand. For example, at 0.1%, one well producing at the rate of 750 BOPD will produce 0.75 b/d of sand. When there are several wells producing into a common platform, the volume of sand can be quite large. In offshore locations, the sand must first be separated from the produced fluids and all oil removed prior to disposal. One processing system that satisfies antipollution laws utilizes cyclone separators and oil cleaning chemicals. In this system, the sand is completely cleaned and discharged into the Gulf of Mexico. In other systems, sand is transported to shore where it is then disposed.

10

Sand Erosion Sand production can cause erosion in both surface and downhole equipment. Downhole erosion is most likely to occur in blast joints or tubing opposite perforations or in screens or slotted liners that were not packed in the gravel pack installation procedure. Erosion is more severe where the sand is produced in gas or where the produced fluids are in turbulent flow. High-pressure gas, containing sand particles, expanding through a surface choke is the most hazardous situation. While it is impossible to completely stop sand production, high-pressure gas production cannot tolerate even smaller quantities of sand because of potential loss of well control.

Types of Sand Control Sand control methods have become more varied in recent years. Since the early application of gravel packing, there have been several new processes introduced with varying results. Many of these innovations were introduced in the U.S. Gulf Coast area because, historically, gravel packing provided poor results in formation sands there.

Results from these new techniques varied widely, so the industry moved rapidly from one process to another, but most often returned to gravel packing. In the 1980s and 1990s, researchers and engineers found some of the keys to improved productivity in gravel pack completions. Therefore, gravel packing has maintained industry dominance and many alternative methods have been abandoned or their use diminished greatly. Factors normally considered in selection and design in a particular field or well are listed below:15 • Initial sand control cost • Expected reliability • Effect on productivity • Completion repair cost • Formation sand quality • Presence of multiple, thin productive sections • Exclusion of inter-bedded water or gas • Presence of undesirable shale streaks • Level of reservoir pressure depletion • History of sand production Sand-control methods can be grouped as follows: • Production rate control • Selective and oriented perforating • Mechanical stressing of the formation • Sand packing to restore formation stresses • In situ sand consolidation • Resin coated gravel packing without a screen • Mechanical control (prepacked, stand-alone, expandable screen, etc.) • Gravel packing, open hole and inside casing • Propped fracturing, including frac packing, propellant gas fracturing, and use of resin-coated sand Details about all of the above are discussed in later sections.

Drilling, Cementing and Completion Considerations Successful sand control applications require that each step of the well completion be designed and executed properly. Such steps include drilling, cementing, perforating and use of drillin fluids or completion and workover fluids. Of course, the sand control completion stage must be suitably designed and installed as well. As Bruist16 correctly emphasized back in 1974, there

Chapter One Controlling Sand-Related Production Problems

are distinct and important mutual dependencies between various completion operations when sand control is installed. Failure at any step may adversely affect well reliability and/or productivity. Higher-permeability sandstone formations, which more likely would produce sand, are often subject to severe near wellbore damage caused by drilling fluids, cement filtrate, and completion fluids. Some of this damage is not easy to remove with acids and solvents, and diversion of treating fluids throughout the damaged interval is difficult.

Cement Mud Casing

Drilling Related Issues Formation damage that can occur during the drilling of the productive interval should be avoided. Such impairment can be difficult or impossible to remove and may cause serious difficulties, such as non-uniform placement of gravel or consolidation chemicals, or unnecessarily high, localized produced fluid velocities. In the latter case, with a portion of the pay zone blocked or restricted, the increased flow rate per unit area of formation open for production may be just high enough to cause sand production. In addition, high velocities can also increase downhole equipment erosion. During drilling, productivity can be damaged by washouts through the pay zone and reduction of permeability by low salinity mud filtrate, which disperses or swells water-sensitive clays. Washouts can reduce cementing effectiveness, commonly causing communication between oil, gas and water zones that require remedial repair work to prevent unnecessary water production or even premature abandonment. Also, the extra-long perforation tunnel through cement in a washed-out section can substantially reduce productivity from a gravel pack due to high-pressure drop across gravel-filled perforations. Effective Cementing Proper cement is imperative to obtain a good well completion, but is one of the most difficult completion phases. Cementing problems still exist that were first discussed in 1941 by Jones and Berdine.17 The goal is and has always been to maximize mud displacement efficiency. Conditions are particu-

Top view

Cross section Fig. 1.11. Cement channeling caused by off-centered pipe

larly severe in deviated and horizontal holes because of the casing being offcenter. This phenomenon is illustrated in Figure 1.11. For such cases, accepted practices are: • Drill gage hole • Centralize pipe • Reciprocate or rotate pipe during placement of cement • Place cement slurry in turbulent flow during displacement if possible; otherwise, maximize the pump rate • Place an adequate, compatible spacer between the mud and cement slurry • Control properties of the mud and cement slurry In practice, some of the above requirements may not be attainable because high pump rates may cause lost circulation and reciprocation or rotation of the pipe may not be possible in highly deviated holes. In addition, spacer fluids should be properly designed to avoid well control problems and hole instability, which can stick the pipe and prevent its further movement. Other Completion Concerns Perforating debris and mud pockets at the cement formation interface can prevent uniform sand placement when

gravel packing. This impairment can be locked in place by the sand control procedure. Moreover, having clean perforations is a must. Completion fluids can cause impairment due to deep formation invasion by entrained solids, or dispersion of formation water-sensitive clays, as with mud filtrates. Therefore, the completion fluid must be formation compatible and adequately filtered. Damage can also occur if the completion fluid is not properly designed and large quantities of bridging material are lost to the formation. The above points are mentioned to emphasize that proper sand control installations depend on almost all aspects of the drilling, cementing and completion operations. Best possible procedures should be followed during a sand control operation. Otherwise, a short-lived, ineffective installation may result if the well is not properly handled before, and after the application. References 1. Penberthy, W. and Shaughnessy, C., Sand Control, SPE Series on Special Topics, Volume 1, 1992. 2. Roberts, A., Geotechnology: An Introductory Text for Students and Engineers, Pergamon Press, New York, New York, 1977.

11

Modern Sandface Completion Practices

3. Suman, G., Jr., Ellis, R., and Snyder, R., Sand Control Handbook, Second Edition, Gulf Publishing Company, Houston, Texas, 1991. 4. Ibid 5. Penberthy, W. and Shaughnessy, C., Sand Control, SPE Series on Special Topics, Volume 1, 1992. 6. Tixier, M., Loveless, G., Anderson, R., “Estimation of Formation Strength From the Mechanical-Properties Log,” Journal of Petroleum Technology, March 1975, 283-293. 7. Earlougher, R. Jr., Advances in Well Test Analysis, SPE Monograph Series, Volume 5, 1977. 8. Williams, B., Gidley, J. and Schechter, R., Acidizing Fundamentals, SPE Monograph Series, Volume 6, 1979. 9. Lee, W., Well Testing, SPE Textbook Series, Volume 1, 1982. 10. Santarelli, F., Tronvoll, J., Skomedal, E. and Bratli, R., “The Skin Factor as a Rock Mechanics Diagnostic Tool.” SPE 37381, presented at the SPE/ISRM Eurock ‘98 Conference, Balkema, 1998. 11. Tronvoll, J., Dusseault, M., Sanfilippo,F., and Santarelli, F., “The Tools of Sand Management.” SPE 71673, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 2001. 12. Ibid. 13. Sanfilippo F., Brignoli M., Giacca D. and Santarelli F. “Sand Production: From Prediction to Management.” SPE 38185, presented at the European Formation Damage Conf. Proc., The Hague, 1997. 14. Tronvoll, J., Kessler, N., Morita, N., Fjær, E., Santarelli, F., 1993: The Effect of Anisotropic Stress State on the Stability of Perforation Cavities, Int. J. Rock Mech. Min. Sci. & Geomech. Abstr. 30, 10851090. 15. Suman, G., Jr., Ellis, R., and Snyder, R., Sand Control Handbook, Second Edition, Gulf Publishing Company, Houston, Texas, 1991. 16. Bruist, E., “Better Performance of Gulf Coast Wells.” SPE 4777, presented at the SPE Symposium on Formation Damage, New Orleans, Lousiana, 1974. 17. Jones, P., and Berdine, D., “Oilwell Cementing Factors Influencing Bond between Cement and Formation,” API Drilling and Production Practice, 1941.

12

CHAPTER TWO

Open-Hole Sandface Completions Drill-In Fluids • Stand-Alone Screens • Gravel Packing • Open-Hole Frac Packing

aintaining borehole stability during the drilling and completion phase of well construction is an essential requirement for open-hole sandface completions. Concern over the lack of borehole stability is a primary reason why open-hole completions are not used more often in unconsolidated formations. Unstable boreholes make running of tubulars and other downhole tools difficult. Fortunately, state-of-the art drill-in fluids are effective in maintaining borehole stability and preventing formation damage, which makes vertical, deviated and horizontal completions possible in dilatant sand formations known to have presented problems in the past. Open-hole sandface completions are usually avoided in formations with several sand and shale sequences, if the shales are prone to eroding and/or sloughing. During an open-hole gravel pack completion (described later in this chapter), the shale can intermix with the gravel-pack sand resulting in reduced gravel permeability and impaired well performance. Proper drill-in fluid selection can alleviate some of the problems associated with laminated sand and shale formations.

M

Drill-In Fluids A drill-in fluid (DIF) is a special fluid designed exclusively for drilling through the payzone or productive reservoir section of a wellbore. The reasons for using this specially designed DIF are to: • Drill the reservoir zone successfully, often a long, horizontal drain hole • Minimize damage and maximize production of exposed zones • Facilitate the well completion needed, which can be simply a stand-alone screen or a complicated procedure, such as a gravel pack.

A drill-in fluid should resemble a completion fluid brine (a whole series of which are discussed in Chapter Three). It may be brine containing only selected solids of appropriate particle size ranges (salt crystals or calcium carbonate) and polymers. Only additives essential for filtration control and cuttings carrying are present in a drill-in fluid. A DIF can also be an all-oil system. Unlike conventional water-based systems, oilbased systems have an inherent advantage of being used without the risks in strata containing shales. Mixed metal silicate (MMS) systems are another alternative DIF.1 However, the focus of this section will be confined to waterbased DIF systems most commonly used in sandface completions.

Fluid selection. The evaluation and selection of drilling and drill-in fluids for long, open-hole completions have been the subjects of numerous studies. In addition to the standard drilling fluid tests (rheology and fluid loss), formation and completion-damage tests must be included to ensure the desired productivity level is achieved. Because the damaged zone created by conventional drilling fluids will not be bypassed in the open-hole completion, more attention has been directed to developing less damaging DIFs. However, to confirm formation compatibility and identify the best DIF, specialized laboratory testing that simulates the anticipated drilling, completion and producing conditions is required.3

Fluid design. Payzone drill-in fluid design should be based on a complete study of the reservoir rock characteristics at downhole conditions. The rock minerals and the chemical composition of the reservoir fluids should be determined and evaluated for compatibility. To maximize well productivity and ensure proper reservoir protection, the casing should be set prior to drilling the payzone section. Conventional mud is then displaced by a displacement fluid, which is specially designed to minimize damage and yet maintain the necessary drilling fluid properties. This fluid must be tested in a laboratory to verify fluid/rock and fluid/fluid interaction, as well as possible residual damage. Based on the test results, the best treatment to remove such damage is devised. Field problems such as scale precipitation while completing wells with high density brines, damage caused by oil-based mud when followed by brine completion fluid, and fluid loss in the payzone can be eliminated by the timely use of available techniques.2

Formates. In recent years sodium and potassium formates have been used successfully for drill-in fluid applications. One application was a low permeability reservoir where solids-free formates were applied with polymers specifically for fluid loss. Formate brine systems tend to stabilize polymers at high temperatures. The polymers can be readily removed with enzymes.4 Additionally, Cabot Specialty Fluids recently reported that cesium formate (another formate based brine) was used in several field operations where wellbore temperatures reached 401ºF (205ºC) and bottomhole pressures exceeded 16,000 psi. Two popular DIFs are ThixsalUltra (a NaCl solids system from TBCBrinadd) and PerfFlow (a CaCO3 solids from Baker Inteq). Thixsal-Ultra is an ideal fluid system for drilling the payzone in highly deviated and horizontal wells. Use of improved bridging particle distribution in Thixsal-Ultra reduces filtration control polymer requirements while providing more dense, ultra-low permeability filter cakes. 13

Modern Sandface Completion Practices

PerfFlow DIF seals pore openings exposed to the wellbore and remains intact during completion operations. The thin (less than 1 mm) PerfFlow filter cake (Fig. 2.1) is easily removed with low production pressures. Other proven DIFs include: FloPro NT (from M-I) and Baradril N (from Halliburton). ActiSystems has a DIF that is being used to drill horizontal and high-angle wells through damage-prone reservoirs. This fluid combines certain surfactants and polymers to create a system of “micro-bubbles” known as gas aphrons

Fig. 2.1. Micrograph of PerfFlow DIF system filter cake

Meniscus: Source of laplace pressure Gas

Gas

Gas

Gas Gas

Gas

Gas

Gas

Gas Gas Gas

Gas Gas

Continuous film

Soap film

Plateau border

Fig. 2.2. Structure of gas aphron 5

Filtration volume, ml

14 12 10 8 6 4

Test conditions: Media = 1,500 md sand Temperature = 150°F Pressure = 250 psi

2 0 0

1

2

3

4

5

6

Filtration time, min

Fig. 2.3. Fluid loss of a 10.5 ppg NaCl suspension 14

7

8

encapsulated in a uniquely viscosified system. (Aphrons are micro-bubbles smaller than 200 micron. Their stability increases as their size decreases and they decrease the density of the base fluid.) These aphrons (Fig. 2.2) are noncoalescing and can be recirculated so that density reduction is accomplished without expensive air or gas injection. A unique feature of the micro-bubble network is stopping or slowing the entry of fluids into the formation by creating downhole bridging.6 Fluid Loss Fluid invasion into productive zones is recognized as detrimental to well productivity. Filtrate and solids invasion can cause irreversible formation damage and permeability reduction. Nondamaging, water-soluble or acid-soluble solids are added to drill-in fluids to promote pore plugging and minimize fluid penetration. Development of less invasive, non-damaging fluid formulations requires knowledge of filtration mechanisms of solids-containing polymeric solutions in porous media. The application of a specialty DIF for an open-hole completion, particularly in horizontal wells, offers distinct advantages for maximizing production. DIF systems are designed to prevent liquid and solids invasion into a permeable formation by bridging and sealing with a readily removable ultra-low permeability filter cake. These characteristics are achieved by selecting a suitable size range and particle distribution of soluble solids for bridging the pore openings between formation sand grains. Four types of soluble solids are available: • Water soluble such as sized NaCl in saturated brine • Acid soluble such as CaCO3 • Oil soluble specialty products • Breakable polymers such as HEC and Xanvis. An optimum concentration of these solids must be determined and properly balanced with sufficient sub-colloidalsized components. The result of this optimized composition is a stable filter cake with low filtrate under specific conditions of temperature and pressure, Figure 2.3.7 The low permeability cake is deposited quickly and prevents excessive filtrate from entering the formation. Also, this

film of polymer and NaCl allows the column of fluid to transmit the necessary hydrostatic pressure to keep the wellbore open, stable and in-gauge. In addition, the correct design and maintenance of a DIF is critical where open-hole completions are planned. The particle-size distribution of solids in the open hole must be carefully chosen, not only to bridge across the exposed formation, but also to permit flow back through the openings in the completion slotted liner or screen. Initial fluid design and testing must be done in the laboratory. Once drilling has started in the reservoir, any flow back testing on field samples usually requires urgent shipping to a laboratory, resulting in costly delays. Figure 2.4, the Production Screen Tester (PST) (from M-I) can be used to perform testing of fluid flow back at the rig site. It can be used effectively with all screen types, from simple singlewrap designs to the more exotic premium screens. (These sand exclusion devices will be discussed in the next section of this Chapter.) The PST unit is equipped with a portable CO2 cartridge holder and regulator to simulate drawdown pressure. In the laboratory, it can be attached to a compressed-air source. Removing fluid loss materials from the filter cake involves first getting the breaking fluid to interact with the bridging material and flushing whatever residual material is present. Washing a formation that has been plugged is difficult. The more powerful acids will eat their way into the formation, but will also disturb the formation matrix and can cause problems greater than those caused by the bridging agents. The best alternative is a material where the breaker (enzyme, oxidizer or acid) travels with the polymer and waits for the proper conditions to go to work. Completion Considerations Maintaining formation compatibility and switching out the drilling fluid into a completion system requires knowledge of possible hole problems and the use of a staged wellbore cleaning procedure. Maximum reduction of solids in the casing and open hole, as well as removal of filter cake, will minimize particle intrusion into the completion assembly during placement or when the

Chapter Two Open-Hole Sandface Completions

well is produced. Five major categories are addressed as completion considerations: • Formation compatibility • Drilling fluid transition to completion system • Completion assembly design • Displacement and clean-up procedure • Post-completion application. Formation compatibility. In situations where troublesome shale sections are anticipated, additions of potassium chloride or various polyglycols can be incorporated into the base fluid system. Shale Stability Index (SSI) values define the surface conditions of shale specimens before and after exposure to test fluids. The lower the SSI value, the higher the water uptake into the shale.8 Relatively high values are displayed in Table 2.1 for the standard polymer/salt system. However, improved values may be obtained through proper treatment. Drilling fluid transition to completion system. After insuring formation compatibility of all fluids that contact the open hole, the next stage in the completion is conducted with the drill pipe in the wellbore after reaching the total depth of the well. The drilling fluid is displaced from the open hole and 500 ft (152.4 m) into the last casing string with a new mixture of properly sheared polymer and suspended NaCl or CaCO3. It should have a maximum particle size that is determined by one of the “rules of thumb” (see the Fluid Filtration section in Chapter Three). Assuming the well is a stand-alone completion, correct particle sizing will help prevent plugging of the slotted liner or screen. (Stand-alone completions are covered in the next section of this Chapter.) When the relationship between pore size or slot width/screen spacing and particle size of the solids in a fluid is: Dp >

will prevent large “fish eyes” (clumps of partially hydrated polymer), and perhaps, “angel hair” (strands of partially hydrated polymer) that could infiltrate and bridge inside the sand exclusion device. Figure 2.5 shows a hydraulic shearing device that can effectively and efficiently mix dry materials with liquids, as well as blend, emulsify and stabilize liquid/liquid phases. A clean displacement mixture is important for several reasons: • It provides a fluid, which does not contain insoluble drill solids. • The soluble solids suspended in the open-hole annulus will ensure adequate secondary bridging particles for fluid loss control if the filter cake is damaged while placing the completion assembly. • If an adequate displacement of the open-hole annulus is not achieved after placing the completion assembly, the smaller micron size of the suspended solids can more readily pass through the pores of a resin coated sand in a prepacked screen.

Fig. 2.4. Production screen tester

Drilling Fluid

SSI

Oil mud Xanthan gum/hydropropylated starch derivative fluid treated with polyglycols KCI/polysaccharide mud Xanthan gum/hydroxypropylated starch derivative fluid Lime/starch mud Lignosulfonate mud

100 95 90 85 74 64

Table 2.1. Shale stability index (SSI) of various fluids

d 3

Then, bridging occurs. Where: Dp = diameter of particle d = average pore diameter or slot width/screen spacing Since the completion pill mixture will not have been sheared through the nozzles of a drill bit, the use of a unit providing mechanical or hydraulic shear

Fig. 2.5. Hydraulic shearing device (Jet Shear) with a chemical hopper and eductor (venturi) 15

Modern Sandface Completion Practices

Opening Size (in.)

Opening Size (micron)

Particle Size Required to Bridge (micron)

0.020 0.012 0.008

508.0 304.8 203.2

169.3 101.6 67.7

Table 2.2. Opening sizes and bridging particle requirements for slotted liners and screens

After displacing the open hole with the polymer/superfine soluble-solids mixture and prior to running the completion assembly, the polymer, sizedsolids drilling fluid in the casing should be replaced with filtered completion brine. This provides a solids-free environment through which the completion assembly may pass. Using clean brine in the upper wellbore will allow the liquid to penetrate and fill the slotted liner or screen. This displacement to filtered brine reduces the risk of solids infiltrating into the sand exclusion device during its placement. Completion assembly design. As previously discussed, wells that produce formation sand can create problems with formation erosion and can damage surface production equipment. Therefore, sand exclusion techniques are incorporated to limit or stop movement of sand while continuing to allow high production rates. The most common alternatives for sand exclusion include: • Slotted liners • Conventional wire-wrapped screens • Prepacked, premium and expandable screens • Gravel packing. Regardless of the slotted liner or type of screen run for sand exclusion, restrictions to flow could develop wherever particles begin to collect and bridge. Therefore, before producing the well, an appropriate displacement and disassociation of the filter cake into its individual components will limit the number of particles which could become plugged in the slotted liner or screen. Successful fluid displacement through the completion assembly can only be accomplished if the openings through which the solids must pass are sized large enough or the particles in the fluid are small enough to prevent bridging. Typical openings for screens and the particle size required to initiate a primary bridge are shown in Table 2.2. 16

Solids in the fluid system must be smaller than 1/3 of the opening size of the selected exclusion device in order not to bridge. Common features of assemblies that address removal of sized solids from the open hole during completion incorporate various options for fluid displacement and subsequent clean-up (Fig. 2.6). Common techniques used to remove solids include: Washing – Offers a method for washing out low side cuttings, sand, bridges and excess fill by circulating fluid through the tubing and annulus during screen placement. It is also effective for spotting or removing pill material prior to setting the packer. Circulating bridging solids – Provides the capacity of removing solidsladen pill material in the open-hole annulus to above packer depth, and out of the wellbore by circulating through tubing to the outside of the screen. The circulating direction is reversed with different options, but each method works equally well if the openings through which fluid must pass are large enough to prevent particle bridging. The fluid path into the annulus can be through: (1) a shoe assembly located near total depth and returned through a closing sleeve port, or (2) out a crossover assembly port near the casing shoe with returns through a slotted subassembly into the base of the washpipe. Isolating open hole – Utilizes seal assemblies or a reverse circulating position to control losses and to provide soak time for clean-up solutions. When using a crossover assembly, the completing brine in the casing can easily be changed without disturbing the cleanup solution in the open hole. Screen cleaning – Provides a technique to remove particulate from the slotted liner or screen with brine jetted from a cup wash tool, while taking returns through a closing sleeve. Diverting fluid flow – Prevent fluid from re-entering the screen during jet-

ting operations with the addition of baffle cups on the washpipe. Post-completion isolation – Isolates the open hole by incorporating a mechanical, knock-out flapper valve for closure into the screen when the washpipe is removed. Displacement and clean-up procedure. The selection of a mechanical configuration, which permits circulation of a solids-laden fluid from a wellbore, is only one of the design parameters that must be considered. The method of displacement is influenced by well geometry, screen standoff, flow rate, fluid density and rheology.9 Combining this with the subsequent uniform removal of the filter cake after positioning the screen is necessary for a successful open-hole completion. Major considerations associated with displacement operations are: Uniform clean-up – Probably the most widely known guideline to achieve a uniform annular displacement is to pump completion brine in turbulent flow. However, mechanical erosion or quick dissolution of very fine NaCl bridging solids with less dense, lower salinity brines (not a problem with sized CaCO3) can result in premature loss of clean-up solutions, thereby, reducing cake removal over the entire interval length. Channeling – Displacement involving fluids of dissimilar density and viscosity will channel in a horizontal wellbore. The effects of gravity and density, especially in an eccentric annulus where a displacement brine will favor the widest side and bypass slower-moving fluid in the narrowest side,10 can result in an ineffective removal of solids in the annulus and subsequently the filter cake. It could potentially restrict production through a prepacked screen. Filter cake composition – The wall cake deposited by a non-damaging fluid system during drilling contains: • Soluble bridging solids • Polymer • Insoluble drill solids. Successful cake removal must recognize the method required to remove or dissolve each of these distinct components. Salt particles, which are inert in a saturated environment, can be dissolved with brine that is not saturated with respect to NaCl. However, sized CaCO3, suspension and filtration polymers in the system overlay and fill in between the

Chapter Two Open-Hole Sandface Completions

particles, which develop an ultra-low permeability membrane, must be treated with an enzyme, acid or oxidizer. Surface, solids-control equipment should remove the majority of the coarse formation sand grains incorporated into the fluid system while drilling. However, fine insoluble drill solids, which are the same size as the soluble particle distribution and are not removed from the system, may ultimately become part of the filter cake, which cannot be dissolved. To maintain fluid rheology and filtration control and to provide a more soluble or compressible filter cake, these fine insolubles must be kept to a minimum with adequate dilution or larger initial drilling system volumes. Post-completion application. The final phase of the completion procedure is conducted after the wellbore clean-up operations. Should the isolation valve fail to close after removing the washpipe while tripping for the production tubing, a sized-NaCl or CaCO3 bridging pill with increased particle sizing may be placed inside the slotted liner or screen to prevent the loss of brine through the screen and into the formation. This pill may either be produced from the wellbore or removed with coiled tubing. Alternatively, solids-free, fluid loss pills (such as a high polymer loading of HEC or a crosslinked pill) can be used. The crosslinked pills are generally preferred because they will minimize the amount of gel leaked off to the formation, resulting in less formation damage. Filter-Cake Removal After placement of the completion assembly, removal of the polymer/ superfine NaCl or CaCO3 in the annulus and the filter cake on the formation is accomplished with a sequence of sweeps and soaks varying in viscosity, density and salinity. Reduced flow rates, which prevent turbulence for specific wellbore geometry, are incrementally increased as the completion stages progress. This method helps reduce channeling and mechanical erosion. It also makes, in a separate step, each component of the filter cake soluble and provides a more uniform wellbore clean-up. The three stages for optimum removal are: • Viscosified push pill • Breaker soak • Wash solution.

Viscosified push pill. Displacement flow pattern in cementing, where different fluid/slurry densities and gel strengths occur, may be directly related and provide guidance for displacing a drilling/completion system. McLean suggests that piston-like displacement of mud by an equal density cement slurry is possible through proper balance of the flow properties of the mud and cement slurries to the eccentricity of the annulus. The more eccentric the annulus, the thicker the cement must be relative to the mud. If proper balance is not achieved, bypassing of mud by cement cannot be prevented without assistance from motion of the casing or buoyant forces. Increasing the flow rate can help start all mud flowing but cannot prevent channeling of cement through slower moving mud in an eccentric annulus.11 Gravity forces will affect the removal of narrow-side annular fluid between the screen and open hole. If the fluid in the annulus is lighter than the displacement slurry, buoyancy of the displaced fluid contributes to its removal. The movement of a more dense fluid, under a lighter one, helps push gelled fluid upward into a wider section of the annulus where it is more easily removed. Therefore, a properly designed displacement push pill for a polymer fluid system containing sized bridging solids should be a weighted, viscosified slurry. The density should be 0.2 to 0.5 ppg higher, and it should have at least three times the low shear rate viscosity at shear rate of 0.06 sec -1 of the fluid being displaced. Upward buoyancy forces and increased yield strengths are generated, which overcome the yield stress of the displaced fluid, thereby creating fluid movement on the narrow side of the annulus. Breaker soak. Laboratory tests and field applications of various breakers have verified the necessity of applying proper techniques to expedite efficient filter cake removal. A soak and subsequent wash procedure has proven to be a preferable technique. Since these filter cakes primarily consist of polymers and NaCl or CaCO3 particles, suitable soak solutions contain enzymes, oxidizers or acids, that will degrade the polymers in the filter cake, yet will allow the bridging solids to remain more or less intact.

OMNI valve

•

Secondary ball seat

• •

•

Hydraulic setting tool Running position

Versa-Trieve packer

Sealbore Ported closing valve

•

Sealbore

•

Inner string swivel

•

Ceramic flapper w/internal prop sleeve

Fig. 2.6. Open-hole completion assembly

In the case of NaCl, each chemical soak is mixed in saturated sodium chloride brine and applied to the filter cake to break down the polymer film that coats the bridging salt. This film of polymer is very tenacious and difficult to penetrate without the application of a proper soak solution, adequate tangential forces or mechanical erosion. Hydraulics provide a method of inducing water losses through the filter cake, especially with low salinity brine or weak acid. However, this complicates uniform removal over long, varied permeability intervals where clean-up solutions can break through the higher permeabilities first, leaving little brine or acid available to remove filter cake from the lower permeabilities. By first degrading the polymer with a chemical breaker, fine NaCl or CaCO3 will remain intact over the formation pores, held in place by hydrostatic pressure. The low permeability between these soluble particles continues to restrict outward flow, allowing brine leakoff into the formation 17

Modern Sandface Completion Practices

Packer

Open hole with slotted liner

Packer

Open hole with screen

Fig. 2.7. Stand-alone slotted liners and screens in an open hole

100 Gravel

Frequency, %

20

Vcg sd

Cg sd

Mg sd

Fg sd

Vfg sd

Silt

Clay

80

15

60

10

40

5

20

0 10

1

0.1 Particle diameter, mm

0.01

Cumulative, %

25

0 0.001

Fig. 2.9. Extended range particle size sand distribution plot from sieve analysis

Fig. 2.8. Screen failure/damage from plugging of progressive screen plugging

to be equalized over the entire interval. Also, the breakdown of polymer separates the water or acid soluble particles and allows easier mechanical removal and particle dissolution during the subsequent displacement stages.

18

Wash solution. Selection of a suitable wash solution is based on the density requirement and compatibility with the soak solution. Wash solutions should be unsaturated at circulating temperature. Suitable wash solutions include potassium or ammonium chloride, sodium chloride, calcium chloride and sodium bromide brines, and weak acid. During the circulating wash phase, pump rates should be increased and decreased in order to reach maximum interval length as the soluble particles are dissolved and probable losses occur.

Stand-Alone Screens In some cases, slotted liners or screens are used alone to control the formation sand in open-hole completions as illustrated in Figure 2.7. These sand exclusion devices actually function as a fil-

ter. Unless the formation is well-sorted, clean sand with a large grain size, a stand-alone completion may have an unacceptably short producing life before the slotted liner or screen plugs. Subsequently, a “hot spot” may develop at some point in the formation interface causing potential erosion and screen failure (Fig. 2.8). Various measures for slot width or screen spacing have been offered in industry literature from results of sieve analysis done with formation sand; the accumulated weight percentage of particles larger than a certain diameter to obtain a size distribution that is plotted on a semi-logarithmic scale. Figure 2.9 illustrates an example plot, using laser particle size analysis (LPSA). If the analysis data is expected to provide accurate gravel-packing information, the samples used for sieve analysis must be representative of the formation. If possible, a sample should be taken every 2 to 3 ft (0.6 to 0.9 m) within the formation or at every lithology change. The minimum size of the formation sample required for a conventional sieve analysis is about 6 g. The typical amount of material used for LPSA varies from about 1 g to 10 g, depending on the amount of silt and clay-sized particles. The typical distribution range for laser-light defraction technology is approximately 3 mm to 0.001 mm. More on formation sand sampling is covered in the next section. These criteria range from those based on a single diameter in the formation sand size distribution (either D10 as suggested by Rogers12 or 2 x D10 as recommended by Coberly13) to attempts to better characterize the distribution through a uniformity coefficient (D40/D90).14 Recently, Tiffin et al.15 provided guidelines based on further experimental results, where they introduced two new parameters: sorting coefficient D10/D95 and mass fraction of fines (particles smaller than 44 micron). Their recommendations can be summarized as follows. Stand-alone screens can be used if: D10 /D95 < 10 And wire-wrapped screens should be used if: D40/D90 < 3 and fines < 2% by weight

Chapter Two Open-Hole Sandface Completions

Prepacked or premium screens should be used if: 3 < D40/D90 < 5 and 2% < fines < 5% by weight

Slotted Liners Slotted liners are manufactured by machining slot openings through oilfield tubulars with small rotary saws. Slotted liners are fabricated in a variety of patterns as illustrated in Figure 2.10. While slotted liners are usually less costly than wire-wrapped screens, they have a smaller inflow area and experience higher-pressure drops during production. Slotted liners also plug more readily than screens and are used where well productivity is low and economics cannot support the use of screens. The single-slotted, staggered-row pattern is generally preferred because a greater portion of the original strength of the pipe is preserved. The staggered pattern also gives a more uniform distribution of slots over the surface area of the pipe. The single slotted staggered pattern is machine-grooved with an even number of rows around the pipe. There is typically a 6 in. (15.2 cm) longitudinal spacing of slot rows. The slots can be straight or keystone shaped. The keystone slot is narrower on the outside surface of the pipe than on the inside. Slots formed in this way have an inverted “V” cross-sectional

Horizontal slotted

Single slotted non-staggered rows

Single slotted staggered rows

Gang slotted staggered rows

Fig. 2.10. Slotted-liner geometry

area and are less prone to plugging since any particle passing through the slot at the outside diameter (OD) of the pipe will continue to flow through rather than lodging within the slot. When used alone as sand exclusion devices, slotted liners (Fig. 2.11) or screens are placed across the productive interval and the formation sand mechanically bridges on the slots or openings in the wire-wrapped screen. Slot widths usually range from 0.012 in. (0.031 cm) to 0.250 in. (0.64 cm). Screen performance is usually judged based on the open area presented to the formation. However, the flow loss through an open slot is much less than that caused by flow convergence in the permeable media near the wellbore. Consequently, slot spacing is even more important, because this feature controls the extent of flow convergence away from the liner and into the formation. Consider the two cases illustrated in Figure 2.12.16 Case 1 illustrates the flow convergence associated with a wider slot over the zone covered by that slot. Case 2 shows two slots half as wide covering the same zone. The open area is the same in both cases, but the wider slot forces flow convergence to begin further away from the liner. The relationship between the extent of convergence and the slot spacing is nearly linear. So, Case 1 generates about twice as much flow loss for the same openarea as does Case 2. This illustrates why wire-wrapped screens perform so well. In addition to a large open area, the slots are very close together thereby minimizing the extent of flow convergence and its associated flow loss. Numerical analysis results demonstrate the slot factor sensitivity to slotting parameters. Figure 2.13 illustrates a comparison of slot factors for three slot widths in terms of open area. The analysis demonstrates that flow loss is

Fig. 2.11. Slotted liners with single-slotted, staggered rows Case 1: Slot width = W Slot width = N

Zone of flow convergence

Formation Inside of liner Case 2: Slot density = W/2 Slot density = 2N

Fig. 2.12. Slot induced flow convergence 10

Slot factor

A later section in this Chapter (“Gravel Packing”) contains details on determining formation grain size and what is meant by Dx. Stand-alone screen selection considerations should include the following: • Screen characteristics – Strength and damage resistance – Mud or DIF flow back – Sand control – Plugging resistance – Erosion resistance • Screen opening size • Laboratory testing with formation sand – Realistic test criteria – Transfer of laboratory results downhole • Prior industry experience. Increasing the area open to flow and decreasing annular flow outside the screen enhances stand-alone screen longevity.

6 in

1

Slot width, in. 0.012 0.018 0.025

0.1

0.01 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Open area, %

Fig. 2.13. Slot factor comparison for 5-1/2 in. liner with respect to open area 19

Modern Sandface Completion Practices

100

24

Slot factor

18 Plugged slot

1

12 Open slot

0.1

6

Plugging ratio

Plugging ratio 10

0.01 0 0 100 200 300 400 500 600 700 Slot density, slots/m

Fig. 2.14. Slotted open and plugged-slot performance for 5-1/2 in. liner

Effective inlet area, sq.-in./ft

32 Wire wrapped ribbed (channels) all welded screen

28 24 20 16

Machine grooved screen (channels)

12 6 Slotted liner

4 0

1

11/2 27/8 4 5 Pipe size, in.

65/8 85/8

Fig. 2.15. Comparison of effective inlet areas (20 gauge) Wire wrap Ribs Pipe base

Fluid flow

Fig. 2.16. Costruction schematic of wire wrapped screen

Fig. 2.17. All-welded, wire-wrapped screen on base pipe 20

nearly proportional to slot size for a given open area (i.e., smaller slots give smaller flow loss). Bridging theory shows that particles will bridge on a slot provided the width of the slot does not exceed two particle diameters. Likewise, particles will bridge against a slot or hole if its diameter does not exceed about three particle diameters. Plugging in slots (or screens) can be attributed to two main types of mechanisms: • Pore-throat plugging (in which the pore throats become filled with fines that migrate with the produced fluid or with precipitates produced by pressure reduction) • Slot plugging (in which sand particles bridge in the slot, causing it to become an extension of the reservoir material. The flow through the slot then becomes Darcy flow instead of open-channel flow, substantially increasing the pressure). If both mechanisms come into being, the pressure-loss problem is obviously compounded. Figure 2.14 illustrates the slot-factor distribution for open and plugged slots, with a curve showing the ratio between flow performance for the two cases.17 Over the range of practical slot densities, the plugging ratio is between 12 and 24, demonstrating dramatically reduced performance for a plugged slot. Furthermore, this resistance can be multiplied by pore throat plugging to effectively block inflow through the liner. The formation sand bridges formed will not be stable, regardless of the criteria used to determine slot width or screen spacing, and may break down from time to time when producing rate is changed or the well is shut-in. Because the bridges can break down, resorting of the formation sand can occur which over time tends to result in plugging of the slotted liner or screen. When this technique is used to control formation sand, the slotted liner or screen diameter should be as large as possible to minimize the amount of resorting that can occur. Another potential disadvantage of both slotted liners and screens in high-rate wells is the possibility of erosion failure of the exclusion device before a bridge can form. Stand-alone screen applications are used extensively in horizontal wells and will be discussed in this Chapter.

Conventional, Prepacked and Premium Screens As previously stated, there are various types of sand screens used for sand exclusion: • Conventional wire-wrapped screens • Prepacked screens • Premium screens. Wire-wrapped screen. Wire-wrapped screens offer an alternative for retaining the gravel in an annular ring between the screen and the formation. The advantage of a wire-wrapped screen over a slotted liner is substantially more inflow area (Fig. 2.15). The screen consists of an outer jacket, which is fabricated on special wrapping machines that resemble a lathe. The wire wrap is simultaneously wrapped and welded to longitudinal rods to form a single helical slot. The jacket is subsequently placed over and welded at each end to a supporting pipe base (containing drilled holes) to provide structural support. This standard design is generic and is manufactured by several companies. A schematic of the screen construction is illustrated in Figure 2.16. The term “gauge” is potentially confusing. Gauge refers to the slot width or wire spacing measured in thousandths of an inch. For example, a 20-gauge screen has a space between the wires of 0.020 in. (0.051 cm), and a 20-gauge slotted liner has a slot of 0.020 in. (0.051 cm) width. The best way to avoid confusion is to always specify the slot widths or wire spacing in inches (or millimeters or microns) rather than gauge. The main advantage of all-welded or wire-wrapped screens (Fig. 2.17), which typically employ grade 316L stainless steel wire, is the screens are more erosion and corrosion resistant than slotted pipe. The slotting process used to manufacture slotted liners changes the metal characteristics around the machined slots. This promotes corrosion problems. There are many cases where slotted liners have been delivered to a well site with corroded and plugged slots, rendering them useless as sand exclusion devices. This problem cannot be properly handled at the well site. However, there are areas and specific well conditions where slotted liners may be the only economical means of sand exclusion. If this is the case, proper care should

Chapter Two Open-Hole Sandface Completions

be taken to maintain the condition and quality of the slotted pipe. A field quality check that should always be made on a screen or liner after it reaches the field is to measure the wire spacing or slot width. A screen or liner should be rejected if the spacing varies more than 0.002 in. (0.005 cm) larger or 0.003 in. (0.008 cm) smaller than what was specified for the well. A screen that has a wire spacing that is too large will not control formation sand. Conversely, screens with openings that are too small are subject to plugging with dirty fluid, drilling fluid solids and formation sand. Prepacked screens. Prepacked screens are a modification of existing wirewrapped screens and represent a modular gravel pack. They consist of a standard screen assembly with a layer of resin coated gravel (consolidated) placed around it which is contained in an annular ring supported by a second screen (dual-screen prepack) or outer shroud (single-screen prepack). The thickness of the gravel layer can be varied to meet special needs. The screens with the lowest profiles are those which contain an annular pack between the jacket and the pipe base. The drilled-pipe base has a thin lattice screen wrapped around it to prevent gravel from flowing through its holes prior to consolidation (SLIM-PAK). Examples of various prepacked screens are shown in Figure 2.18. If they are not protected by a coating, plugging of prepacked screens with formation fines can be a serious problem. Proponents of prepacked screens claim that they are not as subject to plugging as previously thought because modern completion practices demand clean wellbore and filtered fluids. Nevertheless, a very small volume of solids will totally plug a prepacked screen. Some companies have run downhole filters in tubing strings to provide a final filter stage for fluids. However, they are often unable to complete a job without breaking the downhole filter, regardless of how clean the fluids and wellbore are. Prepacked screens are simply another design of a downhole filter. They will plug much more easily than a wire-wrapped screen. Premium screens. Slotted liners, wirewrapped screens and prepacked screens

Fig. 2.18. Three types of prepacked screens

were the initial completion method used to restrict the entry of formation sand into horizontal wells. Within the past ten years or so, several new screens designed to be used in stand-alone applications have become available. This new generation of screens was developed to address perceived problems with stand-alone completions; namely, plugging and erosion before the wells were depleted. Some of the newgeneration, premium screens include: • ResScreen Sand screen • con-slot screen • Baker Excluder2000 screen • Weatherford Stratapac screen • Halliburton PoroMax screen • Stren SC2000 screen • Schlumberger MeshRite screen • Weatherford Expandable Sand screen (ESS). ResScreen sand screen – This sand exclusion device (Fig. 2.19) is a robust single wire-wrapped sand screen that was recently introduced especially for open-hole, stand-alone completions in the North Sea. The base pipe determines its overall mechanical strength. Its design allows for Inflow Control Devices (ICD) (Fig. 2.20) which may mitigate the need for gravel packing and extend the application of standalone completions.18 Reslink uses SAND software19 from PETEC Software & Services, a member of the Rogaland Research Group in Norway, to determine the wire spacing for their screens. Results from the calculations are four, critical slot-wire

spacings that define a safe design interval for screen slot width: • Largest wire spacing where severe plugging is expected to be frequent (d--) • Smallest wire spacing where no plugging is expected to occur (d-) • Largest wire spacing where sand production is not expected to occur (d+) • Smallest wire spacing where continuous sand production is expected to occur (d++). For instance, these critical wire spacings are plotted for all the samples taken from the well. Screen wire-spacing design is then a matter of drawing a straight, horizontal line through the graph that intersects the critical wire-spacing curves as seldom as possible. A possible solution is illustrated in Figure 2.21. Using this method to determine screen wire spacing identifies: • Optimal screen wire spacing for a reservoir or part of a reservoir • Sand types that are well suited to stand-alone screen completions • Sand types that may cause problems for the chosen screen size. con-slot Formation Link screen – This is a heavy-duty, rod-based, wirewrapped screen (RBWWS) that is suitable for controlling formation sand in open-hole horizontal completions. It was introduced in the early 1980s and is promoted in preference to all pipe-base screens, citing that pipe-base screens create a restriction to flow that are not observed with rod-based screens. An important factor in providing for highflow capacity in the con-slot screen 21

Modern Sandface Completion Practices

1,000 d-dd+ d++

Slot spacing, micron

800

Suggested slot width: 250 micron

600

400

200

0 A2

A4

A6

A8 Sand type

A10

A12

A14

Fig. 2.21. Suggested wire-spacing design using SAND software output for an example well

Fig. 2.19. ResScreen sand screen

Fig. 2.22. con-slot RBWWS screen cutaway

Fig. 2.23. Baker Excluder2000 screen

100 90 80 70 60 50 40 30

C o a r s e w e a v e

M e d i u m w e a v e

F i n e w e a v e

Typical formation types Large grain Medium grain Small grain

20 D10

10 0 1,000

Fig. 2.20. ResChoke inflow control device. Produced fluid enters the wire-wrapped, base-pipe annulus through nozzles 22

100 Formation particle diameter, micron

Fig. 2.24. Baker Excluder2000 selection guide chart

10

Chapter Two Open-Hole Sandface Completions

design is the venturi-shape of the wire spacing and sharp corner radii of the wire (Fig. 2.22) which has a selfcleaning effect. However, should the screen still become plugged, surging or jetting from the inside can clean it. Hydraulics of the screen increases the permeability/transmissibility around it due to allowing not only a 100% cleanup of the mud or DIF system, but also a bridging of the coarser sand particles around the screen. This stabilizes the formation and allows for a sand-free production. To determine wire spacing, con-slot applies interpretation of a sorting factor, uniformity coefficient (Cµ ) from the formation sand distribution plot of the sieve analysis:20 Cµ = D40 /D90 When: Cµ < 2.00 Then, very uniform unconsolidated sand is denoted and dictates a slot size at D50 or 50% retention. When: Cµ ≅ 2.00 Then, uniform unconsolidated sand is denoted and dictates a slot size at D40 or 40% retention. When: Cµ > 2.00 Then, non-uniform unconsolidated sand is denoted and dictates a slot size at D30 or 30% retention. Baker Excluder2000 screen – This premium screen design consists of three layers of media placed concentrically around a drilled-pipe base to form the jacket. The base wrap for the jacket consists of a strength-enhancing Bakerweld Inner Jacket for the overlying Vector Weave Membrane medium. The protective Vector Shroud is then placed concentrically over the Vector Weave Membrane (Fig. 2.23). The Excluder2000 screen is available in three micron ratings (Fig. 2.24): • Fine: 100-200 D10 micron range (uniform pore openings promote high retention efficiency and large inflow areas to control sand without high differential pressures) • Medium: 200-300 D10 micron range (optimized membrane allows flowback of mud solids while maintaining sand retention)

• Coarse: >300 D10 micron range (pore size allows the very fine particles that would ordinarily plug the screen to be produced). Weatherford Stratapac screen – The screen design of this downhole exclusion device consists of multiple filtration layers of porous metal membrane (PMM) or porous metal fiber (PMF II). It contains about 30% open area through variable sized pore openings, between underlying drainage and overlying protecting mesh screens that are placed concentrically between a drilledpipe base and a perforated outer shroud. A schematic of the screen construction is illustrated in Figure 2.25. The filter medium for the screen is sintered metal powder that is pressed against a stainless steel lattice screen, which provides structural support for the filtration medium. The sand retention characteristics of the PMM and PMF II are illustrated in Table 2.3. Halliburton PoroMax screen – This screen (Fig. 2.26) is engineered for optimum inflow area in a shrouded, sintered-laminate screen from the Purolator Products Company. It retains the toughness of the highly successful, original Poroplus screen design. It is suitable for installations with an extended reach, long open-hole and multilateral completions, with or without centralization. It can function as a stand-alone or back-up means of sand control in horizontal open-hole completions, which is its most common application. Stren SC2000 screen – This sand exclusion device combines sintered metal mesh layers and metal fiber composite matrix for accurate pore sizing, yielding rugged, accurate sand particle control and flow erosion resistance. Rugged and crush resistant, Stren SC2000 (Fig. 2.27) screens have body diameters typically only 0.25 in. (0.64 cm) larger than tubing upset diameter. Schlumberger MeshRite screen – This screen technology claims to have 100 times the permeability of typical

reservoir formations. Perforated base pipe is wrapped with special stainless steel mesh fiber. The fibers are compressed to form angular, threedimensional pore spaces that range in

Fig. 2.25. Weatherford Stratapac screen

Fig. 2.26. Halliburton PoroMax screens

Fig. 2.27. Stren SC2000 screen

Media

Media Rating*

Equivalent Gravel Size

PMM PMF II 20/40 PMF II 12/20

60 micron 125 micron 200 micron

40/60 US Mesh 20/40 US Mesh 12/20 US Mesh

* Defined at 90% retention efficiency. Table 2.3. Sand retention characteristics of Stratapac filtration layers 23

Modern Sandface Completion Practices

Fig. 2.28. Schlumberger MeshRite screens

Fig. 2.29. Weatherford Expandable Sand Screen (ESS) partially expanded

size from 15 to 600 microns. This mesh structure maximizes the porosity within the filter. A perforated jacket protects the filter element and provides structural strength in both vertical and horizontal well applications. MeshRite screens reliably control a wide range of particle sizes and eliminate the need for screen sizing. The two profiles of a MeshRite screen are shown in Figure 2.28. Weatherford Expandable Sand Screen (ESS) – This sand control device 24

was the first commercially available expandable sand screen design.21 The slim nature of the design facilitates deployment of the screens in various open-hole applications, including high dogleg severity and horizontal wells. After deployment, the ESS can be expanded by a solid expansion cone and/or an Axial Compliant Expansion System. Once expanded it virtually eliminates the annulus, making gravel packing operations unnecessary in reservoirs that carry risks such as reactive shale, low fracture gradient, fractures or faults. A partially expanded ESS is illustrated in Figure 2.29. An ESS consists of three layers: (1) a slotted base pipe, (2) a filtration medium (Petroweave) and (3) an outer protective shroud (Fig. 2.30).22 Petroweave is a wirecloth woven in a Dutch Twill and is available in a range of selected micron ratings from 150 to 270 microns. This ESS design offers a number of unique advantages. It offers a large inflow area that minimizes screen plugging and erosion. It is operationally simple to install. It offers a larger internal diameter than any other type of sand control screen, optimizing inflow performance and facilitating installation of equipment for zonal isolation. In open-hole applications, an ESS eliminates the annulus between the screen and the sandface. It therefore stabilizes the sandface and minimizes sand movement, reducing the risk of sand failure and screen erosion caused by sand production. Other sand exclusion techniques may be more appropriate in some reservoir applications but, by nature, they will involve the loss of wellbore diameter, lower well productivity, and reduced well intervention and workover flexibility when compared to expandable screen technology. Stand-Alone Completion Assemblies A typical stand-alone completion assembly with an RBWWS in a horizontal open-hole is shown in Figure 2.31. Note the end of the coil tubing where there is a jet that can be used to wash inside of the screen. This diagram is representative of hundreds of downhole assemblies which can be designed using standalone liners or screens as the primary method for controlling sand.

Summary. Many more types of screens are available. The screen examples and designs discussed in this Chapter are representative of the wide variety of sand exclusion devices offered by numerous manufacturers. In some cases, there are more or less equivalent screen designs available from other commercial sources. For detailed specifications on these and other screens, contact the various screen manufacturing companies.

Gravel Packing A gravel pack is simply a downhole filter designed to prevent the production of unwanted formation sand. The formation sand is held in place by properly sized gravel-pack sand. The gravel-pack sand is held in place with a properly sized screen. Open-hole gravel packing is a common completion technique in many areas of the world, such as California, Canada, Bolivia, Venezuela, Brunei, China, Indonesia, Nigeria; and in some wells in the Gulf of Mexico and the North Sea. However, there are advantages and disadvantages of open-hole gravel packing, and an understanding of these factors will assist in selecting the completion technique to use where a choice is possible. Advantages of open-hole gravel packing include: • Easiest type of gravel pack to place because of the large annular space between the screen and the formation. Since gravel does not have to be carried through perforations, this technique presents minimal gravel transport problems. • Highest theoretical productivity because there are no perforation tunnels filled with gravel, sand or dirt to restrict flow. • Lowest possible velocity for produced fluids flowing through the gravel pack. • Usually less expensive because it eliminates some casing and cementing costs. Disadvantages of open-hole gravel packing include: • More difficult to control unwanted water or gas production, or injection into thief zones, within the completion interval. • Hole stability during placement of the gravel is often a problem, which

Chapter Two Open-Hole Sandface Completions

may result in sand filling the annulus around the screen before the gravel is placed. • Screen is more easily plugged with formation sand during gravel placement than in cased-hole completions. • The underreaming process may cause additional formation damage. • Generally limited to a bottom interval in multiple zone completions. • Sloughing problems may occur at the casing to open-hole interface. Most open-hole completions are underreamed before they are gravel packed. The underreaming usually increases the diameter of the borehole to approximately twice the casing inside diameter (ID). Usually casing is set above the productive zone, but sometimes casing is set through all productive intervals. Then, a window or windows are milled out through the zones to be gravel packed. Underreaming (Fig. 2.32) is defined as enlarging a wellbore past its original drilled size. It serves two purposes: (1) provides a larger wellbore diameter for slightly increased theoretical productivity and (2) removes mud cake and mud invasion damage. Unfortunately, the underreaming process, as it is commonly practiced, may cause as much formation damage as it removes due to the combination of fluid loss additives, dirt in the fluid and formation fines that are recirculated with the underreaming fluid. To prevent a weak formation from collapsing during underreaming operations, a formation compatible DIF or underreaming fluid must be properly employed to control fluid loss. Discarding the fluid returns is usually not considered due to cost. Consequently, the underreaming DIFs continuously become dirtier and cause more formation damage as underreaming operations advance through the formation. This formation damage cannot be removed prior to the gravel packing because the hole might collapse. So, it is frequently gravel packed in place. The result may be more restrictive than if underreaming were not done, or if casing were set to provide some stability to the formation. These concerns can be addressed with current filtering (see the “Fluid Filtration” section of Chapter Three) and polymer shearing (see the “Drill-In Fluids” section of this Chapter) devices. As gravel is being circulated into an open hole, the formation sand is dis-

turbed much more easily than in a cased-hole completion. This can cause formation sand to be fluidized and plug the slotted liner or screen, usually toward the lower part of the screen. Slurry packing, using a high-viscosity high-density slurry, can help alleviate this problem (see the “Gravel Packing” section of Chapter Three). Underreaming can cause formation damage toward the lower part of a zone. Additionally, the lower part of the slotted liner or screen can be plugged by circulating fluid and gravel. The overall result of these problems is that the highest leak-off rate, highest production rate and worst thief zones tend to be toward the top of the open-hole completion. Any subsequent stimulation treatment

Fig. 2.30. Weatherford ESS construction. Slotted base pipe, a metal weave filtration layer and outer protective shrouded

Fig. 2.32. Underreaming operation

Fig. 2.31. Stand-alone completion assembly with RBWWS 25

Modern Sandface Completion Practices

Outer core barrel

Steel sleeve

Split spring Full closure core catcher

Core bit Coring mode

Retrieval mode

Fig. 2.33. Hydro-Lift full closure core catcher

(i.e., steam injection, solvent treatment or acidizing) will preferentially flow into the upper part of the gravel pack. Once the pack is damaged, diversion of fluids from entering the upper part is difficult. Gravel-Pack Sand Sizing and Substitutes To determine what size gravel pack sand is required, samples of the formation sand must be evaluated to determine the median grain size diameter and grain size distribution. With this information, gravel pack sand can be selected using the technique outlined by Saucier.23 The quality of the sand used is as important as the proper sizing. API Recommended Practice 58 has set forth the minimum specifications desirable for a gravel pack sand.24 26

Formation sand sampling. Improper formation sand sampling techniques can lead to gravel packs which fail due to the production of sand or plugging of the gravel pack. The importance of a truly representative sample of the formation sand cannot be overstated in determining proper sand control design. Without a representative sample, the following items cannot be determined and are at best a guess: • Proper size gravel, slot or screen spacing to stop formation sand while maintaining productivity • Degree and type of clay stabilization required • Benefits or hazards of acidizing • Fluid filtration requirements to avoid damaging the formation (see “Fluid Filtration” section in Chapter Three). Samples must be at least 15 cc each. They should be taken every two to three

feet or at each lithology change. Most pay zones have varying permeabilities, porosities, average grain sizes and strengths. These parameters may change very quickly within an interval. Sandstone formations also vary across the reservoir; thus, representative samples should be taken from each well in a field. Unless a considerable history is available on a producing formation or reservoir, samples from only one well in a field should not be considered adequate. Continuous coring technology has been developed and may prove valuable for coring horizontal and long, high-angle wells. Today, depending on the type of formation being drilled, the best samples of formation sands are obtained by coring operations. The formation type will usually dictate the coring procedure (e.g., either double-tube, which have effectively replaced rubber sleeve, or conventional core barrels).25 The classification of formation sands include: • Quicksand (completely unconsolidated formation sand) • Partially consolidated sand (has some cement agents present, but is only weakly consolidated) • Friable sands (semi-competent, well cemented and potentially troublesome). The use of double-tube core barrels, enhanced by a full-closure core catcher system (Fig. 2.33) is the only technique currently available to obtain good samples of quicksand. This type of formation sand tends to fall out of conventional core barrels and limits core recoveries. The rubber or plastic sleeve core barrel holds the core together during the coring and retrieving operation and often results in better core recovery. A conventional core barrel can be used to recover samples of friable and partially consolidated formations. However, low recovery efficiencies would indicate alternating intervals of consolidated and unconsolidated formations, and consideration should be given to using double-tube core barrels for total recovery. Experience in a formation will dictate the best coring system. If full cores of the formation are not available, the next best samples are sidewall cores. Partially because they are less expensive than full cores, sidewall cores are frequently the only types of cores available from most sandstone formations (especially in workover operations). Sidewall core samples are

Chapter Two Open-Hole Sandface Completions

small and often contain mud cake or invaded mud particles. However, they are more representative of the formation sand than either produced or bailed sand samples. Samples of the formation sand obtained at the surface in vessels or flow lines will usually contain only the smaller sand grains, which were easily transported out of the wellbore. Samples taken at different points on the surface (wellhead, sand trap, heater treater, etc.) will indicate a variation in sand grain size distribution. This variation makes it difficult to know which sample to use. Samples obtained from bailing operations or from circulation of fill off bottom will generally include the larger sand grains from some of the interval(s) opened to production. In summary, if full-sized cores are not available, the next best samples are sidewall cores. Sidewall cores are small and generally will contain some mud, but they are more representative of the formation sands than either produced or bailed samples of sand. Produced samples of formation sand tend to be skewed toward the small grain sizes and bailed sand samples tend toward the larger grain sizes. Surface or bailed samples of formation sand should never be used for designing sand control treatments.26 Conventional core, unconsolidated core and sieve analyses. Numerous laboratory tests, which can be performed on core samples and other types of formation samples, aid in the proper design of (1) drilling mud, (2) DIFs, (3) completion fluids, (4) stimulation treatments and (5) sand control installations. For example, Core Lab was the first company to introduce laser-optics, particle-size analysis as a routine service. With a range of measurements that cover sand, silt and clay size particles, the applications of the data have grown to include enhanced sidewall core permeability determination, stand-alone slotted liner or screen selection and gravel-pack design. The analysis of data obtained from formation cores and samples have become very sophisticated, and an indepth discussion of modern data analysis and data management techniques is well beyond the limitations of the scope of this presentation. However, for discussions related to unconsolidated

sands, three basic types of laboratory analysis should be reviewed. Conventional core analysis – A set of measurements normally carried out on core plugs or whole cores. These generally include porosity, grain density, horizontal permeability, fluid saturation and a lithologic description. Routine core analyses often include a core gamma log and measurements of vertical permeability. Measurements are made at room temperature and at atmospheric confining pressure, formation confining pressure or both. It should be understood that conventional core analysis is distinct from special core analysis (SCAL). Recommended practices for routine core analysis, which are routinely performed in oil field laboratories, are available in Core Analysis, 2nd Edition, API Recommended Practices 40, February 1998.27 Unconsolidated core analysis – It must be understood that unconsolidated formation samples can be easily damaged and require special equipment and techniques for safe, reliable acquisition and transportation. Labs located in key producing regions around the world offer various tests, which can be performed on these samples and include: • Sample selection and preparation using spectral core gamma, CT scanning and mineralogy screening. • Poro-Perm to determine porosity, gas permeability, and Klinkenberg corrected permeability. • Resination to preserve core integrity after slabbing. • Sw/Sor determined directly from core. • Unsteady-State Profile Permeametry to provide rapid, quantitative determination of detailed permeability variations. • Profile Acoustic to evaluate sanding potential and borehole stability models. • Photography to reveal fluorescing hydrocarbons and minerals. • High Resolution Digital Core Imaging to provide detailed sedimentary information by acquiring continuous images of the entire core at resolutions up to 300 dots per inch (dpi) at the core surface. At selected positions, an area over 10 mm by 7 mm and up to 5,000 dpi can be produced to provide highly detailed textural information (Fig. 2.34). Sieve analysis – A typical laboratory routine performed on a formation sand

Fig. 2.34. High-resoolution digital core imaging

Fig. 2.35. Sieves and shaker apparatus

Fig. 2.36. Various sieves containing formation samples after sieving process 27

Modern Sandface Completion Practices

Cumulative weight, %

100 90 80 70 60 50 40 30 20 10 0 0.1000

Well sorted sand Poorly sorted sand D50

0.100 0.0010 Grain diameter, in.

0.0001

Fig. 2.37. Sieve analysis of uniform and non-uniform formation sands

Gravel

Fluid flow

Sand

Ratio of final permeability to initial permeability, kf/ki

Fig. 2.38. Saucier’s experimental core

12 10 0.8 0.6 0.4 0.2 0.0

0 2 4 6 8 10 12 14 16 18 20 Ratio of median gravel pack sand diameter to median formation sand dia., D50/d50

Increased gravel pack sand permeability as a function of D50 and D50/d50

Fig. 2.39. Results of Saucier’s gravel size experiments 29

Optimum sand control

No sand control

0 2 4 6 8 10 12 14 Ratio of median gravel-pack sand diameter to median formation sand dia., D50/d50

Fig. 2.40. Gravel-pack sand size optimization 28

sample for the selection of the proper size gravel-pack sand according to ASTM E-11. Figure 2.35 shows a typical sieves and shaker apparatus. Sieve analysis consists of placing a formation sample at the top of a series of screens, which have progressively smaller mesh sizes. The sand grains in the original well sample will fall through the screens until encountering a screen through which grains size cannot pass because the openings in the screen are too small. By weighing the screens before and after sieving (Fig. 2.36) the weight of formation sample retained by each size screen can be determined.

The cumulative weight percent of each sample retained can be plotted as a comparison of screen mesh size on semi-log coordinates to obtain a sand size distribution plot (Fig. 2.37). Reading the graph at the 50% cumulative weight gives the median formation grain size diameter. This grain size, often referred to as D50, is the basis of gravel-pack sand-size selection procedures. Table 2.4 provides a reference for mesh size versus sieve opening. Gravel size determination. There have been several published techniques for selecting a gravel-pack sand size to

US Series Mesh

Sieve Opening (in.)

Sieve Opening (mm)

2.5 3 3.5 4 5 6 7 8 10 12 14 16 18 20 25 30 35 40 45 50 60 70 80 100 120 140 170 200 230 270 325 400

0.3150 0.2650 0.2230 0.1870 0.1570 0.1320 0.1110 0.0937 0.0787 0.0661 0.0555 0.0469 0.0394 0.0331 0.0280 0.0232 0.0197 0.0165 0.0138 0.0117 0.0098 0.0083 0.0070 0.0059 0.0049 0.0041 0.0035 0.0029 0.0024 0.0021 0.0017 0.0015

8.000 6.730 5.660 4.760 4.000 3.360 2.830 2.380 2.000 1.680 1.410 1.190 1.000 0.840 0.710 0.589 0.500 0.420 0.351 0.297 0.250 0.210 0.177 0.149 0.124 0.104 0.088 0.074 0.062 0.053 0.044 0.037

Table 2.4. Standard sieve openings

Chapter Two Open-Hole Sandface Completions

control the production of formation sand. The technique most widely used today was developed by Saucier.28 The basic premise of Saucier’s work is that optimum sand control is achieved when the median grain size of the gravel-pack sand is no more than six times larger than the median grain size of the formation sand. Saucier determined this relationship in a series of core flow experiments where half the core consisted of gravel-pack sand and the other half was formation sand (Fig. 2.38). The ratio of median grain size of the gravel pack sand and median grain size of the formation sand was changed over a range from two to ten to determine when optimum sand control was achieved. The experimental procedure consisted of establishing an initial stabilized flow rate and pressure drop through the core and calculating an effective initial permeability (ki ). The flow rate was increased and maintained until the pressure drop stabilized followed by a decrease in flow rate back to the initial value. Once again, pressure drop was allowed to stabilize and an effective final permeability (kf ) of the core was calculated. If the final permeability was the same as the initial permeability, a conclusion was made that effective sand control was achieved with no adverse productivity effects. If the final permeability was less than the initial permeability, the conclusion was made that the formation sand was invading and plugging the gravel-pack sand. In this situation sand control may be achieved, but at the expense of well productivity. Figure 2.39 illustrates the results of the core flow experiments and can be summarized as follows: When: D50 /d50 ≥ 6 Then, there is good sand control and no formation sand invasion of gravel pack sand. When: 6 < D50 /d50 ≥ 13 Then, there is good sand control but restricted flow due to formation sand invasion of gravel-pack sand. When: D50 /d50 < 13 Then, there is no sand control and the formation sand passes through the gravel-pack sand.

In practice, the proper gravel-pack sand size is selected by multiplying the median grain size of the formation sand by four and eight to achieve a gravelpack sand size range whose average is six times larger than the median grain size of the formation sand. This calculated gravel-pack sand size range is compared to the available commercial grades of gravel-pack sand. The available gravel-pack sand that matches the calculated gravel-pack size range is selected. In the event that the calculated sand-size range falls between the size ranges of commercially available gravelpack sand, the smaller gravel-pack sand is normally selected. Table 2.5 contains information on commercially available gravel pack-sand sizes from Unimin. Note that Saucier’s technique is based solely on the median grain size of the formation sand with no consideration given to the range of sand grain diameters or degree of sorting present in the formation. The sieve analysis plot discussed earlier can be used to establish an indication of the degree of sorting in a particular formation sample. A near vertical sieve analysis plot represents a high degree of sorting (most of the formation sand is in a very narrow size range) versus a more horizontal plot which indicates poorer sorting. Again, refer to the plots shown in Figure 2.37. A sorting factor, or uniformity coefficient, can be calculated as follows: Cµ = D40 /D90 US Series Mesh (ASTM E-11)

12/20

12 16 18 20 25 30 35 40 45 50 60 70 PAN

– 22.7 59.4 17.1 0.8 – – – – – – – –

Where: Cµ = sorting factor or uniformity coefficient D40 = grain size at the 40% cumulative level from sieve analysis plot D90 = grain size at the 90% cumulative level from sieve analysis plot If Cµ is greater than five, the sand is considered to be poorly sorted. In such case, the next smaller size gravel-pack sand than the size calculated using Saucier’s technique may be justified. Another method, which can be applied when poorly sorted sand is encountered, is to use the D75 grain size instead of D50 to calculate the appropriate gravelpack sand size. Using the results of Saucier’s experiments, optimization of gravel-pack sand size (Fig. 2.40) can be accomplished using the following guidelines.30 When: D50 /d50 < 5 Then, there is good sand control but restricted flow due to low gravel permeability. When: 5 < D50 /d50 < 7 Then, there is good sand control and maximum pack permeability. When: 7 < D50 /d50 < 9 Then, there is good sand control but restricted flow due to formation sand invasion of gravel- pack sand.

Typical Mean % Retained on Individual Sieves 16/30 20/30 20/40 30/40 – trace 6.9 54.4 36.7 1.8 0.1 – – – – – –

– – – 0.4 72.1 26.7 0.8 – – – – – –

– – – 0.4 14.1 29.3 47.3 8.1 0.8 – – – –

– – – – – 0.5 74.0 24.7 0.8 – – – –

40/60 – – – – – – – 0.6 40.9 48.3 9.3 0.9 –

Table 2.5. Gravel sizes distribution of Accupack 29

Modern Sandface Completion Practices

When: D50/d50 > 9 Then, there is no sand control and the formation sand passes through the gravel-pack sand. Gravel-pack sand. Gravel pack well productivity is sensitive to the permeability of the gravel-pack sand. To ensure maximum well productivity only high-quality, gravel-pack sand should be used. The API Recommended Practices 58 31 establishes rigid specifications for acceptable properties of sands used for gravel packing. These specifications focus on ensuring the maximum permeability and longevity of the sand under typical well production and treatment conditions. The specifications define minimum acceptable standards for the size and shape of the grains, the amount of fines and impurities, acid solubility and crush resistance. Only a few naturally occurring sands are capable of meeting the API specifications without excessive processing. The high quartz content and consistency in grain size characterize these sands. A majority of the gravel-pack sand used in the world is mined from the Ottawa formation in the Northern United States. Table 2.6 documents the permeability from three separate inves-

tigations of common gravel-pack sand sizes that conform to the API Recommended Practices 58 specifications. Gravel-pack sand substitutes. Although naturally occurring quartz sand is the most common gravel-pack material used, a number of alternative materials for gravel-pack applications exist. These alternative materials include resin-coated sand, garnet, glass beads and aluminum oxides. Although two to three times more costly, each of these materials offers specific properties that are beneficial for given applications. Resin-coated gravel – A thin layer of resin coating on standard gravel-pack sand may provide some protection against quartz dissolution due to high pH steam,35 but not by HCl-HF acid. It is primarily used in the manufacture of prepacked screens (discussed earlier in this Chapter), and has gained some renewed interest for screenless frac packing (see Chapter Three). Aluminum oxide (Sintered Bauxite, CarboLite, etc.) – This is a processed product with extremely high permeability. It resists dissolution due to high pH steam and is moderately to highly soluble in HCl-HF acid. The primary applications of these products are for frac packing and for fracturing thermal wells.

US Mesh Range

Permeability 32 (Darcy)

Permeability 33 (Darcy)

Permeability 34 (Darcy)

6/10 8/12 10/20 12/20 16/30 20/40 40/60 50/70

2703 1969 652 171 69 -

500 250 119 40 -

668 415 225 69 45

Table 2.6. Permeabilities of gravel-pack sands

Gravel Size (US Mesh)

Gravel Size (in.)

Screen Gauge (in.)

Screen Gauge (in.)

40/60 30/50 20/40 16/30 12/20 8/12

0.0165-0.0098 0.0230-0.0120 0.0330-0.0165 0.0470-0.0230 0.0660-0.0330 0.0940-0.0470

0.008 0.010 0.012 0.016 0.020 0.028

8 10 12 16 20 28

Table 2.7. Screen gauge used with various gravel sizes 30

Garnet – This mineral is a brittle and more-or-less a transparent, usually red, complex silicate with a high specific gravity (3.4 to 4.3). Its primary application is in thermal wells due to its resistance to dissolution by high pH steam. Garnets are also resistant to HCl-HF acid. Glass beads – This silica material is a processed product that is extremely round and highly soluble in HCl-HF acid. It is a predecessor to aluminum oxide. Slotted Liner and Screen Design These two general types of sand exclusion devices perform the same function in gravel packs, so the discussion in this section will use the term “screen” to include both slotted liners and screens. Screens must be designed to allow gravel to be packed completely around them and then hold the gravel in place during production, just as the gravel holds the formation sand in place. Production of a substantial quantity of gravel will jeopardize the success of a gravel pack by uncovering the upper portion of the completion or creating a hole in the pack. Wedging of out-ofsize gravel into the openings of the screen will restrict fluid production. Therefore, proper screen designs for gravel packs are very important. Screen openings (slot widths or wire spacing) should be smaller than the smallest gravel grains at downhole conditions. There is little difference between screen openings at the surface and downhole, but gravel sizes do change. Gravel is eroded as it is pumped through triplex pumps, down a work string and through crossover tools; and the effect of erosion depends on the gravel size and quality, the pump rate and the fluid that is used. A weak, non-spherical, poorly rounded gravel (less than API standard gravel), high pump rate and low-viscosity brine will cause the greatest amount of erosion, as well as considerable screen plugging. Screen openings are usually referred to by the term “gauge,” which means one thousandth of an inch (e.g., 0.012 in. is 12 gauge). The most common screen opening designs are listed in Table 2.7, which indicates that a 12gauge screen is normally used with 20/40 U.S. Mesh gravel. These recommended screen openings provide the best results with good quality gravel, low pump rates and gelled or viscous

Chapter Two Open-Hole Sandface Completions

fluids. Smaller screen openings should be used for poor quality gravel, water packing and high rate water packing. Screen diameters should allow at least a two-inch radial clearance in open-hole completions. The reasons for this recommendation are: • A large annulus reduces the chance of gravel bridges forming as the well is being packed, which could leave cavities in the gravel pack. • Gravel can shift more easily in a larger annulus, which makes it easier to tightly pack the well. • Two inches or more reduces the risk of fluidizing the formation sand in an open hole when gravel is being circulated around the screen. Screens have such high flow capacities that there is no reason for the diameter of a screen to be larger than the production tubing unless multiple gravel packs are performed in one wellbore or a logging tool or pump needs to be positioned inside the screen. Centralizers should be placed below and above the screen and/or at minimum spacing of 15 ft (4.57 m) so that the gravel can be packed uniformly around the screen. Bow-spring type centralizers are used in open holes. A tell-tale screen is usually a short section of screen placed above or below the production screen. Lower tell-tale screens, used when open-hole gravel packing, are usually no longer than 5 ft (1.52 m) and have a seal bore between the lower tell-tale screen and the main screen. Lower tell-tale screens are used in open-hole gravel packing with highviscosity, high-density gravel slurry. Upper tell-tale screens are usually used with conventional low-viscosity, lowdensity, gravel-packing fluids. The top of the screen in an open hole should be designed to provide reserve gravel in the underreamed open-hole section. Gravel Packing Methods Based on experiences of major service companies, the following are absolute requirements for open-hole gravel-pack tool systems: • Must be capable of maintaining overbalance pressure at all times. • All operations must be performed without swabbing or surging the formation. • Must provide ability for positive tool positioning.

Casing

Cement

Slotted-liner or wire wrapped screen

Wash pipe (tail pipe) Underreamed open hole

Fig. 2.41. Reverse circulation, open-hole gravel pack method

Three basic tools are used in gravel packing operations: • Packer/crossover tool assembly • Over-the-top tool assembly • Port collars. Some are completion tools that remain in the well after the gravel pack is complete. On the other hand, service tools are used while placing the gravel pack but then are removed. Vertical wells. Reverse circulation gravel packing (Fig. 2.41)36 was one of the early techniques used before the development of the crossover tool. It was frequently used in relatively short, open-hole intervals where there was minimum deviation and separation of zones was not necessary. It is not as popular today because of the following problems: • Requires large volumes of fluid • Potential pack damage due to casing debris during annular gravel placement • Potential pack damage due to mixing gravel with filter cake and formation sand. For low-pressure, shallow wells, one popular version of the crossover method, which has been around for decades, is the “over-the-top” system. It uses a downward cup-type pack above the crossover tool. Gravel is

Fig. 2.42. Mechanical set cup-type packer

placed below a cup-type service packer (Fig. 2.42). For reversing, clean fluids are pumped past the cup packer and back up the tubing. The cup packer is then pulled, and an inexpensive O-ring or Chevron seal overshot is landed into the top of the screen (Fig. 2.43). For higher-pressure wells where greater control is needed, “one-trip” tools are used. These tools are described more fully in Chapter Three. Briefly, the advantage is that a highquality production packer can be run 31

Modern Sandface Completion Practices

Casing

Packer Cement

Upper tell-tale Underreamed open hole Screen

Fig. 2.44. Open-hole, low-viscosity, lowdensity, crossover gravel-pack method

Fig. 2.43. Liner sealed to casing with O-ring or Chevron seal overshot

and tested. In many cases the production packer is required as an integral part of a high-pressure well completion. Figure 2.44 illustrates a modern gravelpack tool being used to circulate a pack into place in an underreamed hole, with fill-up to be indicated with an upper, tell-tale screen.37 Special equipment that may be used in open-hole gravel packing includes port collars, inflatable packers and combination tools. 32

In a vertical open-hole well, the gravel-packing screen and tool hookup should typically be as follows (starting from the bull plug on the bottom): 1. Approximately 5 to 10 ft (1.52 to 3.05 m) of blank liner will allow for some sloughing of formation sand between the time the screen is on bottom and the time the gravel is placed. A 5 ft (1.52 m) blank is probably enough for relatively strong (friable) formations and 10 ft (3.05 m) should be used for weaker formations. 2. Approximately 5 ft (1.52 m) lower tell-tale screen and seal bore above it will indicate sand fill, screen plugging and when gravel reaches the bottom of the well. 3. Slotted liner or screen from the lower blank liner to within 10 ft (3.05 m) below the top of the underreamed hole section. 4. At least 10 ft (3.05 m) of blank liner, or 10% of the total open-hole length if the total open-hole length is more than 100 ft (30.48 m). This allows reserve gravel to be placed inside the underreamed hole so that the gravel may settle without exposing the screen or slotted liner to direct contact with the formation. 5. About 20 to 30 ft (6.10 to 9.14 m) of blank liner up in the casing.

6. Approximately 5 ft (1.52 m) upper tell-tale screen, only if conventional gravel packing placement technique is used. 7. Approximately 5 to 10 ft (1.52 to 3.05 m) of blank liner. 8. Crossover tool assembly and packer. 9. Washpipe or stinger hanging from the crossover tool with its bottom in the seal assembly, if a lower tell-tale screen is used (otherwise hanging just to near the bottom of the main screen). 10. Bow-spring centralizers spaced out every 15 ft (4.57 m) in the open hole, starting with one on the lower blank liner. 11. Steel-wing centralizers should be used on the upper blank liner in the casing. A simplified illustration of this assembly, but without the lower tell-tale screen, is illustrated in Figure 2.45. The following recommendations have been successful for obtaining good results in open-hole gravel packs: Placement technique – Use the onetrip tools (described in the “Gravel Packing” section of Chapter Three) with lower tell-tale screen and seal bore with the high-density, slurry-pack technique. After fluid returns are lost by covering the lower tell-tale screen with gravel, the tools can then be shifted to the upper circulating position to finish packing the annulus while back pressure is held on fluid returns to help pack gravel against the formation. Alternate technique – Some operators keep the tools in the lower circulating position or shift to the squeeze position until a sandout is observed. Some claim that this actually balloons the open hole to achieve a better pack. High gravel concentration (15 to 20 lb/gal), large screen/hole annulus and downward momentum of the slurry in vertical wellbores allow packing of the entire open-hole section. This is not advisable in long open holes (>100 ft [>30.48 m]) and high-angle open holes (>60° from vertical). Lower tell-tale screen – A lower telltale screen and seal bore should be used for high-viscosity, high-density gravel packing on every well. The reason for this is that a lower tell-tale and seal bore will indicate if the screen is being covered with sand or plugged with sand or dirt before you start pumping gravel. The pressure drop across a 5 ft (1.52 m)

Chapter Two Open-Hole Sandface Completions

screen should be approximately the same as the pressure drop circulating through the main screen while circulating ungelled brine at 1 or 2 bpm. If the pressure to circulate in the lower circulating position is much higher than in the upper circulating position, the entire assembly should be pulled and wellbore and screen cleaned. Caliper logs – The hole should be callipered after underreaming to ensure it is open to the desired diameter and depth, and to determine the quantity of gravel needed to fully pack the hole. Underreaming fluids – These fluids must be clean and formation compatible. They should provide low-fluid-loss rate and enough viscosity to carry cuttings to the surface. All of these properties are necessary to maintain hole stability, minimize formation skin damage, maximize well productivity and reduce thief zone problems. In quicksand and many partially consolidated formations, this is virtually impossible to achieve without adding an oil-soluble, watersoluble or acid-soluble fluid loss additive to a viscous fluid and discarding the fluid returns. Naturally, these additives will add considerable cost to the operation and must be removed before maximum well productivity is obtained. Drill-in fluid – Initially drilling the payzone with a DIF (discussed previously in this chapter) may eliminate the need for an underreaming step. Removal of formation damage after the pack – Serious efforts should be made to prevent formation damage during drilling and underreaming an open hole, but there will always be some damage present. No attempt should be made to remove this damage before gravel is packed in the well, because of the risk that the formation sand will slough into the hole and interfere with gravel placement. Removal of formation damage after the pack must be done very carefully to prevent pushing gravel away from the slotted liner or screen, mixing of gravel with the formation sand or adding more damage to the pack and formation. Spotting solvent on bottom and soaking it into the gravel and formation or slowly injecting solvent via coil tubing are the preferred methods. However, neither of these techniques is really very effective because they do not force solvent into the most damaged sections of the completion.

Fig. 2.45. Typical vertical open-hole assembly

Wash tools with opposing cups (Fig. 2.46) have been used with some success to focus the injected solvent, but these tools have proven to be extremely damaging to a gravel pack when they are used to circulate fluid through the pack. If short blank sections of screen or liner have been made-up between sections of the gravel-pack screen or slotted liner, and if spaced out so that the tool cups will match blank sections and isolate each section of screen or slotted liner; injecting solvents slowly through a wash tool could be effective. Gravel packing low-pressure wells – Foam has been successfully used to circulate gravel into shallow, low-pressure open holes. Low-liquid-volume fraction foam helps stabilize the hole because it does not easily leak-off to the formation, but it can flow through the screen as gravel is being packed. Forty pounds of gravel per minute can be added to the foam via a downstream sand injector, and standard crossover circulation tool systems can be used. Foam is also a good diverting system for after gravel-pack acid treatments,

Fig. 2.46. Wash tool

especially if HEC gelled brines and acid-soluble or water-soluble additives have been used for fluid loss control while drilling or underreaming. Washing the pack – Do not wash a pack after it is in place. This procedure is sometimes undertaken in an attempt to eliminate voids and place additional gravel across the screen. Studies have shown that this damages the pack and promotes mixing of gravel with formation sand. It should never be attempted. Correct placement techniques and fluids should completely pack the interval; but if much less than 100% fill is obtained or logs indicate there are cavities in the pack, the screen and gravel should be removed and the gravel pack should be redone. Horizontal/deviated wells. An exact definition of a horizontal well is a drilled hole achieving a deviation angle of 90° from vertical. In application, the technology is much broader than this, and well profiles with deviation angles exceeding ±70° (highly deviated) are often referred to as “hori33

Modern Sandface Completion Practices

First horizontal openhole gravel pack from Floater Brazil (Oct. 1998)

First horizontal OHGP (openhole gravel pack) Congo (1990) First horizontal, offshore California (1988)

1988

First Gulf of Mexico horizontal gravel pack (1993)

1990

1992

1994

First deepwater Gulf of Mexico horizontal openhole gravel pack (Aug. 1997)

1996

1998

2000

Fig. 2.47. Horizontal gravel-packing time line

1,600 Directional wells Frac-pack wells Horz gravel packs Horz slotted lines

1,400 1,200

bopd

1,000 800 600 400 200 0 1

2

3

4

5

6 7 Months

8

9

10

11

12

Fig. 2.48. Comparison of average initial 12 month oil production in Venezuela wells

Crossover packer Upper tell tale Wash pipe Upper tell tale Screen 45° Wire-wrap screen

Wash pipe

Fig. 2.49. Low-viscosity circulation gravel packs 34

zontal” if the length of the wellbore within the producing formation is many times greater than the thickness of the producing formation. Gravel packing is the option to standalone screens, discussed previously, for completing horizontal wells in unconsolidated formations. While this technology is more complicated and sophisticated than slotted liners, wire-wrapped screens, prepacked screens or premium screens, it is a more general-purpose completion for horizontal wells where sand control presents a problem. While using slotted liners, wire-wrapped screens, prepacked screens or premium screens may be applicable only for certain wells; a gravel pack can be used on almost any horizontal completion provided that sound gravel placement guidelines are followed. Additionally, this technique is believed to meet the challenge of completing high volume producers (>15,000 bbl/d in oil wells or >70 mmcf/d in gas wells) in high permeability formations with well lives of up to 15 years.38 Note the time line of significant horizontal gravel-packing events (Fig. 2.47). Some believe that gravel packing long, horizontal wellbores should only be considered if it will improve well productivity or stability. The combination of high angle and long interval is very difficult to gravel pack successfully without trapping a lot of formation damage in place. The effect of gravel packing around a prepacked screen on well productivity can be seen in Table 2.8.39 If gravel packing is not done, the formation sand may eventually fill the screen/hole annulus when the well is on production. This will not significantly reduce the well productivity, if the permeability of the sand remains nearly equal to that of the undamaged formation sand. However, if mud cake and formation mix reduces the permeability of the sand in the annulus from 1,000 to 100 md, the well productivity may be reduced by approximately 24%. Because it is highly unlikely that it will occur in a horizontal wellbore, sand and shale mixing will not reduce gravel permeability. Theoretically, the impairment of well productivity will be less if gravel prevents the screen/casing annulus from filling with low permeability. However, more damage to the formation may be done by fluid-loss-control solids and

Chapter Two Open-Hole Sandface Completions

polymer during the gravel pack, which will result in severe impairment. Gravel packing has not been widely used in horizontal wells until the last decade or so, but results since then have been promising. Consider the comparison of production from directional, frac-pack, horizontal gravel pack and horizontal slotted-liner completed wells in Venezuela (Fig. 2.48).40 The reason for the initial lack of use appears to have been reluctance on the part of operating companies to try a long, horizontal gravel pack because of the perception that the technology is not available to place gravel over an interval of several thousand feet with success. The industry has long recognized the difficulties of successfully gravel packing long, highly deviated conventional wells using viscous gravel carrier fluids.41 Since horizontal wells represent the ultimate long, highly deviated well, a reluctance to gravel pack is well founded. At the time horizontal wells were beginning to be drilled in unconsolidated formations, viscous gel carrier fluids represented the state-of-the-art in gravel-packing technology. Research and studies in physical models confirm that performing a successful gravel pack in a horizontal well using viscous gravel carrier fluids is extremely difficult. Today, brine is the state-of-the-art gravel carrier fluid. Research and studies in physical models confirm that performing a successful gravel pack in a horizontal well using brine is possible. It is widely believed that by stabilizing the formation sand, gravel packing increases the reliability and longevity of sand control completions in highly deviated and horizontal wells. An additional driver for open-hole gravel packing is the productivity limitations of the casedhole frac-packing technique in hightransmissibility formations. Although open-hole gravel packing of horizontal wells extends well life, achieving a high-productivity, sand-free completion involves a number of considerations in the design and execution stages. Field-scale testing – The feasibility of gravel packing a long, horizontal well (which includes the completion equipment design, pumping schedules and other related procedures) has been determined using scaled physical models.42 Up to well deviations of about 60º, gravity tends to initially assist in transporting

the gravel to the bottom of the completion interval (Fig. 2.49). However, at well deviations exceeding 60º, the angle of repose of the gravel is exceeded (Fig. 2.50). As a result, dimensional changes must be made to the gravel-pack equipment and higher pump rates are required to completely gravel pack the entire interval. The main requirement is that the ratio of the OD of the wash pipe to the ID of the screen must be at least 0.75, and returns through the wash pipe must be sufficient to transport the gravel to the toe of the well. The gravel placement at deviations exceeding 60° is initiated at the top of the completion interval rather than at the bottom of the well, as is the case when well deviations are less than 60°. The subsequent gravel placement extends downwards until the gravel dune, commonly referred to as the

alpha wave, reaches the bottom of the well. At that point, secondary placement, or beta wave deposition, packs the volume above the alpha wave (Figure 2.51). However, if the gravel concentration is too high, the flow rate is too low, or the wash pipe permits excessive flow in the annulus between it and the screen, the alpha wave will prema-

Container Inverted cone of dry sand

Dry sand

62° 28°

Fig. 2.50. Gravel angle of repose ∼60°

Effective Permeability of Sand/Mud Fill in Screen/Drilled Hole Annulus (md)

Productivity Rate Ratio for Horizontal Hole Q Collapsed /Q Undamaged

500 250 100 50 10

0.96 0.90 0.76 0.61 0.23

Drill hole radius (rw) = 0.33 ft, Screen radius (rs) = 0.250 ft, Formation permeability (Ke) = 1,000 md, Reservoir radius (re) = 2,106 ft, Completion zone length (L) = 1,000 ft Table 2.8. Effect of a wellbore collapse around a screen in a horizontal completion

Wash pipe

Crossover packer

80° Screen

80°

After settling Fig. 2.51. Packing sequence with brine in high-angle well with high rate and large diameter washpipe 35

Modern Sandface Completion Practices

Thief zone Qt

Flow in Qi

Screen Fluid loss

1

P4

P3

P2 P1

2

3

4

5

6

Return flow, Qr

P5

1

2

3

Windows Thief zone

4

5

6

Perforation 1,500 ft

Fig. 2.52. 1,500 ft horizontal, gravel-pack model

Fig. 2.53. Results from 1,500-ft horizontal gravel-pack model: alpha wave propagating in model

turely stall. Increasing the diameter ratio to 0.75 and maintaining a return flow superficial velocity of 1 ft/sec (the ratio of the flow rate to the cross-sectional area of the annulus) promotes the stable alpha-beta wave packing sequence (Fig. 2.52).43 Later studies44 in a 7 in. OD by 25-ft long (7.62 m) scaled gravel-pack simulator have confirmed the findings portrayed in Figures 2.49 and 2.51. However, because the model was short, there was concern that horizontal gravel-pack tests would not be representative for actual conditions since tests could be dominated by end effects. Consequently, a longer field-scale model was designed and constructed. The model consisted of 1,500 ft (457.2 m) of 4-1/2 in. casing equipped with a 2-1/16 in. screen and is illustrated in Figure 2.52. Using footlong pipe filled with resin-coated gravel simulated fluid loss. The difference in the flow into the model and the returns through the wash pipe was the fluid loss to the formation. The model was equipped with high-strength plastic windows that allowed the visualization of the gravel packing process as it progressed down the model. Figure 2.53 shows the alpha wave traversing a window and Figure 2.5445 36

perhaps illustrates more clearly the alpha beta wave principle. A typical plot of the location of the alpha and beta waves as a function of time for a horizontal gravel pack is illustrated in Figure 2.55 and demonstrates that the entire 1,500-ft (457.2 m) model was packed with gravel. Provided that the design of the gravel pack is dimensionally correct and a superficial velocity of 1.0 ft/sec (30.48 cm/sec) is maintained, gravel packing a long horizontal gravel pack can be performed with routine procedures. However, for open-hole completions, a clean, stable wellbore is an additional requirement for a quality gravel pack to avoid contamination with formation material. Displacing the hole to brine prior to running the screen and gravel packing the well is preferred. Typical installation method – The following steps are performed in a typical open-hole, horizontal gravel pack:46 1. Drill open hole with formationcompatible fluid designed to be nondamaging to the payzone and establish a nearly impermeable filter cake that allows fluid returns to almost equal the pumping rate. (Low leak-off rate must be established and maintained to stabilize the hole and maintain a high

enough fluid velocity to push gravel dunes to the toe of the screen and finish packing the annulus.) 2. Circulate the hole clean and displace open hole with solids-free DIF. 3. Run in hole with bottom gravelpack assembly. (Figure 2.56 illustrates a simplified hook-up). 4. Flush-joint wash pipe is run in the screen assembly till it engages to the receptacle of the isolation plug. 5. The retrievable packer, closing sleeve with upper and lower extensions threaded to the gravel pack service tool is picked up and made up to the wash pipe as well as screens. 6. The entire packer assembly is run in the well on drill pipe until the packer reaches setting depth inside the liner and screens are in open hole. 7. After reaching target depth, perform a circulation test to make sure the open-hole is in stable condition, and the tool is clear to pump through it. This is a critical step in the success of the overall completion. If there were problems circulating at this point, it would be best to attempt to retrieve the downhole screen assembly. 8. Set the gravel-pack packer. 9. Test the packer by pressuring the annulus, then apply an upward pull and slack off. 10. Mark positions and pump the gravel slurry at a concentration of no more than 1.5 ppg. Care should be taken to stay below frac pressure. (The slurry should form a dune of sand beginning at the heel of the well and progress to the toe of the well until the end of the screen is reached. The returning fluid enters through the telltale screen into the wash pipe and flows back to the surface via the crossover tool from the annulus side.) 11. Continue the process until the beta wave is fully formed and screenout occurs. 12. Reverse out the slurry in the workstring. 13. Acidize screens with wash tool or foamed acid using coiled tubing. The above horizontal, gravel-packing method can be done by using the BJ HST System or equivalent. It allows the washdown, gravel pack and stimulation of a horizontal well in a single trip that has the benefit of reducing the potential for fluid loss to the formation. The various positions of this type service tool are shown in Figure 2.57.

Chapter Two Open-Hole Sandface Completions

Field result – Several hundred horizontal wells around the world have now been completed with gravel packs. The vast majority being open-hole installations. Typical gravel mix ratios pumped have been about 1 ppa (pound per gallon added); however, pack times have been reasonably short except for large diameter holes. Typical gravel pack times are in the 4 to 6 hour range. Wells that have been gravel packed many times do not experience the productivity declines observed with stand-alone screens provided that the completion process described above is followed. Summary – Achieving a successful horizontal gravel pack requires: • Washpipe screen OD-ID ratio of at least 0.75 • Running the washpipe to the end of the screen • Maintaining a superficial velocity of at least 1.0 ft/sec (30.48 cm/sec) based on return flow • Ensuring that the formation is not fractured • Pumping at gravel concentrations that are typically 1.0 lb/gal (119.8 kg/cu m) Alternate Path Screen Options Alternate Path Technology. This technology (developed by Mobil Oil) (also see the “Frac-Pack Methods/Applications” section of Chapter Three) combined with Schlumberger AllPAC screens, is an advanced gravel placement technique, which ensures 100% annular pack even in the most adverse hole conditions. The technique utilizes viscous fluids with high gravel concentrations (4–8 ppa) and involves the use of shunt tubes attached to the screen 2,000 1,800 Dune location, ft

Gravel-pack paker

Gravel-pack extension

Pump rate - 1.5 bpm mix ratio - 0.75 ppga

1,600

Fig. 2.54. Alpha-beta wave principle

End of model

1,400 1,200 1,000 800

Blank pipe

Thief zone

600

Alpha wave (velocity 9.9 fpm)

400 200 0 0

Beta wave (velocity 33.5 fpm)

1 2 Elapse time, hr

Production screen

Seal bore

Bull plug

3

Fig. 2.55. Results from 1,500-ft horizontal gravel-pack model; gravel dune location vs. elapsed time

Fig. 2.56. Typical horizontal open-hole hookup 37

Modern Sandface Completion Practices

can be gravel packed and will especially address the issue of fluid loss during gravel packing long horizontal intervals.

Fig. 2.57. BJ HST System horizontal, gravel-packing method

AllPAC Pipe OD 1 in.

Screen shunt ring

screen joint. Each transport tube, which runs the length of the screen and connections joint-to-joint, feeds one or more 1.0-in. x 0.50-in. docking shunt tubes. The docking tubes have nozzles sized at either 1/4 in. or 3/8 in., depending on the application requirements. Horizontal AllPAC screens also include an outer shroud. The shroud not only protects the gravel-pack screen’s wire wrapping and shunts during run in, but it also centralizes the assembly, making the use of open-hole centralizers redundant. This type screen is normally applied in horizontal or highly deviated wells with intervals more than 250 ft (76.2 m). In cases where synthetic oil-based DIFs are used, low flow initiation pressures typically observed with these fluids can result in cake liftoff with slight underbalances. These underbalances may occur during tool manipulations, causing high leak-off and jeopardizing the completion of the gravel packing operation. The association of low liftoff pressures and low yield stresses with oil based filter cakes as observed in field applications indicates these cakes are prone to erosion. Field experience shows that gravel packing open-hole horizontal wells with long shale sections can be problematic. Because the shunt technique is independent of the state of the filter cake, it allows the use of breakers in the carrier fluid to gravel pack and simultaneously to aid in cleanup of the filter cake.47 Alternate-Path screens have been successfully run in several horizontal wells (Fig. 2.60) offshore Trinidad, Venezuela and several other worldwide locations.48,49 This technology may increase the length of formations that 93

Screen OD

0.5 in.

Fishing OD Joint connector OD

Fig. 2.58. AllPAC screen cross section

(Figs. 2.58 and 2.59), which allow bypass of annular bridges that may form as a result of high leak-off. Gravel packing with shunt tubes does not rely on the existence of a tight filter cake, as is required in conventional horizontal, open-hole gravel packing. The AllPAC screen is used in gravelpacked completions with Alternate Path technology. The screen design features one or more 1.0 in. x 0.50 in. shunt tubes that are attached either concentrically or eccentrically to the screen joint with 1/4 in. exit nozzles at 6.0 ft (1.83 m) intervals on each shunt tube. Gravel packing rate can be up to 2.0 bpm per shunt tube, depending on the screen type, blank pipe length, and type of gravel-pack fluid. The horizontal AllPAC screen design features one or more 1.50-in. x 0.75-in. tubes attached eccentrically to the 38

Concentric Annular Packing Service (CAPS). Halliburton has introduced CAPS, an alternate-path screen system. It too provides multiple paths so that gravel-pack slurry can bypass any premature annulus bridges that formed during gravel placement, ensuring a complete annular pack. Annular clearance is particularly important in the design of the system. For normal vertical open-hole wells, the normal annular clearance is typically 1.5 to 2 in. (3.81 to 5.08 cm). Figure 2.61 illustrates the possible bridging problem in an open hole and how it can be bypassed with CAPS to obtain a complete pack.

Open-Hole Frac Packing Frac packing has been a popular sandcontrol technique since the early 1990s and provides highly reliable completions aimed at enhancing the productivity of gravel-packed wells. The technique consists of incorporating a ‘‘tip-screenout’’50 hydraulic fracturing treatment (see “Frac-Pack Methods/ Applications” section of Chapter Three) as part of the gravel-packing procedure, thus stimulating the well. The tipscreenout method provides a high contrast between fracture permeability and formation permeability and is essential to ensure that fracture width and proppant concentrations are adequate to efficiently connect the reservoir to the wellbore. Since the beginning of its increased attractiveness, almost all frac-pack treatments have been performed in cased holes. This stimulation technique, including frac fluids and proppants (sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment), are discussed thoroughly in Chapter Three as noted. In high-performance wells, perforations are the dominant restriction to flow. In these high-transmissivity wells requiring sand control, an open-hole completion is preferred because perforations, and thus flow restrictions, are eliminated. As mentioned in Chapter One, poorly consolidated, usually moderateto high-permeability sandstone, reservoirs are susceptible to sand production.

Chapter Two Open-Hole Sandface Completions

• Laminated sand/shale sequences • Poor productivity expected after a gravel-pack installation. Therefore, an alternative approach to gravel packing high-performance wells is open-hole frac packing, which combines the benefits of an open hole and fracturing and eliminates perforations, as well as provides a highly conductive flow path that bypasses near-wellbore damage. However, one problem encountered in frac packing or gravel packing long intervals is annular bridging that results in incomplete packing of the sections below a sand bridge.

Transport tube

Pipe size Screen OD

Special Products and Tools

Cover OD

The Alternate Path screen option using Schlumberger AllFRAC Screens (described in the previous section of this Chapter) has proved successful in bypassing bridges and yields higher productivity through complete packing of long intervals. This technique also has been proposed for frac packing horizontal wells53 as well as gravel packing open-holes above fracturing pressure without pads.54 In addition, unlike a conventional frac-pack treatment, this approach does not use pads and is intended to simply bypass the filtercake damage. By employing larger shunts than on the Alternate Path screens used for conventional gravel packing, increased pump rates can be applied to perform frac-pack operations. Fractures propagate throughout the interval, not just

Transport tubes

Packing tubes with nozzles

Pipe size Screen OD Cover OD Fig. 2.59. Horizontal AllPAC screen cross sections

Transport tube

QUANTUM gravel-pack packer

Nozzles

Screens Shroud

93

Candidate Selection Proper candidate selection, treatment design and execution can increase production and alleviate fines migration by reducing pressure losses and flow velocities. Figure 2.63 illustrates an ideal fracture system in a high-performance well that can accomplish the treatment design objectives. Good candidates for open-hole frac packing include wells with the following characteristics: • High permeability, easily damaged reservoirs • Near-wellbore damage • Low permeability reservoirs and formations with fines migration problems • Formation sanding potential • Productive layers not connected to the wellbore

Packing tubes with nozzles

93

Sometimes, traditional techniques (described earlier in this handbook) to control the sand influx typically result in decreased well productivity. To possibly solve this decreased production problem, operators have discovered that performing a fracturing treatment combined with a sand control gravel pack can enhance well productivity and mitigates the tendency of a stand-alone screen or gravel pack to decrease production. The success of this frac-pack technique is due in part to the larger proppant sizes used in fracturing than those sizes commonly used in gravel packing (Fig. 2.62). Non-Darcy effects are primarily due to the acceleration and deceleration of the fluid as it travels through the tortuous flow path of porous media (in this instance, the propped fracture). The oil, water or gas in the fracture must continually change direction, accelerating through pore throats and decelerating in the larger pore spaces.51 Excessive velocities in the created fractures of high-transmissivity wells may make for significant non-Darcy effects and some resulting skin.52 Frac packing an open-hole of a highly permeable, unconsolidated formation combines fracturing and gravel packing as a single operation with a screen or sand exclusion device (discussed previously in this Chapter). The fracture provides stimulation and enhances the effectiveness of the gravel-pack operation in eliminating sand production.

Packing tube

Oil-bearing layer

AllPAC screens

Fig. 2.60. QUANTUM packer and AllPAC screens used in a horizontal, open-hole gravel pack 39

Modern Sandface Completion Practices

casing. Two large shunt tubes extending through the packer bypassed the reactive shale section. A protective shroud covered the AllFRAC screens and shunt tubes to prevent mechanical damage from hole instability or assembly rotation to reach total depth. The shroud also centralized the screens for a more complete annular pack. Case History

Fig. 2.61. Conventional screen with gravel bridge and incomplete pack (top). CAPS screen bypasses bridge (middle). Completed open-hole gravel pack via CAPS (bottom).

Fig. 2.62. High concentrations of large, spherical proppant offset embedment and non-Darcy flow effects

Fig. 2.63. Ideal fracture system in a high productivity well

above a premature bridge, and proppant is placed along the entire interval. In addition, the fractures as well as the screen/open-hole annulus can be tightly packed for maximum conductivity. (Also see Figure 2.61, which illustrates a similar proceedure using the CAPS horizontal, open-hole, gravel-pack technique.) A typical open-hole, frac-pack tool assembly is illustrated in Figure 2.64. The Baker Model CS-300 crossover tool 40

in this string is designed to maintain hydrostatic overbalance across the formation during all phases of the openhole, gravel-pack completion. If the hydrostatic pressure is allowed to decrease to the static bottomhole pressure, the risk of filter cake removal or hole sloughing increases dramatically. Specialized components in the assembly permit hydrostatic, overbalance-pressure transmission to the borehole at all phases of completion. The system is designed to provide positive tool locating and elimination of surge and swab pressures. Another completion tool string that was used in the open-hole, frac-pack case history, described below, is illustrated in Figure 2.65.55 Run as part of the completion assembly, a Multi-Zone (MZ) isolation packer was located below the QUANTUM gravel-pack packer inside 7-in.

A 70° deviated offshore well in the Java Sea had a 110 ft (33.53 m) section to frac pack. Packing efficiency was a concern based on previous completion failures where incomplete packing of the deviated wellbore was suspected. To address these two considerations, a combination of screen with shunt tubes and an MZ packer was selected for the job. The MZ packer has cup-type elements that prevent flow across it, which is illustrated in Figure 2.65. Frac-pack execution went smoothly despite concerns about the high-angle wellbore, multiple competing fractures and excessive fluid leak-off through 225 ft (68.58 m) of open-hole interval with 47 ft (14.33 m) of high-permeability net sand. Treatment simulation indicated a final fracture half-length of 18 ft (5.49m) with a propped fracture width of 1.0 in. Initial production of 2,000 bpd total fluid with 500 bopd from an electrical submersible pump exceeded expectations. Post-treatment skin was not measured by pressurebuildup analysis, but a sensor on the electrical submersible pump monitored downhole flowing pressures, which indicated a small pressure drop at the completion sandface.

Chapter Two Open-Hole Sandface Completions

QUANTUM service tool

Seting tool

Washpipe

QUANTUM gravel-pack packer

SC-R type packer

MZ isolation packer with bypass shunts AllFRAC blank pipe without nozzles

Shunt tubes

Reactive shale

AllFRAC screens with nozzles

GP sliding sleeve CS crossover port Seal bore sub

Drilling motor Drilling bit

Fig. 2.65. Offshore Java Sea completion

FASTool

S-1 shifting tool

Indicating coupling

SMART collet

Fig. 2.64. Open-hole, frac-pack tool assembly with Model CS-300 crossover tool

References 1. Davidson, E. and Stewart, S., “Open Hole Completions: Drilling Fluid Selection,” SPE/IADC 39284, Middle East Drilling Technology Conference, Bahrain, November 23-25, 1997. 2. Ezzat, A., “Completion Fluids Design Criteria and Current Technology Weaknesses,” SPE 19434, Formation Damage Control Symposium, Lafayette, Louisiana, February 22-23, 1990. 3. Hodge, R., Augustine, B., Burton, R., and Sanders, W., “Evaluation and Selection of Drill-In Fluid Candidates to Minimize Formation Damage,” SPE Drilling and Completion, September 1997, 174. 4. Saasen, A., Jordal, O., Durkhead, D., Berg, P., Løklingholm, G., Pedersen, E., Turner, J., and Harris, M., “Drilling HT/HP Wells Using a Cesium Formate Based Drilling Fluid,” IADC/SPE 74541, Drilling Conference in Dallas, Texas, February 26-28, 2002. 5. Scbba, F., Foams and Biliquid Foams-Aphrons, John Wiley and Sons, New York, 1987, 46-61. 6. Brookey, T., “’Micro-Bubbles’: New Aphron Drill-in Fluid Technique Reduces Formation Damage in Horizontal Wells, SPE 39589, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 13-15, 1998. 7. Dobson, J. and Kayga, D., “Soluble Bridging Particle Drilling System Generates Successful Completions in Unconsolidated Sand Reservoirs,” 5th International Conference on Horizontal Well Technology, Amsterdam, The Netherlands, July 14-16, 1993.

8. Mondshine, T., "Tests Show Potassium-Mud Versatility," Oil & Gas Journal, April 1974. 9. Ryan, D., Kellingray, D., and Lockyear, C., "Improved Cement Placement on North Sea Wells Using a Cement Placement Simulator," SPE 24977 presented at the European Petroleum Conference, Cannes, France, November 16-18, 1992. 10. McLean, R., Manry, C., and Whitaker, W., "Displacement Mechanics in Primary Cementing," Journal of Petroleum Technology, February 1967. 11. Ibid. 12. Rogers, E., “Sand Control in Oil and Gas Wells,” Oil & Gas Journal, November 1, 8, 15 and 22, 1971, 54-68 13. Coberly, C., “Selection of Screen Openings for Unconsolidated Sands,” Drilling & Production Practices, API, 1937, 189-201. 14. Schwartz, D., “Successful Sand Control Design for High Rate Oil and Water Wells,” Journal of Petroleum Technology, September 1969, 1193-98. 15. Tiffin, D., King, G., Larese, and Britt, L., “New Criteria for Gravel and Screen Selection for Sand Control,” SPE 39437. Formation Damage Control Symposium, Lafayette, Louisiana, February 18-19, 1998. 16. Kaiser, T., Wilson, S., and Venning, L., “Inflow Analysis and Optimization of Slotted Liners,” SPE Drilling and Completion, December 2002, 201-202. 17. Ibid 18. Moen, T., Gunneroed, T., and Kvernstuen, O., “A New Sand Screen Concept: No Longer the Weakest Link of the Completion String,” SPE 68937, European Formation Damage Conference, The Hague, May 21-22, 2001. 19. Markestad, P., Christie, O., and Espedal, A., “Selection of Screen Slot Width to Prevent Plugging and Sand Production,” SPE 31087, Formation Damage Control Symposium, Lafayette, Louisiana, February 14-15, 1996. 20. Gillespie, G., Deem, C., and Malbrel, C., “Screen Selection for Sand Control Based on Laboratory Tests,” SPE 64398, Asia Pacific Oil and Gas Conference, Brisbane, Australia, October 16-18, 2000. 21. Metcalfe, P. and Whitelaw, C., “The Development of the First Expandable Sand Screen,” OTC 11032, Offshore Technology Conference, Houston, Texas, May 3-6, 1999. 22. van Buren, M., van den Broek, L., and Whitelaw, C., “Trial of an Expandable Sand Screen to Replace Internal Gravel Packing,” SPE/IADC 57565, Middle East Drilling Technology Conference, Abu Dhabi, UAE, November 8-10, 1999. 23. Saucier, R., “Considerations in Gravel Pack Design,” SPE 4030, Journal of Petroleum Technology, February 1974, 205-212 24. “Recommended Practices for Testing Sand Used in Gravel Packing Operations,” API Recommended Practices 58, 2nd Ed., December 1986. 25. Skopec, R., “Proper Coring and Wellsite Core Handling Procedures: The First Step Toward Reliable Core Analysis,” Journal of Petroleum Technology, April 1994, 280.

41

Modern Sandface Completion Practices

26. Gurley, D., Copeland, C., and Hendrick Jr., J., “Design, Plan, and Execution of Gravel-Pack Operations for Maximum Productivity,” Journal of Petroleum Technology, October 1977, 1259-1266. 27. “Core Analysis,” API Recommended Practices 40, 2nd Ed., February 1998. 28. Saucier, R., “Considerations in Gravel Pack Design,” SPE 4030, Journal of Petroleum Technology, February 1974, 205-212. 29. Ibid. 30. Cocales, B., “Optimizing Materials for Better Gravel Packs,” World Oil, December 1992, 73-77. 31. “Recommended Practices for Testing Sand Used in Gravel Packing Operations,” API Recommended Practice 58, 2nd Ed., December 1986. 32. Sparlin, D., “Sand and Gravel – A Study of Their Permeabilities,” SPE 4772, “Symposium on Formation Damage Control, New Orleans, Louisiana, February 7-8,1974. 33. Gurley, D., Copeland, C., and Hendrick Jr., J., “Design, Plan, and Execution of Gravel-Pack Operations for Maximum Productivity,” Journal of Petroleum Technology, October 1977, 1259-1266. 34. Cocales, B., “Optimizing Materials for Better Gravel Packs,” World Oil, December 1992, 73-77. 35. Diallo, M., Jenkins-Smith, N., and Bunge, A., “Dissolution Rates for Quartz, Aluminum-Bearing Minerals, and Their Mixtures in Sodium and Potassium Hydroxide,” SPE 16276, International Symposium on Oilfield Chemistry, San Antonio, Texas, February 4-5, 1987 36. Suman, G. Jr., Ellis, R., and Snyder, R., Sand Control Handbook, Gulf Publishing Company, Houston, Texas, 1991. 37. Ibid. 38. Foster, J., Grigsby, T., and LaFontaine, J., “The Evolution of Horizontal Completion Techniques for the Gulf of Mexico. Where Have We Been and Where Are We Going!” SPE 53926, Latin American and Caribbean Petroleum Engineering Conference, Caracas, Venezuela, April 21-23,1999. 39. Karcher, B., Giger, F., and Combe, J., Some Practical Formulas to Predict Horizontal Well Behavior,” SPE15430, Annual Technical Conference, New Orleans, Louisiana, October 5-8, 1986. 40. Benavides, S. and McKee, J., Using Horizontal Gravel Packing Technology to Optimize Well Productivity and Field Economics: Case History, Uracoa Field, Venezuela,” SPE 65468, International Conference on Horizontal Well Technology, Calgary, Alberta, Canada, November 6-8, 2000. 41. Forrest, J., “Horizontal Gravel Packing Studies in a Full Scale Model Wellbore,” SPE 20681, Annual Technical Conference, New Orleans, Louisiana, September 23-26, 1990. 42. Penberthy, W. and Echols, E., “Gravel Placement in Wells,” SPE 22793, Annual Technical Conference, Dallas, Texas, October 6-9, 1991. 43. Ibid. 44. Penberthy, W., Bickham, K., and Nguyen, H., “Gravel Placement in Horizontal Wells,” SPE Drilling and Completion, June 1997, 85-92. 45. Ibid. 42

46. Walvekar, S. and Ross, C., “Production Enhancement Through Horizontal Gravel Pack,” SPE 73777, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 20-21, 2003. 47. Price-Smith, C., Parlar, M., Kelkar, S. Brady, M., Hoxha, B., Tibbles, R., Green, T., and Foxenberg. B. “Laboratory Development of a Novel, Synthetic OilBased Reservoir Drilling and Gravel Pack Fluid System That Allows Simultaneous Gravel Packing and Cake Cleanup in Open-Hole Completions,” SPE 64399, Asia Pacific Oil and Gas Conference, Brisbane, Australia, October 16-18, 2000. 48. Foster, J., Grigsby, T., and LaFonntaine, J., “The Evolution of Horizontal Completion Techniques for the Gulf of Mexico. Where Have We Been and Where Are We Going!” SPE 53926, Latin American and Caribbean Petroleum Engineering Conference, Caracas, Venezuela, April 21-23,1999. 49. Romero, J., Pizzarelli, S. and Mancini, J., “Simultaneous Stimulations and/or Packing in Multiple Zones. Effective Solutions,” SPE 77437, Annual Technical Conference, San Antonio, Texas, September 29October 2, 2002. 50. Smith, M. and Haga, J., “Tip Screenout Fracturing: A Technique for Soft Unstable Formations,” SPEPE, May 1987, 95 Transcript, AIME, 203. 51. Vincent, M., Pearson, M. and Kullman, J., “NonDarcy and Multiphase Flow in Propped Fractures: Case Studies Illustrate the Dramatic Effect on Well Productivity,” SPE 54630, Western Regional Meeting, Anchorage, Alaska, May 26-28, 1999. 52. Ayoub, J., Barree, R. and Chu, W., “Evaluation of Frac and Pack Completions and Future Outlook,” SPE Production & Facilities, Vol. 15, No. 3, August 2000, 137-143. 53. Jones, L., “Frac-packing Horizontal Wells Allows Ultra-High Rates from Mediocre Formations,” Petroleum Engineer International, July 1999, 37-40. 54. Parlar, M., Bennett, C., Gilchrist, J., Elliott, F., PriceSmith, C., Brady, M., Tibbles, R., Kelkar, S. and Foxengerg, B., “Emerging Techniques in Gravel Packing Open-Hole Horizontal Completions in High Performance Wells,” SPE 64412, Asia Pacific Oil and Gas Conference, Brisbane, Australia, October 16-18, 2000. 55. Saldungaray, P., Troncoso, J., Sofyan, M., Santoso, B., Parlar, M., Price-Smith, C., Hurst, G. and Bailey, W., “Frac-Packing Open-hole Completions: An Industry Milestone,” SPE 73757, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 20-21, 2002.

CHAPTER THREE

Cased-Hole Sandface Completions Completion Fluids • Debris Removal and Mysteries • Fluid Filtration • Perforating Stand-Alone Screens • Gravel Packing • Frac Packing • Gravel Packing Method Selection

areful planning, well preparation and completion execution are all required for the success of a cased-hole sandface completion. The omission of any of these steps may account for a completion that falls short of its objectives since many of the completion operations are interdependent. To achieve the completion goals of sand control, productivity and longevity, attention must be given to completion fluids, debris management, fluid filtration and perforating. Proper preparation of a well for stand-alone completions, gravel packing and frac packing can be the key to a successful completion. Cleanliness may be one of the most important considerations when preparing a well for a stand-alone completion, gravel pack or frac pack. Since all of these operations represent the installation of a downhole filter, any action that promotes plugging the filter (i.e., the screen, gravel pack sand or frac pack proppant) is detrimental to the success of the completion and well productivity. Many advances have been made in improving the cleanliness of these completion operations, particularly completion fluids. However, in spite of the fact that clean completion fluids are used, the lack of cleanliness in the casing, work string, lines, pits and other equipment is a source of potential formation damage and lost productivity.1,2 While cleaning the well and rig equipment can be expensive, it is not as expensive as lost productivity or having to rework the entire completion because proper cleaning was neglected in the beginning.

C

Completions Fluids It is useful to think of completion fluids as tools that aid in performing a downhole operation on, or in contact with, a producing formation, after the well has been drilled, cased and cemented. As

tools, these fluids are (1) introduced for a particular function, (2) removed after the job and (3) not intended to leave the wellbore and penetrate the formation. However, it is impossible to prevent some loss. The proper selection and use of fluids in completing and/or working-over a well can significantly affect both formation productivity and mechanical performance. Generally, a completion fluid is any fluid used to conduct downhole operations subsequent to drilling the wellbore. The completion fluid is important because of its role in well control and perforation clean-up or “washing.” A dirty or contaminated completion fluid can plug perforations with solids, hence creating a barrier for the proper and consistent placement of gravel during gravel pack operations. Additionally, fines from an improperly filtered fluid can mix with the gravelpack gravel, thereby reducing gravel pack permeability. A poor gravel pack can result in sand-control failures and/or low production rates. Mechanical plugging is the most important cause of formation permeability damage. Formation fines, added solids, cement or other debris suspended in the completion fluid, can cause plugging. For this reason, typical or even modified drilling mud with their high solids content should not be placed against a producing formation. Accordingly, every attempt must be made to use only clean, particle free, completion and workover fluids. A program of clean well site handling practices and proper completion fluid filtration is necessary to obtain the desired level of clarity. Since a density of approximately 8.6 ppg (1,030.5 Kg/m3) is as light as practical for conventional completion fluids, a wellbore that is overbalanced is a par-

ticular problem when working in a lowpressure or pressure-depleted formation. The potential for fluid loss can lead to difficulties with well control and/or obtaining clean perforations. Clean perforations are considered crucial to the completion process. Generally, perforating a formation with an overbalanced, solids-laden fluid (mud) yields the least efficient perforation. Perforating a formation with an overbalanced, solids-free, non-damaging fluid (brine) yields a more efficient perforation. Perforating with an underbalance into the wellbore yields a still more efficient perforation, with the least formation damage.3 Use of Completion Fluids Completion fluids are required downhole to conduct operations such as: • Well killing and well control • Perforating • Perforation washing • Gravel packing • Under reaming • Sand fill cleanout • Spotting or displacing treating fluids • Drilling or milling • Leaving behind a packer. They are used to enhance the safety and efficiency of each operation. Solids-free brines are selected for use whenever the producing formation is exposed during completion and workover operations. They serve primarily to control downhole formation pressures, while reducing the risk of formation damage resulting from invasion of either solids or liquids. These brines accomplish this task by utilizing highly water-soluble salts, which do not react with the formation minerals or water to obstruct the effective permeability. Otherwise, formation permeability can be plugged by precipitates formed when incompatible waters are 43

Modern Sandface Completion Practices

Chloride Salts

Bromide Salts

NaCl KCI NH4CI CaCI2

NaBr CaBr2 ZnBr2

Formate Salts NaHCO2 KHCO2 CsHCO2

Table 3.1. Water-soluble salts

Brine Type

Density Range (ppg)

Typical Dencity (ppg)

NaCl KCI NH4CI NaBr NaCl/NaBr NaHCO2 KHCO2 CsHCO2 KHCO2/CsHCO2 NaHCO2/KHCO2 CaCI2 CaBr2 CaCI2/CaBr2 ZnBr2 ZnBr2/CaBr2 ZnBr2/CaBr2/CaCl2

8.4 - 10.0 8.4 - 9.7 8.4 - 8.9 8.4 - 12.7 8.4 - 12.5 8.4 - 11.1 8.4 - 13.3 13.0 - 20.0 13.0 - 20.0 8.4 - 13.1 8.4 - 11.8 8.4 - 15.3 8.4 - 15.1 12.0 - 21.0 12.0 - 19.2 12.0 - 19.1

8.5 - 10.0 8.5 - 9.0 8.5 - 8.7 10.0 - 12.5 10.0 - 12.5 9.0 - 11.0 11.0 - 13.1 17.5 - 20.0 13.0 - 17.5 11.0 - 13.1 9.0 - 11.6 12.0 - 14.2 11.7 - 15.1 19.2 - 21.0 14.0 - 19.2 14.2 - 19.1

Table 3.2. Brine selection density range

intermingled.4 Most damage mechanisms, such as emulsifying or scaleforming potential, can be anticipated and avoided through proper testing and design. The primary water-soluble salts, which make up the commercially available, solids-free completion brines, are listed in Table 3.1. All of these salts are highly soluble and stable, and economical to use. (Consider the economic consequences of lost production due to formation damage caused by barite, bentonite or other drilling mud plugging solids.) These brines are generally safe to handle and can be easily disposed, with several notable exceptions. Operationally, they are adaptable to rig site procedures, and require only simple safety considerations and equipment during use. This provides the operator a fluid that (1) minimizes fluid loss by hydrostatic balance, (2) is compatible with the producing formation, and (3) offers ease of handling and performance at the rig site.

44

Selection Criteria Most operators will order brine based on three principal criteria. These are (1) density for proper well control, (2) compatibility with the formation rock matrix and fluids, and (3) true crystallization temperature (TCT) for maximum storage and optimum operating conditions. Density. The primary performance requirement for completion brine is to maintain hydrostatic pressure. The density specified must be sufficient to hold back the formation pressure and prevent influx of produced fluids. Typically, an overbalance of 200 psi to 300 psi over reservoir pressure is used to maintain well control. Table 3.2 displays brine density ranges for the common salt brine completion fluids at 60ºF (15.6ºC). Unlike drilling muds that depend on solids to maintain density, completion fluids must be blended in anticipation of a lower effective-fluid-density downhole due to increased temperature at depth. Completion brines exhibit a volumetric

response to temperature and pressure (i.e., they expand with increasing temperature and compress with increasing pressure). Under downhole conditions, the temperature effect (expansion) is more pronounced than the pressure effect (compression) on a completion fluid. The increase in volume results in a decrease in fluid density. This can cause well control problems due to reduced hydrostatic pressures. Formate brines were introduced as a completion fluid in the 1990s. Cabot Specialty Fluids reports that these fluids have all the advantages of more conventional solids-free brines, yet none of the disadvantages of the halide brines. The formate brines, which are shown in Table 3.2, consist of sodium (11.0 ppg), potassium (13.1 ppg) and cesium formates (20.0 ppg). Formate brines can be blended to achieve any density between 8.4 ppg and 20.0 ppg. Bromide brines can be used at similar, higher densities, but these have additional limitations, particularly regarding HSE (health, safety and environment), corrosivity, formation damage and polymer compatibility. Bromide brines above 14.3 ppg are normally considered impractical as a completion fluid because they are toxic, corrosive and incompatible with most oil field elastomers and polymers.5 The Dow Chemical Company, in connection with OSCA (now BJ Services), investigated the expansion/compression properties of completion fluids under typical oil field conditions and derived a mathematical model that calculates the surface density needed to achieve the required hydrostatic pressures. This model is being used worldwide to predict the effects of temperature and pressure on a column of completion fluid in a wellbore. Expansion and compression factors for various clear brine fluids are shown in Table 3.3.6 Note that expansion and compression effects on density are greater in the higher density ranges, and, when compared on a percent change, the effects are greater on sodium-based brines than on calcium-based brines. Many suppliers of solids-free brines have software to calculate the optimal surface density for a given bottomhole temperature (BHT) and desired hydrostatic pressure. The program accounts for the effects of both temperature and pressure, and with it considerably

Chapter Three Cased-Hole Sandface Completions

improved estimates of effective downhole pressures are achieved resulting in lower fluid losses and better clean up under production conditions. The program has been in field use for several years. The densities calculated by this method have been found to control formation pressures with less fluid loss to the formation than by correction algorithms previously used. The program can be used to perform four important functions: • Calculate a required surface density to achieve a specified bottomhole pressure • Calculate the downhole effects of a specified surface density completion fluid • Calculate surface temperature effects only on the fluid density • Calculate average density for the well. Formation damage. Formation damage is described as the reduction of permeability to a producing formation by any means at all. The most common causes of formation damage, when using completion brines, typically is either the plugging via solids invasion or possible incompatibility within the formation or hydrocarbons. Clay problems can be created by water-based completion fluids that are lost to the formation during the well completion or a workover. Whether these fluids cause clays to swell or to become mobilized, formation damage will result. Not all formations are sensitive to this problem, but it is most common in sandstones. The magnitude of clay problems is related to the: • Amount and type of water-based fluid and additives that enter the formation • Types and amounts of clays present • Condition and arrangement of the clays in their native state. Therefore, Baroid Drilling Fluids (now Halliburton Energy Services) suggests that completion fluid design should be based on a detailed study of reservoir characteristics at downhole conditions, and that fluid sensitivity studies should be conducted to ensure fluid/fluid and fluid/formation compatibility.7 Solids-free completion fluids have found widespread application because they are considered far less damaging to the productive zone than solids-laden fluids. Particulate matter can be filtered out of clear brine fluids down to a size

At 12,000 psi from 76°F to 345°F Brine System Density lb/gal NaCI CaCI2 NaBr CaBr2 ZnBr2/CaBr2/CaCl2 ZnBr2/CaBr2

9.49 11.45 12.48 14.30 16.01 19.27

At 198°F from 2,000 psi to 12,000 psi Brine System Density lb/gal NaCI CaCI2 NaBr CaBr2 ZnBr2/CaBr2/CaCl2 ZnBr2/CaBr2

9.49 11.45 12.48 14.30 16.01 19.27

Expandibility Coefficient α Vol/vol/°F x 10 4 2.54 2.39 2.67 2.33 2.27 2.54

A lb/gal/100°F 0.24 0.27 0.33 0.33 0.36 0.48

Compressibility Coefficient β Vol/vol/psi x 10 6

B lb/gal/1,000 psi

1.98 1.50 1.67 1.53 1.39 1.64

0.019 0.017 0.021 0.022 0.022 0.031

A = Density correction factor for temperature B = Density correction factor for pressure

Table 3.3. Expandability and compressibility of brine systems

of 2 microns to reduce formation damage caused by solids. The high salinity attainable with brine completion fluids helps assure that clay swelling and/or migration are also minimized. Since these solutions are also relatively nonreactive with most oilfield waters, their interaction with formation fluids is generally considered to be minimal. For these reasons, clear brines have been particularly useful in frac/gravel packing operations where the gravel carrying fluid may leak off into the formation during the transport of gravel into perforation tunnels or open-hole type operations. Clear brine fluids versus seawater. The use of seawater as a completion fluid should be avoided whenever possible. Seawater contains many contaminants such as carbonate, bicarbonate, and sulfate which all can precipitate within a producing formation. This precipitation reaction can produce insoluble solids in what is supposed to be solids-free brine especially if interacted with other types of completion brines or even some formation waters. While calcium carbonate generally precipitates at a higher pH and at higher temperatures, calcium sulfate precipitates under most conditions. Even if the calcium brine is prepared and filtered on the surface, a

positive carbonate-scaling tendency may occur downhole. Seawater also contains many types of microorganisms that cause a variety of problems. Common bacterial problems include slime formation or plugging solids. The worst of the bacteria are the sulfate-reducers, which generate H2S gas under downhole conditions and are usually the source for the formation of iron sulfide scale. Typically, all lowdensity brine systems (low total salt content) are susceptible to bacterial contamination. In order to minimize formation damage associated with seawater-based completion fluids: • Add a scale inhibitor • Treat with a biocide • Saturate the brine with the appropriate salt and filter fluid to 2 micron absolute • Dilute to working density (if possible, with fresh water), and then filter again. Crystallization temperature. The crystallization temperature of brines is defined as the temperature at which solid crystals will form in the solution. Another way to consider the crystallization temperature is the temperature below which a component of the brine exceeds its maximum solubility. Please 45

Modern Sandface Completion Practices

note, however, that there are various methods for determining this property of brines: • First crystal to appear (FCTA) • True crystallization temperature (TCT) • Last crystal to dissolve (LCTD). Figure 3.1 is a plot of the above temperature points for an example 19.2 ppg ZnBr2/CaBr2 brine. When salt is added to fresh water, the freezing point of the water is depressed. In dilute solutions, the freezing point depression is directly proportional to the amount of salt; that is, 10 lb (4.5 kg) of salt will lower the freezing point of a barrel of water by twice that of 5 lb (2.25 kg). As the solution becomes more concentrated, this simple relationship no longer holds true. At high salt concentrations, the maximum solubility becomes a more complex function of water temperature. When completion brine is cooled below its crystallization temperature, the least soluble component in the solution will crystallize. This solid can be ice, salt or salt hydrates, depending on the solubility

Temperature, °F

40 19.2 ppg ZnBr2/CaBr2 brine LCTD TCT 24°F 16.5°F

30 20 FCTA 15°F

10

Cooling

Heating

0 0

10

20 30 Time, min

40

50

Fig. 3.1. Crystallization curve for one example brine illustrates three possible “crystallization points.” (data from The Dow Chemical Company)

limits of that salt in water. Operations utilizing completion fluids must account for the crystallization temperature by recognizing the coolest temperature to which the bulk of the brine will be exposed for any significant period of time. For example, a completion fluid standing static in the riser of a well drilled in 2,000 ft (609.6 m) of water may be exposed to very low temperatures near the mudline. This should be taken into account to avoid forming a plug in the riser due to crystallized fluid, even though the surface conditions may be sunny and warm. Since the cost of brine increases with decreasing crystallization temperature, it is worthwhile to select the brine with the maximum crystallization temperature possible for the operating conditions. Except for single salt brines, adjusting the concentration and composition of salts in solution can cause a variance of the crystallization temperature of a brine. For example, 13.0 ppg calcium chloride-calcium bromide brine can be formulated to have crystallization temperatures from less than -35ºF (-37.3ºC) to 70ºF (21.1ºC) by adjusting the ratio of calcium bromide to calcium chloride. Surfactants. Surfactants are often added to completion fluids to minimize potential formation damage problems associated with water blocking, oil wetting and emulsions. Surfactants are surface active agents that reduce the surface tension and interfacial tension of fluids and control the wettability of the matrix to help prevent these problems. They must not be used indiscriminately, however, as they can cause more damage than they are supposed to prevent. Many different types of surfactants are used in the oil field for such purposes as to disperse solids, emulsify

Cationic Surfactants

Anionic Surfactants

Oil wets sands Water wets carbonates Emulsifies water in oil Breaks oil-in-water emulsions Biocculate clays in water

Water wet sands Oil wets carbonates Emulsifies oil in water Breaks oil-in-water emulsions Floculates clays in water

Disperses clays in oil

Disperses clays in water

Note: The function of surfactants also depends on pH, other chemicals present, formation properties, and crude oil properties. Table 3.4. Functional tendencies of surfactants 46

water in oil (invert emulsion mud), separate oil and water, etc. The four general types of surfactants used in the oil field are (1) Cationic, (2) Anionic, (3) Nonionic, and (4) Amphoteric. There are many different chemicals and brand names for each of these types of surfactants, but we can generalize the properties of the first two types, as shown in Table 3.4, and as follows: • Anionic surfactants tend to water-wet sand • Cationic surfactants tend to oil-wet sand • Anionic surfactants tend to oil-wet carbonates • Cationic surfactants tend to water-wet carbonates • Anionic surfactants tend to emulsify oil-in-water and break water-in-oil emulsions • Cationic surfactants tend to emulsify water-in-oil and break oil-in-water emulsions • Anionic surfactants tend to disperse clays in water • Cationic surfactants tend to flocculate clays in water • Anionic and cationic surfactants are not compatible with each other. We cannot generalize on the other two types of surfactants, because they have a wide variety of properties. These surfactants have many useful properties, but they should be tested if there is any question about what effect they will have. The wrong type of surfactant, or the wrong concentration of surfactant, may cause formation damage. Service companies often use surfactants which are selected by experience in a given formation or area. Normally these have been checked thoroughly and will aid in preventing formation damage; but when a new formation is being treated or completed, samples of the formation crude oil, brine, and core should be tested to be certain that these surfactants are compatible. The concentrations of surfactants in fluids are normally very small; usually only 1% or 2% is adequate, and often much less than this will do a job. It is dangerous to add too much surfactant as this may cause the opposite effect of what is desired. Always be certain that tests have been performed to indicate what type and concentration of surfactant are required for a particular effect. Do not change or modify this recommendation without good reason.

Chapter Three Cased-Hole Sandface Completions

Fluid Loss Control Fluid loss should be controlled or managed but not necessarily stopped. The amount of fluid loss that can be tolerated during the completion is site specific. Ideally, nothing would be done to stop fluid loss, but when expensive high density brine is being lost, completion fluid reserves are low or the loss rate makes operations unsafe, some type of loss control system must be employed. Also, the formation damage potential of continued fluid loss (even though the fluid is filtered) should be considered in light of the potential damage from employing a fluid loss control system. The normal methods for controlling fluid loss are: • Reduced hydrostatic pressure • Viscous polymer gels • Graded solid particles • Mechanical means. Reduced hydrostatic pressure. Fluid loss is a direct result of differential pressure into the formation due to the overbalanced condition created by the hydrostatic pressure of the completion fluid. A reduction in the rate of fluid loss can be accomplished by simply lowering the density of the completion fluid. Some operators have even allowed the hydrostatic pressure exerted by the completion fluid to equalize with the formation pressure by letting the completion fluid seek its own level in the wellbore. Working with a low fluid level in the well would only be acceptable in wells that are not capable of flowing to surface. Regulatory authorities and/or operator imposed safety regulations may dictate the minimum hydrostatic over-

Q=

kh∆P  r   24 × 141.2 × Bo × µ × ln e  − 0.75 + S    rw  

Where: Q = loss rate (bph) k = permeability (md) ∆P = pressure differential (psi) µ = viscosity of completion fluid (cp) S = skin h = net sand thickness (ft) Bo = formation vol. factor of comp. fluid ln(re /rw) = Assume = 8 This equation indicates that the flow of fluids from the wellbore for a given differential pressure is controlled by the formation’s permeability, the interval thickness, the viscosity of the flowing fluid, the compressibility of the reservoir fluids, as well as the degree of formation damage surrounding the wellbore. Figure 3.2 illustrates the level of fluid loss rates associated with a 1 cp fluid leaking off to formations of different permeabilities with overbalance pressures ranging from 0 psi to 500 psi. This plot makes it clear that while a reduction of overbalance pressure may successfully control fluid loss for moderate to low permeability formations, for high permeability formations excessive loss rates may still occur even for overbalance pressures down to 100 psi to 200 psi. Overbalance pressures much below this level will impose additional well control concerns on the operation. Viscous polymer gels. The viscosity of the fluid that is lost to the formation directly affects fluid loss rate. This relationship between loss rate and viscosity has led to the common use of viscous polymer gels to control fluid loss. Viscous gels are very effective at controlling losses provided the permeability of the formation and the overbalance are not too great. In general, it becomes impractical to control fluid loss if the wellbore pressure exceeds the reservoir

160 140 120 Loss rate, bph

balance allowed which could limit the effectiveness of this technique. The rate of fluid loss associated with a given overbalance pressure is controlled by several factors. To estimate the fluid loss rate for a given differential pressure, Darcy’s Law for radial flow can be examined.

100 80 60

Interval length = 25 ft Fluid viscosity = 1 cp Skin = 5 500 md 250 md 100 md 50 md

40 20 0 0 50 100 150 200 250 300 350 400 450 500 Differential pressure, psi

Fig. 3.2. Effect of differential pressure on fluid loss rate for 1 cp fluid 90 80 lb/1,000 gal HEC 30 ft interval length Desired fluid loss rate = 4 bph

80 70 Pill volume, bbl

Often two or more surfactants are required to have the desired total effect. For instance, some completion or workover fluids (acid treatment, heavier weight completion fluids, etc.) will contain both a corrosion inhibitor and surfactant. The corrosion inhibitors are commonly cationic in nature. If an anionic surface tension reducing surfactant is added to these cationic corrosion inhibitors, it will interfere with the corrosion inhibitor and neither additive will function properly. Normally, a nonionic surfactant must be selected when cationic corrosion inhibitors are required.8,9

60

Formation permeability 1,000 md 500 md 250 md 100 md

50 40 30 20 10 0 1,000

750 500 250 Differential pressure, psi

Fig. 3.3. Volumes of HEC pills required to control fluid losses .

pressure by more than approximately 500 psi. In addition, elevated temperatures are detrimental to the ability of gels to control fluid loss. The gels will degrade at high temperatures and often additional gel pills will be required throughout the course of the completion or workover to keep the loss rate at an acceptable level. The total volume of pills likely to be needed can be calculated based upon Darcy’s Law calculations. Combined calculations of viscosity increase as the velocity decreases with radial distance into the formation. Figure 3.3 illustrates the results of such a calculation. The least damaging means of controlling fluid losses may be to increase the viscosity of the fluid with a viscous polymer gel. There are many different types of polymers that are used for this purpose, but the polymer that is gener-

47

Modern Sandface Completion Practices

API Fluid Loss (400 psi/36 min)

Average Permeability Reduction

cc 80 190

Unfiltered HEC Sheared/Filtered HEC

Initial (%) 71 20

After HCI (%) 5 3

Test Conditions: 24 md Berea cores, 120°F, 40 pore volumes 7.5% HCI, 80 lb/1,000 gal HEC, no chemical breakers Table 3.5. HEC performance: sheared vs. unsheared

Product Name Xanvis Shellflo-S Biopolymer HEC

511

sec-1

20 16 100

Viscosity, cp 170 sec-1 1 sec-1 42 35 200

4,650 2,600 3,500

0.1 sec-1 23,500 10,200 5,900

Table 3.6. Comparision of polymer viscosities

ally accepted as being least damaging to formations is HEC (Hydroxyethyl Cellulose). Chemical breakers, that cause the viscosity of the HEC gelled brine to break after it is downhole, are acids, oxidizing agents and enzymes. Hydrochloric acid and ammonium hypochlorite have been commonly used, but enzymes are now becoming more common. Enzymes used to have a temperature limitation of only 130°F (54.5ºC), but now the temperature limitation has been increased to 200°F (93.4ºC) by specifically designed cellulose-polymer-specific enzymes. These recently developed enzymes offer significantly better chemical degradation of the polymer and are considered to be the best breakers within their temperature and pH limits. Limitations and potential problems with HEC are: • Contain microgels if not sheared and filtered • Cause formation damage if its viscosity is not broken • Contain fish eyes if not properly mixed • Maximum thermal stability of 210°F (99ºC) without special additives • Relatively low shear strength. Microgels in HEC gelled pills are beneficial because they serve as a fluid loss control agent; thus HEC gelled pills should never be sheared and filtered after they are prepared. Table 3.510 compares some properties of HEC, before and after shearing the gelled brine. This data appears to indi48

cate that HEC will cause a lot of formation damage if it is not sheared, but notice the “Initial” data was obtained by using HEC without a chemical breaker. Since HCl acid is a common chemical breaker, the data in the “After HCl” column shows that there is no difference between the sheared and unsheared HEC solutions, as 5% and 3% permeability reduction data are within normal laboratory core test scatter. The API fluid loss data in Table 3.5 shows clearly why it is important that HEC should not be sheared when it is used for gelled pills to control fluid loss rate. More, recent studies have shown that fluids viscosified with dry HEC are not as thermally stable as fluids viscosified with liquid products. HEC prehydrated in an activating polyol solvent system easily disperses into all brine systems and hydrates rapidly to produce a more effective viscosifier and thermally stable fluids than dry HEC.11 If dry HEC is used, care must always be taken while preparing HEC pills to prevent fish eyes. These are clumps or clusters of partially hydrated HEC polymer that will not dissolve, and can plug the formation and perforations. This problem can easily be prevented by following proper guidelines for preparing the pills (i.e., adequate stirring while adding the HEC, low pH conditions until the polymer particles are totally dispersed, pre-wetting of the polymer with isopropanol or kerosene, and not adding polymer after gelation has begun). Tests by Shell Development Company describe many useful parameters of

HEC for perforating and fluid loss control. They recommend that an HEC concentration of 4.2 ppb of brine be used as a minimum for fluid loss control pills. At this concentration, the viscosity will slowly break and reach approximately 10% of its initial viscosity after about 24 hours at 200°F (93.4ºC).12 Some operators are using 5 ppb HEC in brines as a fluid loss control pill. This has an extremely high viscosity and will remain stable for approximately three days at 200°F (93.4ºC). However, a special additive can be used that will stabilize HEC to temperatures as high as 270°F (132.3ºC). Other water soluble polymers such as Xanthan Gums, HPG (hydroxypropyl guar) or CMHPG (carboxymethyl hydroxypropyl guar) may be used for high temperature applications. Kelco XC (Xanthan Gum) type polymers are also used for gelling brines and some laboratory reports indicate that there is less potential formation damage with this gelling agent than with HEC. The most common problems with this type of polymer are that it is difficult to prepare a good solution in the field because of the high shear rate required and its sensitivity to heavy brines. If XC polymer is properly prepared (without fish eyes), it will have better gel strength and can suspend more solids at lower shear rates than an HEC polymer solution. The high viscosity (23,500 cp) at a low shear rate of 0.1 sec-1, Table 3.6, indicates the relatively high shear strength of XC gelled water. Although HEC gelled water has a higher viscosity (100 cp) at a high shear rate (511 sec-1) than XC gel, the viscosity of HEC is much less (5,900 cp) at a low shear rate (0.1 sec-1), which allows sand particles to fall much faster in HEC gel at static conditions. These data favor the use of XC gelled pills to control fluid loss rate, but also indicate a much greater potential for formation damage by any XC gel that does enter the formation. The viscosities of Shellflo-S, a biopolymer viscosifier, fall between the Xanvis and HEC.13 All of the above products can be used to viscosify solids-free completions. They are also compatible with a wide range of completion fluids and Xanvis and HEC may be broken with a wide range of breakers. Viscosity breaking of Shellflo-S Biopolymer can be achieved without a conventional breaker by using

Chapter Three Cased-Hole Sandface Completions

its unique viscosity-temperature profile, which is brine dependent.14 If required to be stored for more than a few days after hydrating, biocide must be added to any viscous polymer gels because bacteria present in the brine, tanks or lines will cause the polymer to break prematurely. Each product has been used for fluid loss control, but none of them are effective in extremely high permeability formations. Generally, HEC gelled pills are preferred over XC gelled pills where wellbore conditions do not exceed the HEC gel limitations and when the HEC gelled pills are prepared properly and contain the proper viscosity breakers.15 It is also important to note here that HEC is being challenged as the “polymer of choice.” OSCA (now BJ Services) reported on a New Polymer (NP) that is slightly less formation damaging than HEC when tested as a solids-free pill. In brines where HEC shows precipitation, NP will not precipitate and no NP precipitation was seen in the brines tested. HEC generally shows greater viscosity at low temperatures than NP, but NP shows greater viscosity at high temperatures.16

Debris Removal and Mysteries The productivity of a well can be damaged by drilling and cementing long before a completion fluid is introduced into the wellbore. These operations can force particles as incidental bridging agents into the formation. Therefore, to help prevent further damage, it is important to make an extra effort to take steps to remove as much debris as possible when switching from the drilling mud to completion fluid. In addition, completion fluid related mysteries should be avoided, if possible. For example: • The completion ran perfectly, but the packers will not set. • The completion ran perfectly, but the mechanical or hydraulic valves will not operate. • The brine cleaned the casing to a “spotless” condition, but the completion got stuck running in. • The casing was cleaned perfectly and perforating and the completion went without a hitch, but the well does not produce at all or below par. The cause of the above problems can almost always be tracked back to poor cased cleaning. Consider that 9,000 ft

Variable Color Organic material a Inorganic material Average density c Acid solubility d

Tubing & Casing

Drill Pipe

Brown 26.4 wt% b 73.6 wt% 4.44 g/cm 3 25 wt%

Gray 39.4 wt% b 60.6 wt% 4.23 g/cm3 75 wt%

a. Solubility in xylene, b. Average of three measurements, c. Density of inorganic material, d. Solubility of the inorganic portion in 20 wt% HCI Table 3.7. Characteristics of pipe dope

(2,743.2 m) of 7 in. chrome casing can contain up to 330.75 lb (150 kg) and up to 300 ft (91.4 m) of pipe extruded pipe dope inside of it. Further, 9,000 ft (2,743.2 m) of 9-5/8 in. casing containing brine with only 500 ppm solids extrapolates into 150 ft (45.7 m) of solids fill. Pipe dope, which can be easily overlooked as a damaging material, can be a difficult problem to remedy. A recent study done by Saudi Aramco, whereby they examined samples of pipe dope used during placing well casing and the drill pipe, documents this. Table 3.717 summarizes the results obtained with the two types of pipe dope. The pipe dope that was used for the casing contained nearly 26 wt% of organic material, whereas that used in drill pipe had 39 wt% organic materials. This data verifies that pipe dope is indeed, wherever found in a well, not an easy material to remove. Note the extruded pipe dope shown in Figure 3.4. If not properly removed, this material can negatively effect the completion. Pipe dope removal from the wellbore is critical because it: • Weighs two times more than water • Consists of metal solids as well as heavy oils • Accumulates on tubing and casing, and unless removed settles in the wellbore • Clogs perforations, pore throats • Agglomerates other solids remaining to form large masses, which can cause tool and packer sticking or failure. Super Pickle products (solvent and surfactant blends from Well Flow International) are excellent oil, ester and pipe dope removers. All Super Pickle products are designed for minimum 95% to 100% combined pipe dope and oil-based mud (OBM) removal in 180 seconds at laminar flow rates. Field

Fig. 3.4. Internal photo of extruded pipe dope

exposures vary from 3 to 12 minutes at the same rates. All possible debris needs to be removed from the well in the course of displacement procedures. Proper procedures include the following steps: • Displace drilling fluid • Pump base fluid spacer, followed by a: • Surfactant spacer (Rinse Aid, a non-ionic water soluble surfactant system, or equivalent) • Solvent wash (Super Pickle or equivalent) • Water wetting wash (Rinse Aid or equivalent). An efficient wellbore cleanup can (1) eliminate risk of completion tools, packers and strings from sticking or becoming inoperable, (2) eliminate particle invasion to the formation, (3) enhance productive capability of the well, and (4) extend the working life of the completion. Displacement Procedures The objectives of a drilling mud to completion fluid displacement are to remove the mud and mud filter cake, maintain control of the wellbore and minimize overall rig operation time. To effectively remove the drilling mud, it must be conditioned prior to its displacement. The rheology should be adjusted to minimum plastic viscosity 49

Modern Sandface Completion Practices

Total suspended solids content, mg/l

Sea water

Surfactant Sea 8.7 lb/ water gal KCI

3,000 2,000 1,000

100

0 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Time, hrs

Fig. 3.5. Suspended solids content of circulated returns

(PV) and yield point (YP) values to ensure that circulation can be established. To remove solids from the casing walls, the work string should be run into the well with two casing scrapers for each casing size. It is commonly recommended to run in with a bottom scraper to the plug back depth or liner top and an upper scraper spaced midway in the casing section. Circulation should be established to condition the mud, to disperse mud cakes from tanks and drill pipe, and to remove solids through all available solids control equipment. Rotation and reciprocation of the drill pipe is also recommended if possible. Once completed, a short trip with the drill pipe should be made. In addition to conditioning the mud, the surface pits containing drilling mud should be pumped empty, and the tanks that will contain completion fluid should be pressure washed. All surface equipment should be cleaned with a volume of surfactant-treated drill-water (or seawater), and then flushed again. Tanks and surface equipment should be allowed to drain and dry prior to receiving clean completion fluid. To accomplish efficient mud displacement, the following wellbore cleanup design steps are recommended: • Verify cleanup procedures with laboratory testing. • Design surfactant spacer and wash train based on cased well design and mud type/characteristics. • Program tool usage based on casing design. 50

• Detail surface cleaning procedures to avoid contamination. • Implement clean-up procedures. Chevron applied a successful displacement procedure offshore California. They reported the suspended solids content of circulated well returns during a typical changeover, Figure 3.5.18 After running a scraper and flushing with seawater, the solids load normally stabilizes at a level below 100 mg/l indicating that most of the easily removable solids in the wellbore have been removed. When the surfactant sweep is circulated, solids content often rises over 1,000 mg/l as the surfactant frees up particulate attached to the casing by reducing interfacial tension. Another flush of seawater is circulated to pick up any solids loosened by the surfactant that may have strung out through the well. Finally, when the completion fluid is circulated through the well, it picks up only a minor amount of additional solids. Pump Rates and Pressure Calculations Hydrostatic differences between the spacer pills and drilling mud can have a major impact during direct displacement, where pump rates and pressure calculations are critical. Knowledge of casing and work string size is essential to these calculations, and for a determination of friction loss estimates calculated for both the forward and reverse circulating directions. The pumping direction chosen is often based on lower pump pressure and hydraulic horsepower requirements. Generally, however, the forward circulating direction is preferred in order to facilitate rotation and reciprocation of the work string, which helps reduce residual mud pockets in the annulus. A good guideline is to pump at rates based on a minimum flow rate of 3 ft/sec (91.44 cm/sec) in the largest annulus. This velocity is sufficient to put non-viscous pills in turbulent flow, which ensures good contact of chemical cleaners with the surface of pipe, casing and mud cake, and provides efficient mud removal and pipe-wall cleaning. Displacements are categorized as direct, indirect, balanced or staged. All can be pumped in either the forward or the reverse pumping direction. The forward, conventional displacement pumps

fluid down the work string, taking returns up the annulus. A reverse circulating displacement pumps fluid down the annulus, taking returns up the work string. There are advantages and limitations to both. A standard displacement replaces the drilling mud that is heavy enough to control the well with a completion fluid that also controls the well pressures. However, prior to placing a full-hole volume of completion fluid in the wellbore, a series of low-density spacers is circulated. This situation requires well control considerations when open or squeezed perforations are exposed, liner tops have not been negatively tested, or other pressure sensitive situations are evident. Balanced displacements are the exceptions. Conventional circulation allows easy rotation and reciprocation of the work string when the annular blowout preventer and pipe rams remain open. Pipe movement is especially important in deviated wellbores. Forward circulation usually permits higher pump rates and less frictional pressure loss over the course of the displacement, where much of the pump pressure is contained within the work string rather than transmitted to the annulus. Conventional displacements also allow greater control over differential pressure across liner tops, squeezed perforations and other pressure sensitive areas. When well control does require back pressure, rotation and reciprocation of the work string is less likely. Reverse circulation limits contamination of the interface between highdensity mud and lower-density spacer pills or completion fluid. It is often used as the first stage of an indirect displacement in which the mud is reversed out of the hole with water and then the annulus and work string cleanup is pumped conventionally. Because reverse circulation is carried out with the annular pressure control equipment closed, the possibility of pipe movement is limited or eliminated. While pressure calculations are less significant when indirect displacements are possible, high flow rates should still be maintained to facilitate mud removal and wellbore cleanup. Additionally, brine cleaning can be enhanced with the use of products such as Dirt Magnet (from Well Flow International). Dirt Magnet uses a system

Chapter Three Cased-Hole Sandface Completions

of surfactants specially blended with a high boiling point alcohol carrier to remove mud, oil, sand, barite and other solids effectively from casing and production tubing. It is somewhat unique and effectively flocculates micro-emulsified oil and fine solids, minimizes fluid filtration requirements and helps ensure a solids-free well completion.

0

0.02

Volume injected, gallons/perforation 0.04 0.06 0.08

0.1

500 A (2 ppm) B (2.5 ppm)

Contamination reduces production and shortens the productive life of the well. Contamination can occur during perforating, fracturing, acidizing, workover or gravel packing a well. Any time a fluid is put into the wellbore with solid particle content, no matter how slight, the chance of damaging the well is present. Particle-induced impairment of this type is shown from lab test results performed on 450 md Cypress sandstone cores to be severe and only partly removable with acid when caused by bay water solids (Fig. 3.6).19 In the field, fluids having 10 to 15 ppm solids appear “clean” in pits. However, in Figure 3.5 note that 10 to 15 ppm solids caused a permeability reduction of 90%. Then, only 10% to 30% of the original permeability was restored by backflowing and acid restored just 50% of original permeability. The purpose of using clear brine as a completion fluid is to provide a solids-free environment that protects the producing formation from particle invasion damage. The single most important aspect of completion fluid maintenance is filtration. Filtration can be defined as the removal of solid particles from a fluid. This process is critical to keep all solids from the intended productive interval and to allow a well to produce at its full potential for the maximum period of time. Although filtering can be expensive and time consuming, it is quickly offset by the net increase in production. Filtration has evolved from the old surface sand bed systems with low volumes capabilities to highly sophisticated systems. Regardless of which system is used, a case for filtering fluid can be made for every well that has concerns for any type of particulate impairment. The following example illustrates the seriousness of formation damage: In 50 bbl of fluid containing one-half percent solids (1/2% = 0.005 = 5,000

Permeability, md

Fluid Filtration

C (14 ppm)

100

E (50 ppm) F (48 ppm) D (26 ppm) G (94 ppm)

50

H (110 ppm) I (485 ppm)

Location A 998-112 B 1008-48 C Platform AA D 1008-77 E 998-112 F 1008-77 G Fed lease H 998-112 I 1008-48

Treatment Sand pack filter Ballast tank, 2µ cotton filter (Blk 27), untreated 5µ cotton filter 5µ cotton filter Untreated Produced water, untreated Untreated Collapsed 2µ cotton filter

10 0

100

200

300

400

500

Volume injected, pore volumes Fig. 3.6. Apparent permeability reduction due to injection of various treated and untreated bay waters

ppm), there are approximately 2,426 cu in. of solids. Since the volume of a perforation tunnel 1/2 in. in diameter and 10 in. long is 1.96 cu in., the volume of solids in those 50 bbl of fluid could totally plug 1,235 perforations. If a gravel pack is to be done and contaminated fluid is used as a carrying fluid, the small particles of solids mixing with the sand will take up the pore space between the sand grains reducing permeability. The permeability of this mixture is actually less than that of the gravel pack with only sand particles. A contaminant in completion fluid can come in many sizes and forms. Cuttings from drilling operations, drilling mud, rust, scale, pipe dope, paraffin, undissolved polymer and any other material on the casing or pipe string contribute to solids in the fluid. At times

it is virtually impossible, because of particle size, to remove all of the solids from the fluid, but by filtering, this success factor can be increased 100%. Filtration Guidelines How clean does the fluid need to be? What size particle needs to be removed? During the past 25 years, many studies have been done to assess the effects of particle invasion damage and the size cut and quality level of filtration necessary to prevent formation damage. The pore throat size of the productive formation must first be determined or estimated. If core material is available, the pore throat size distribution can be measured by mercury injection and capillary pressure relationships, or by directly measuring pore throat sizes 51

Modern Sandface Completion Practices

Particle size

Affect

>1/3 pore throat diameter

Bridge instantly on the throat and do not penetrate the formation. Solution: Filter fluids to remove particles +/>1/3 the pore diameter. Remove particulates from the perforated tunnels by applying a perforation wash tool. Invade the formation and bridge on the pore throat deeper in the formation. Solution: Filter fluids to remove particles less than 14% of the pore diameter. Normally considered non-damaging to the formation.

1/3 to 1/7 pore throat diameter <1/7 pore throat diameter <2 micron

Considered non-damaging in most cases.

Table 3.8. Summary of particle size affects Particle size (micrometers) 10,000 Beach 1,000 sand

d=

Where: d

100 Fly ash

φ k

10 1.0

Bacteria

0.01 0.01 0.1

1.0

10

100 1,000

Solids concentration, ppm (by wt.)

Fig. 3.7. Scope of filtration

by a scanning electron microscope. Should sieve analyses of the formation be available, an estimation of the average pore size of a formation sand can be determined by the Coberly equation: d=

D50 6.5

Where: d = average pore size D50 = diameter of median formation grain However, when core material is not available, a rough approximation of the average pore size of a formation sand can be determined by Kozeny’s method: d=

φD50 k = 0.128 φ 3(1 − φ)

= average pore size, microns D50 = diameter of median formation grain microns φ = porosity, fraction k = permeability, md Or, from an equation developed by Blick and Civan:

d , bridging occurs. 3 d d If < D p < , shallow invasion 7 3 occurs (worst case). d Iff D p < , deep invasion occurs 7 (no problem).

If D p >

Where: Dp = diameter of particle d = average pore diameter In terms of minimum filtration criteria, the objective is for all particles to be small enough to freely flow through the formation without plugging the critical near wellbore area. Thus, filtering should be done to achieve a maximum particle size in the completion fluid, which is less than d/7. For example, consider a formation with k = 2,000 md and φ = 22%, and use Kozeny’s method: d = 0.128

Where: d

52

= mean pore diameter, micron = porosity, percent = permeability, md

The relationship between pore size and particle size of the solids in a fluid are given by the following “rules of thumb.”

0.1 Virus

32 k φ

Dp =

2, 000 = 12.2 micron 0.22 12.2 = 1.7 micron 7

Therefore, the minimum filtration requirement is 2 micron. In summary, the diameter of the grains of formation sand is 6.5 times the size of the pore throat (Coberly equation), assuming the sand is per-

fectly round. Particles greater than 1/3 the diameter of the pore throat bridge instantly on the throat and do not penetrate the formation. These particles present some problems, which usually can be remedied by removing the particles from the perforation tunnels with a perforation wash tool. Particles less than 1/7 the pore diameter pass through the throat and through the formation without bridging or plugging. However, particles between 1/3 and 1/7 the pore throat diameter invade the formation and bridge on the pore throat deeper in the formation. These particles are the ones that cause the serious problems. With the pore throats plugged causing significantly reduced permeability, fluids cannot be injected into the formation to clean the pore throats. The concept described above is illustrated in Table 3.8. Put another way, any particle that is 33% of the pore diameter will instantly bridge and block the pore. Any particle that is 14% to about 30% of the pore throat diameter will penetrate deeper into the formation and plug or bridge matrix permeability. Filtration levels are based on removing particles to the 14% throat diameter level to prevent particulate damage. Even 3 Darcy formations, often thought not to need filtration, are subject to particle damage from material too small to see. Figure 3.7, illustrates the particle size range that is damaging to formation matrices. Particles in the highlighted range can have a very large particle count without occupying large part per million levels. They may appear insignificant, but should be considered a potential problem and filtered accordingly. Relationship between Completion and Filtration In the last stages of the well completion process, wellbores are exposed to fluids contaminated by a high concentration of particles over a wide range of sizes. To maintain production, the recommended filtering process should employ a number of steps to remove contaminants, starting with the largest and working down to the smallest. This includes the use of (in order) a shale shaker, tank, desilter, centrifugal separator, cartridge filters, and Diatomaceous Earth (DE) filtration. However, there are several limitations. Consider

Chapter Three Cased-Hole Sandface Completions

the actual process of well completion and how it interacts with filtration in the following offshore well scenario. 1. Displacement of drilling mud with seawater. All drilling mud in the borehole is displaced with unfiltered sea or salt water while the work string is slowly rotated to ensure complete displacement of the mud. Unfiltered sea or salt water is used in an open-loop system. Both straight circulation and reverse circulation have been used during this stage of the process; this decision is usually based on on-site judgment. The advantage of the reverse circulation technique is that it offers low viscosity, high turbulence flow through a smaller pipe diameter to carry particles to the surface. During this step, the bit and casing scraper runs are made through the wellbore to remove mud cake and rust. 2. Assurance of a clean wellbore. When water returns are of the same quality as the water pumped into the well, unfiltered sea or salt water is displaced with filtered sea or salt water, again while rotating the work string to assure complete displacement. Filtering down to 2 microns is desirable to remove plankton and bacteria, preventing growth of microorganisms in the bore after the completion. An advantage of first flushing the wellbore with unfiltered water is that it reduces the filtering time by removing a great percentage of contaminant during this initial phase. At this point, the clean fluids are introduced into the wellbore. The most desirable method of operation is to switch to clean tanks, lines, troughs, pumps and traps, that are uncontaminated by drilling mud. If this is not possible, the entire existing system should be cleaned of mud. A clean production or work string should be used for completions. When inserting a new string, dope should be applied to the pin end only in small amounts, rather than to the box end in large amounts, as excess dope can fall in the hole and plug formations. 3. Displacement of completion fluid. When recirculated sea or salt water is clean, indicating a clean wellbore, a completion fluid is pumped into the

system. If possible, it is desirable to run a clean spacer system as an interface between water and completion fluid. Maintenance of clean completion fluids starts at the dock by assuring that all equipment used to handle completion fluids is clean. Field mixing of brines is not recommended. Delivery should be made in clean tanks. Final filtration when running them downhole is recommended. 4. Perforations. After perforating and washing perforations, if applicable, perforation debris and formation sand must be filtered out of the completion fluid to prevent replugging of the open perforations and formation. 5. Gravel packing. When perforating is complete and the completion fluid has been filtered to the desired level, the drill pipe is pulled, and the gravel packing operation commences. Taking these precautions can generally help result in a stable pack with the desired productivity, although there is no assurance that this will be the case. Experience has shown that successful completions depend primarily on following a set procedure without taking shortcuts, and on detailed attention to good housekeeping practices. A key element in the entire process is using clean fluids, which is made possible in large part through filtration techniques.

Filter Level Quality How effective a filter system is at removing particles became a concern in the early 1980s. Nominal cartridge filters were the equipment of choice for many years. They were relatively inexpensive and did not require much space. The standard used to measure the efficiency of the filter was solids removal by weight percent. The most common method of testing the size cut of a filter was the “Bubble Point” method. Laboratory testing with particle counters and particle size distribution graphs revealed that as much as 70% of the total particle count in a fluid was passing through the filter and that particles much larger than the size rating of the filter were passing the media. Figure 3.7 illustrates how fine particles take up small weight percentage, ppm. Nominal filters were found to have relatively poor construction integrity. The media was subject to deformation and shifting at the upper range of delta pressure. A more reliable media structure and a more accurate efficiency standard were sought. The result was the absolute rated filter. A comparison of absolute rated and nominally rated filters is shown in Table 3.9.20 The method of rating a filter’s efficiency that was adopted was the Beta Ratio (βR). The beta ratio method compares the particle size distribution and particle counts before and after a filter

Particle density in unfiltered fluids = 295 mg/l I. 1.0 and 2.0 micron nominal filters averaged 53% reduction of solids * Particle size % of total solids % of total solids (micron) in unfiltered fluids in filtered fluids 0.5 - 3 38 34 3-8 29 32 8+ 33 34 II. 2.5 micron absolute filters averaged 72% reduction of solids ** Particle size (micron) 1-5 5 - 15 15 - 25 25 - 50 50 +

% of total solids in unfiltered fluids 64 28 6 1 1

% of total solids in filtered fluids 100 0 0 0 0

* Analytical method: millipore testing ** Analytical method: particle counting and gravimetric analysis Table 3.9. Comparison of nominally and absolute-rated cartridge filters 53

Modern Sandface Completion Practices

Fig. 3.8. Pleated absolute cartridge

Fig. 3.10. Diatoms

Vent

Filter cartridge Gauge connections

Inlet

Particle removal efficiency testing: Procedure – OSU F-2 (Modified single – pass water) Test Particles – AC Test Dust Fluid – Water maintained at 1 cp kinematic viscosity Flow Rate – 1 gpm per 10 in. cartridge or as specified by user Sample Sequence – A minimum of five sample sets is taken upstream and downstream of the cartridge. The first sample set is taken at the start of the test, after the system has stabilized. The remaining sample sets are taken at 10%, 20%, 40% and 80% increase in the net pressure drop. Terminal pressure drop is 35 psi. The two methods used to verify fluid quality are Particle Size Distribution (PSD) and Total Suspended Solids (TSS). These tests require a laser particle counter and a very sensitive lab scale. Both pieces of equipment are not accurate under field conditions and the time required to perform the testing precludes a rapid test result. Samples of filtered fluid are usually collected and submitted for testing on a 48-hr time scale.

Drain (dirty)

Completion Fluid Filter Types Outlet

Drain (clean)

There are two basic types of completion fluid filters: cartridge filters and diatomaceous earth (DE) filters. Modern well completion technology has shown that filtration with DE systems followed by final polishing filtration with disposable cartridge filters is the recommended method of assuring the clean non-damaging character of completion fluids.

Fig. 3.9. Cartridge filter housing

medium and expresses the efficiency as a β coefficient. The following formula illustrates how the β coefficient is determined and Table 3.10 shows corresponding removal efficiencies for various β coefficients. Removal efficiency (β R ) = inlet concentration − outlet concentration inlet concentration

× 100

A Beta coefficient of 5,000 (99.98%) was established as the preferred level of filter efficiency. Cartridge filters capable of this efficiency are referred to as Absolute (ABS) filters. They are usually composed of a shallow or multi-layered filter media. The media has strong bonding mechanisms that prevent the media from shifting or deforming, thus assur54

ing high integrity throughout the delta range of the cartridge. Most ABS filters are configured as pleated cylinders to provide maximum surface area and therefore maximum flow rate per unit. The Beta ratio of a filter at the desired level of size cut is the basis for quality assurance in the field. Since actual particle size and count measurement is very difficult to impossible in the field, the Beta-rated cartridge is the determining factor. The Beta method used to test and verify a cartridge filter’s removal efficiency is referred to as the modified OSU (Oklahoma State University) F-2 standard. This testing procedure is described as follows:

Cartridge filters. There are various types of cartridge filters. The commonly used absolute Beta-rated fiber cartridges are relatively inexpensive, but they are not designed for backwashing and are normally discarded when they become plugged. In multi-cartridge filter housings, adequate cleaning of all cartridges by backwashing the entire unit is normally impossible because of flow channeling through a few cartridges. However, if the cartridges are removed from the filter and washed individually, cleaning may be effective. ABS filter cartridges are several times more expensive than nominally rated cartridges. Beta 5,000 cartridges are cost effective when used as a downstream polishing filter after a DE filter unit.

Chapter Three Cased-Hole Sandface Completions

Cartridge filtration alone is cost effective for low volume or low contaminant level fluids. Filtering make-up water for chemicals and or filtering relatively clean seawater are examples. The demands of circulation and maintenance of a completion fluid system are better addressed by a staged filter system comprised of a DE unit followed by ABS cartridge filters. A common use for cartridge filters is polymer solution filtration. Beta 5,000 10-micron filters are used to remove contaminants from polymer pills. Combined with hydraulic shear devices and due to the low volumes and relatively low percentage of contaminants, these cartridges provide a cost effective means of formation protection with polymer pills. Figure 3.8 is a cut-away of a typical ABS filter cartridge, which is contained in multi-cartridge filter housing, Figure 3.9. Diatomaceous earth filters. DE is the fossilized skeletal remains of marine diatoms. There are two main types, salt and fresh water. These structures provide a highly porous non-compressible cake ideal for the removal of solid contaminants. Figure 3.10 are microphotographs of typical diatoms. DE is produced in a variety of size and treatment grades and is used in a broad range of industrial applications. Although a DE filter consistently produces a very high fluid quality (less than 50 ppm), it is not absolute Beta rated because the filter cake is susceptible to shifting. Some DE particles and solids across a small range (relative to the DE type) can pass through the DE filter. The nominal median pore size in microns of DE provided by Celite Corporation are: • 10 micron Celite 503 • 5 micron Celite 512 • 2 micron Celite 505. For oil field applications, the most commonly used DE material is Celite 505 and in some applications 512. The 503 grade is used in high concentration contaminant situations when stagingdown to a required level is the practical method. There are two main types of DE filters used in brine filtration: • Recessed Plate Press • Vertical Leaf Pressure Filter.

Recessed Plate Press (Fig. 3.11) – The plate manifold is made up of a number of plates with recessed chambers on each side of the plate. At the head and tail of the manifold are special plates with only one recessed side. The plate recessions are covered with and appropriate filter septum material that promotes the formation of a DE cake but permits maximum flow through the septum. The plates with their cloths are closed and hydraulic pressure is applied to seal the individual plates. A pre-coat of clean DE is established by pumping slurry of clean brine and DE into the central port of the manifold. The slurry spreads radially through all the plate chambers. As the slurry passes through the filter septum, the DE is deposited on the septum as a

Beta (β)

Removal efficiency (%)

1 2 4 5 10 20 50 75 100 1,000 5,000 10,000

0 5O 75 80 90 95 98 98.67 99 99.9 99.98 99.99 100

∞

Table 3.10. Particle removal efficiency based on ß coefficients

Fig. 3.11. Combination filter unit including recessed plate press on bottom and cartridge filter housing on top 55

Modern Sandface Completion Practices

Top view

Expansion plate assembly

Right side end view

Inlet Outlet port

Air blowdown manifold Head Head liner plate Intermediate plates

Left end view

Follower liner plate Follower

Hydraulic control unit

Inlet

Side view Outlet port

Fig. 3.12. Recessed plate press diagram

Fig. 3.13. Combination filter unit including VLF at right and cartridge filter housing at left

uniform and clean coating. The fluid that passes through the septum travels via channels to the inside corners of each plate recess. Exit ports in the plate allow the fluid to enter the manifold discharge ports and then exit the press. Once a clear and air-free circulation is seen in the slurry skid pre-coat tank, the press is ready to begin filtering dirty fluid. Figure 3.12 is a diagram of a recessed plate press. The slurry skid has an additional tank that is used to prepare a body feed slurry of DE and fluid. This slurry is a concentrated suspension of DE. The slurry skid manifold is configured to allow dirty fluid to be brought from the 56

rig return pit and body feed slurry is either injected or pulled into the dirty fluid stream. The mixture of DE and dirty fluid enters the press through the center port and makes a radial distribution through the plate stack. As the DE and dirty fluid pass through the pre-coat a continuous layer of DE and trapped solids is deposited building a porous cake. The clean fluid exits the press and is routed to the downstream guard filter with absolute cartridge filters and then to the rig clean pit. Filtration continues until the press reaches its maximum cake capacity or maximum pressure drop. Ideally maxi-

mum cake and maximum pressure happen simultaneously. The slurry skid is configured for recirculation and pumping stops. The fluid in the press is evacuated by air pressure and the press is opened. The spent cake is removed from the plate recesses and the press is closed and sealed again ready for the next filter cycle. The length of a press cycle is governed by the concentration of contaminants and their type. Ridged particles are easily incorporated into the DE cake and do not create excessive pressure drop across the cake. Malleable solids such as clays and polymers deform readily and block a much higher portion of the DE cake permeability and cause more rapid delta pressure build across the cake. Sudden influxes of malleable particles can cause the press to “blind.” In other words, the press will reach its maximum pressure drop before reaching maximum capacity. DE presses can usually deal with solids concentrations of up to 1.0% or 1.5% and maintain a practical cycle length. Solids concentrations above this threshold can be impractical to process with a filter press. Some other method of solids concentration reduction must be used first. Vertical Leaf Pressure Filter (VLF) – These DE units approach pressure containment in a different manner. Instead of plates, clothes and pressure sealing, the VLF encloses the filter areas in a pressure vessel (Fig. 3.13). A pressure leaf is composed of a ridged hollow frame enclosed in a filter septum of cloth or metal mesh. Fluid filtrate exits to the interior of the leaf then out a discharge port at the bottom of the leaf to the system manifold. The DE filter cycle is performed the same as with a press unit. The difference begins at the cleaning point. Manual systems evacuate the pressure housing with air. The vessel lid is opened and the vertical leaves are washed with water. The water and spent cake exit via a large diameter cleanout port. VLF units have some unique advantages as a result of design. The flow rate possible with a VLF is higher per unit area than a press unit. VLF units are usually set with 100 to 1,000 sq ft of leaf surface and achieve flow rates with light fluids in the 8 to 15 bpm range. The equipment foot print is smaller

Chapter Three Cased-Hole Sandface Completions

than a press system and cycle cleaning is usually faster than a press unit. The disadvantages of the VLF are that it cannot deal with rapid changes in solids concentration or higher malleable particle loads. The VLF units also have a lower range of practical solids loading, on the order of less than a half percent by volume. Situations that have blinding particle loads and inconsistent solids loads are not practical use points for a VLF filter. Figure 3.14 illustrates fluid flow paths inside a VLF unit. Filter system selection is a critical component of the completion design process. Table 3.11 is a filter system selection guide. Filtration Quality Control 21 Since clean fluid is essential for maximizing well potential, it is important to verify system efficiency during the filtration process. Complete on-site analysis would include the following operations: • Fluid sampling • Centrifugal shakeouts • Turbidity testing • Gravimetric analysis • Determination of particle size distribution. Fluid sampling. Representative fluid samples should be taken from the following locations: 1. Upstream of the DE unit – This sample gives an indication of the solids content of the dirty fluid and is useful in determining the proper DE add-mix ratio. 2. Downstream of the DE unit – This sample indicates the efficiency of the DE unit and will reveal any DE screen bypass problems. An efficiently operated unit should reduce the solids content to 20 to 30 mg/l. 3. Downstream of the polishing filters – This sample indicates the overall efficiency of the system. A comparison of the DE downstream sample with this sample can reveal element bypass problems. 4. At the shale shakers – These samples are used to monitor wellbore cleanup progress. Since filtration efficiency can vary with pressure changes, flow rate fluctuations and cycle lengths, fluid samples should be taken as follows: • At beginning of cycle • At end of cycle • Once per hour during cycle.

Outlet

Inlet

Fig. 3.14. VLF interior diagram

System Type Cartridge units Filter press VLF filter

Best Usage Low volume or low contaminant levels. Use when space limitations are severe. Applicable in most filter situations. May experience size limitations in some circumstances. Applicable with lighter fluids or fluids with low or consistent solids loads. Use when size limitations make press units less attractive.

Table 3.11. Filter system selection guide

It is important to ensure that each sample taken is representative of the overall fluid mix. Sample locations should ensure that fluid is drawn from a flowing stream, not from dead fluid traps. The following practices will assist in obtaining good samples: 1. Sample ports should be flushed for 30 seconds prior to drawing sample. 2. Flush sample bottles several times with fluid before catching the final sample. 3. If samples are not analyzed immediately, treat with a bactericide to prevent organic growth. 4. Label each sample with well information, sample port location, date, time, fluid type and weight.

Centrifugal shakeouts. A centrifugal shakeout of suspended solids is a useful technique for obtaining a rough estimate of the percentage solids in a given fluid. Using this information, a proper DE add-mix ratio can be chosen to maximize flow rate and filtration cycle. The use of shakeouts to determine final wellbore cleanliness is not recommended because the most accurate devices will only read as low as 0.05% solids or 500 ppm. Turbidity testing. Turbidity is a measurement of fluid clarity and is recorded in Nephelometric Turbidity Units (NTU). A lower NTU reading corresponds to better clarity. Turbidity is one of the opti57

Modern Sandface Completion Practices

Lenses

Lamp

Sample cell

Spatial filters Detector Light shield

Fig. 3.15. Turbidimeter optical diagram

Fig. 3.16. Turbidimeter

200

Turbidity, NTU

150

100

50

0 0 1 2 3 4 5 6 7 8 9 10 11 12 Circulation time, hr

Fig. 3.17. Typical wellbore cleanup curve

Total suspended solids, mg/l

700 600 500 400 300 200 100 0 0

20

40

60 80 100 120 140 Turbidity, NTU

Fig. 3.18. Typical calibration curves 58

cal properties of a liquid and is related to the presence, nature and concentration of discrete aggregations of material different from the pure liquid center. Since it is defined as an appearance parameter, it can be measured by optical techniques. Basic measuring systems of different brand turbidimeters are similar. A linear photo detector mounted in the detector section of the instrument senses a narrow optical beam that is projected through fluid. This detector, mounted 90 degrees to the lamp source, measures the intensity of the light scattered by the particles in the fluid. Electronic components amplify this signal and provide a meter reading that corresponds to the concentration of particles. See Figures 3.15 and 3.16. Although turbidity readings alone cannot determine solids content, they are very useful in monitoring filter performance and wellbore cleanup. Clarity differences between filter influent and effluent samples reflect filter efficiency. Plotting turbidity of well returns versus circulating time (Fig. 3.17) is helpful in determining when optimum wellbore cleanup is achieved. The accuracy of turbidity measurements is dependent upon instrument limitations and the use of proper field testing techniques. The following points should be considered while using a turbidimeter: 1. Each new instrument is supplied with its own unique turbidity “transfer standard” that has been calibrated to duplicate factory settings. Using an off-the-shelf replacement standard can affect the accuracy of a given turbidimeter by as much as 20%. 2. Since turbidity readings are optical measurements, any extraneous distortions caused by scratched or dirty glassware will affect the NTU reading. It is important to keep the “transfer standard” and sample vials free of finger prints, scratches and particle contamination. 3. Sample preparation is important for consistent and accurate turbidity readings. The collected sample should be passed through a 200 mesh screen, to remove particles larger than 74 microns, and then allowed to stand for a few minutes. The sample used for measurement should not contain any settled or floating solids. 4. Turbidity readings between different turbidimeters on the same sample

will not produce the same results unless the units have identical optical systems. Gravimetric analysis. Gravimetric analysis is used to determine the total amount of total suspended solids (TSS) in a completion fluid sample. This technique involves passing a specified amount of fluid through a 0.45 micron membrane, drying the membrane, and measuring its weight gain due to trapped solids. By convention, solids content is measured in number of milligrams per liter of fluid (mg/l). Since there are 1,000 ml in one liter of fluid, the following calculation can be used to determine the solids content in a given fluid based on a gravimetric analysis: Practice for TSS ( mg l ) = ( final mg weight − original mg weight) × 1, 000 sample volume in ml

API RP 13J, “Testing Heavy Brines,” 2nd Edition, March 1996, provides a laboratory procedure for correlating turbidity readings to total suspended solids. This technique uses a calibration curve that is generated from gravimetric analysis. The procedure involves taking NTU measurements on five fluid samples that have increasing levels of suspended solids. Gravimetric analysis is then run on each sample. The data is plotted with NTU on one axis and total suspended solids on the other axis (Fig. 3.18).22 The resulting linear calibration curve can be used to estimate suspended solids at any given NTU reading. It is important to remember that accuracy of the correlation is dependent upon the analysis of the same fluid using the same turbidimeter throughout the filtration operation. If a different fluid or distribution is introduced into the system, a new calibration curve should be generated. Determination of particle size distribution. As previously discussed, it is generally accepted that particles 1/3 to 1/7 the diameter of the average pore throat cause the most significant wellbore damage. Actual determination of the particle size distribution can be accomplished by using particle counters or microscopic analysis. Onsite particle size distribution determination can be expensive and time consuming. Unless a trained technician is available, it can

Chapter Three Cased-Hole Sandface Completions

also be difficult to obtain reproducible data. For these reasons, field particle size distribution testing is not recommended at this time.

Perforating The main purpose of perforating an oil or gas well is to establish good flow communication between the wellbore and the reservoir. Although in all casedhole completions perforating is the primary means for establishing reservoir connectivity, it is frequently taken for granted in the completion design process. In any completion, the primary objectives of perforation should be clearly defined and an appropriate design accordingly implemented. Both well productivity and injectivity depend primarily on near-wellbore pressure drop (commonly referred to as skin) which is a function of completion type, formation damage and perforation parameters. Modern perforating is inseparable from other services that improve well productivity, such as fracturing, acidizing and sand control or prevention.23 In addition to being conduits for oil and gas inflow, perforations provide uniform points of injection for water, gas, acid, proppant-laden gels for hydraulic fracture stimulations and fluids that place gravel to control sand in weak or unconsolidated formations.24 In other sand-management applications, perforating provides the required number, orientation and size of stable holes to prevent sand production.25 Jet perforating, using special shapedcharge explosives made specifically for oilfield perforators, has been commonly employed since the late 1940s. The shaped charge evolved from the WWII military bazooka and replaced less powerful bullet perforators and other technologies such as mechanical cutters and hydraulic jets. While jet perforating is the most common way to establish conductive tunnels that link oil and gas reservoirs to steel-cased wellbores that lead to the surface, the perforating event also damages formation permeability around each perforation tunnel. This damage and various perforation parameters—formation penetration, hole size, shot density and the angle between holes or phasing—have a significant impact on pressure drop and, therefore, on production. Optimizing these parameters and mitigating

induced damage are important aspects of perforating. In the past, completion engineers often based the selection of perforating systems solely on charge performance data from API RP 43 Concrete and Berea Test criteria such as depth of penetration and/or casing-exit hole size. It was generally accepted that a good indication of charge hole size could be obtained from the concrete target tests since in these the charges are fired through casing. Likewise, since the Berea sandstone target core is more uniform, results from it were thought to yield more reliable charge penetration performance. Much of the perforating charge data published by the service companies is still based on the API RP 43 evaluation tests. Today, optimizing the perforating process involves much more than the analysis of shaped-charge penetration and hole size. Most would agree that understanding and predicting perforation inflow performance is critical for predicting well inflow performance in natural (cased and perforated) completions. The same is true to a lesser degree in fractured or sand-control completions where additional operations are conducted to enhance or assure a reliable connection to the reservoir.26 In November 2000, the American Petroleum Institute published API RP 19B, First Edition, “Recommended Practices for Evaluation of Well Perforators.” This Recommended Practice supersedes all previously issued editions of API RP 43. Sections 1 through 4 of API 19B provide means for evaluating perforating systems (multiple shot) in four ways: 1. Performance under ambient temperature and atmospheric pressure test conditions. 2. Performance in stressed Berea sandstone targets (simulated wellbore pressure test conditions). 3. How performance may be changed after exposure to elevated temperature conditions. 4. Flow performance of a perforation under specific stressed test conditions. Service companies have started providing performance information on new perforator systems based on the API RP 19B criteria. There is a multitude of perforating options varying in charge type, gun size, shot density, phasing, conveyance

method (tubing versus wireline, etc.), wellbore fluids, and perforating shot conditions (under/over/extreme over balance). While many combinations of these options have been applied in field perforating systems, some debate still exists over the relative benefits (e.g., shooting under versus overbalance, tubing conveyed versus wireline, and charge selection). In addition, technical analyses have been developed to quantitatively address components of an optimized perforating system (e.g., optimum underbalance or charge performance) but, rarely, the entire system itself. This is in large part due to the magnitude of parameters and the difficulty in validating the quantitative impact in the field. Many questions still exist concerning the entire range of perforating systems and their application: • How to predict their impact on inflow • When should a given perforating system be applied • Can different parts be interchanged (e.g., does each charge have the same optimum underbalance based on permeability) • What are the risk factors to achieve predicted performance.27 Although the development of a definitive strategy for the optimum perforating system design is well beyond the scope of this discussion, it is important to understand the basic components of a perforating system and how each impacts the completion process. Hence, the balance of this section will concentrate on the following: • Shaped-charge design and performance • Gun design and deployment techniques • Detonation methods • Well/reservoir characteristics • Perforation clean-up • Special perforating techniques. Shaped-charge design and performance. Perforations are created in less than a second by shaped charges that use an explosive cavity effect usually coupled with a metal liner to maximize penetration. Perforating charges consist of a primer, outer case, high explosive and conical liner connected to a detonating cord (Fig. 3.19). The detonating cord initiates the primer and detonates the main explosive. The liner collapses to form the high-velocity jet of fluidized 59

Modern Sandface Completion Practices

Shaped charge

Charge detonation

Detonating cord Case Conical liner

5 microseconds

Primer Main explosive

25 microseconds

Explosive cavity effects Explosive

Steel target Metallic liner

Lined cavity effect

Unlined cavity effect

40 microseconds

50 microseconds

Flat-end 70 microseconds

Fig. 3.19. Shaped charges, with a capability to instantaneously release energy in an explosive, use a cavity effect and metal liner to maximize penetration (lower left). Shaped charges consist of four basic components—primer, main explosive, conical liner and case (top left). An explosive wave travels down the detonating cord, initiating the primer and detonating the main explosive. A detonation advances spherically, reaching pressures of 7.5 million psi (50 Gpa) before arriving at the liner apex. The charge case expands and the liner collapses to form a high-velocity jet of fluidized metal particles that is propelled along the charge axis (right).

metal particles that are propelled along the charge axis through the well casing and cement and into the formation. Each component of the shaped charge must be made to exact tolerances. The first requirement for predicting perforation inflow performance is an accurate description of the perforation geometry. The API RP-43 Section 1 test was designed to provide a simple means to assess charge penetration performance using standard field guns. Pratt and Carrera28 have raised some concerns that charges can be designed to optimize performance in any material, and hence, comparison in concrete targets may be misleading for selecting charges for rocks with different properties. However, in a statistical analysis 60

of the available Section 1 data, Bell et al29 demonstrate that while charge optimization is a real phenomenon, the data can still be analyzed within reasonable accuracy limits in a meaningful way to infer penetration performance in target rocks of different strengths. In this analysis, most of the data (including “hard” rocks, i.e., rocks with sufficient strength that natural completions would not normally be considered) falls within reasonable error bands of the predicted average performance. The API RP-43 Section 4 test arises from a set of recommended API procedures30-32 designed to assess performance of perforating gun systems. The purpose of the Section 4 test is to assess perforation inflow performance for a

single shaped charge explosive under simulated in-situ stress and perforating conditions. Halleck and Dogulu33 review Section 4 test procedures along with different test experiences. Numerous papers34,35 have been written on pioneering work and results using Section 4 tests; in particular, inflow damage created during the perforating operation and optimal perforating conditions to remove the damage have been documented. However, the open literature has limited documentation on the standardization or repeatability in conducting these tests, in part, because of test complexity, and perhaps, because there are limited test facilities with which to compare results. Furthermore, a large percentage of the published results are based on small charges (3.2 gm and 6.5 gm weight explosives) not typically used in well completions. Depending on whether inflow performance is unique to each charge, some questions remain regarding the universality of the results and how to implement these results to design and optimize perforating gun systems for field application.36 As previously mentioned, an undesirable side effect of perforating is additional damage in the form of a low-permeability zone around perforations. The jet penetrating mechanism is one of “punching” rather than blasting, burning, drilling or abrasive wearing. This punching effect is achieved by extremely high impact pressures—3 million psi (20 Gpa) on casing and 300,000 psi (2 Gpa) on formation stemming from impact of the initial portion of the jet traveling at approximately 30,000 ft/sec (914,000 cm/sec). These enormous jet impact pressures cause steel, cement, rock, and pore fluids to flow plastically outward. Elastic rebound leaves shock-damaged rock, pulverized formation grains and debris in the newly created perforation tunnels. Hence, perforating damage can consist of three elements—a crushed zone,37 migration of fine formation particles and debris inside perforation tunnels (Fig. 3.20). The crushed zone can limit both productivity and injectivity. Fines and debris restrict injectivity and increase pump pressure, which decreases injection volumes and impairs placement or distribution of gravel and proppants for sand control or hydraulic fracture treatments.38 Erosion of the crushed

Chapter Three Cased-Hole Sandface Completions

zone as well as removal of debris from perforations by surge flow are essential to mitigate perforating damage and ensure well success in all but the most prolific reservoirs. Studies show that induced damage increases for larger explosive charges.39 The extent of perforation damage is a function of lithology, rock strength, porosity, pore fluid compressibility, clay content, formation grain size and shaped-charge designs.40 Research in conjunction with numerical modeling is providing a better understanding of permeability damage in perforated wells that can be used to improve completion designs in the future.41 It is important to note that shaped charges have been designed to generate optimal combinations of hole size and penetration using minimum of explosive material. Among the many advances in perforating technology are new deep-penetrating charges that increase well productivity by shooting beyond drilling and completion fluid invasion, and big-hole charges for gravel packing or frac packing. Drilling and completion fluid invasion can range from several inches to a few feet. When formation damage is severe and perforations do not extend beyond the invaded zone, pressure drop, or skin, is high and productivity is reduced.42 Perforations that reach beyond the damage increase effective wellbore radius and intersect more natural fractures if these are present. Deeper penetration also reduces the pressure drop across perforated intervals to prevent or reduce sand production. In general, hard, high-strength formations and reservoirs damaged by drilling fluids benefit the most from deep-penetrating perforations that extend beyond the formation damage and increase the effective wellbore radius. Low-permeability reservoirs that need hydraulic-fracture stimulation to produce economically require appropriately spaced and oriented perforations. Unconsolidated formations that may produce sand need high density, big-diameter holes which reduce pressure drop and can be packed with gravel to keep the formation particles out of the perforation and the wellbore. Perforations also can be designed to prevent tunnel and formation failure associated with sand production.43

Fig. 3.20. Perforating damage. A zone of reduced permeability is created around perforation tunnels by shaped-charge jets. Shock-wave pressures pulverize adjacent rock, fracture matrix grains, break down intergranular cementation and debond clay particles. Shattering of the formation around perforations damages in-situ permeability primarily by reducing pore-throat size. Photomicrographs show undamaged rock (top insert) compared to microfracturing in a perforation crushed zone (bottom insert ).

Gun Design and Deployment Techniques Gun design. Shaped charges are placed in guns (Table 3.12) and conveyed downhole to the correct depth by wireline, slickline, tubing or drill pipe, or via coiled tubing. There are two types of guns, capsule and carrier (Fig. 3.21). Capsule guns are used in electric wireline and slickline perforating for through-tubing applications. Since the shaped charges in capsule guns are exposed to well conditions, they must be encapsulated in separate pressure-proof containers. Debris from these expendable guns is left in a well after firing. Carrier guns (including those with threaded and sealed port plugs, machined scallops or non-scallops) are deployed on wireline or slickline, tubing or drill pipe run by drilling and workover rigs or snubbing units, and on coiled tubing with or without an electric line. In these guns, charges and most of the debris are contained in hollow steel carriers that are retrieved or released and dropped to the bottom of the wellbore after perforating. Casing and through-tubing guns, both capsule and carrier, were initially run on wireline; tubing-conveyed perforating (TCP) with high shot density (HSD) guns became popular in the late 1970s and early 1980s. Through-tubing guns are limited in gun size and length by well

completion design and surface pressure control equipment. The use of underbalance is also limited when guns are run on electric line. Conversely, TCP guns offer a wide variety of choices and allow for simultaneous underbalance perforating of long intervals, which is often considered essential for gravel packing or frac packing. Shot density and phasing. Shot density (the number of holes specified in shots per foot) and phasing (perforation orientation or the angle between holes) play important roles in perforating technology. An adequate shot density can reduce perforation skin and produce wells at lower pressure differentials. Optimized phasing reduces pressure drop near the wellbore by providing flow conduits on all sides of the casing minimizing interference and interlinking of adjacent damaged zones and reducing the risk of formation failure without compromising flow rate per perforation. Deployment methods. Deployment of perforating guns has evolved from early electric line and tubing or drillstringconveyed guns, and now includes coiled tubing with or without electric line, snubbing units, slickline and downhole tractors on wireline and coiled tubing. Each conveyance method has advantages and disadvantages related to per61

Modern Sandface Completion Practices

Gun Configuration Gun OD (in.)

Shot Density (spf)

3-3/8 3-3/8 3-3/8 3-3/8 3-3/8 4-1/2 4-1/2 4-1/2 4-1/2 4-1/2 4-5/8 4-5/8 4-5/8 4-5/8 4-5/8 5 5 5-1/4 5-1/4 6 6 7 7 7

Charge Performance Data

Charge Information

Phase (deg.)

Entry Hole Dia. (in.)

Target Penetration (in.)

Casing O.D. (in.)

Data Source

6 6 6 12 12 12 12 12-Auger 18 18 12 16 16 16 16 18 18 18 18 12 16 12 18 18

60 60 60 150/30 150/30 135/45 135/45 135/45 140/20 140/20 135/45 135/45 135/45 135/45 135/45 140/20 140/20 140/20 140/20 135/45 135/45 135/45 140/20 140/20

0.70 0.76 0.77 0.64 0.62 0.71 0.72 0.71 0.71 0.79 0.92 0.98 0.92 0.93 0.86 0.70 0.72 0.87 0.90 0.78 0.78 0.99 0.95 1.07

6.50 6.40 8.50 5.60 5.30 6.40 6.60 6.90 6.90 6.50 5.80 4.80 5.80 4.56 5.01 6.40 6.60 6.30 5.70 6.40 6.40 7.10 6.50 7.20

5-1/2 4-1/2 4-1/2 5-1/2 5-1/2 7 7 7 7 7 7 7 7 7 7 7-5/8 7-5/8 7-5/8 7-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8

API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API 19B API RP43 API RP43 API RP43 API 19B API 19B API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43

3-3/8 3-3/8 4-5/8 4-5/8 4-5/8 4-5/8 4-5/8 4-5/8 4-5/8 5 5-1/8 5-1/8 6-1/2 7 7 7 7

12 12 12 12 12 12 14 14 18 21 14 14 12/14 12/14 12/14 12 12/14

150/30 150/30 150/30 150/30 150/30 150/30 128.5/25.7 128.5/25.7 135/45 120/60 231.4 231.4 138 135-138 135-138 32 135-138

0.62 0.64 0.93 0.96 0.81 0.85 0.93 0.96 0.73 0.72 0.93 0.94 0.91 1.03 0.98 1.16 1.29

5.33 5.24 6.30 5.10 5.40 5.30 6.30 5.10 6.18 5.40 5.11 5.83 6.80 4.70 6.40 5.00 5.80

5-1/2 5-1/2 7 7 7 7 7 7 7 7-5/8 7-5/8 7-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8

API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API 19B API RP43 API RP43 API 19B API 19B API 19B API 19B API 19B

3-3/8 3-3/8 3-3/8 4-1/2 4-1/2 4-1/2 4-1/2 4-1/2 4-1/2 5-1/8 5-1/8 5-1/8 7 7 7 7

6 12 12 12/16 12/16 12 16 18 18 12/16 12/16 16 12/16 12/16 18 18

60 135/45 135/45 135/45 135/45 135/45 140/20 140/20 140/20 135/45 135/45 140/20 135/45 135/45 140/20 140/20

0.73 0.63 0.63 0.72 0.72 0.94 0.82 0.82 0.78 0.72 0.71 0.80 1.13 1.06 1.13 1.06

6.05 4.87 5.46 6.32 6.96 6.15 7.00 6.67 6.57 6.87 7.05 6.51 7.60 7.43 7.60 7.43

5 5-1/2 5-1/2 7 7 7 7 7 7 7-5/8 7-5/8 7-5/8 9-5/8 9-5/8 9-5/8 9-5/8

API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43 API RP43

3-3/8 3-3/8 4-1/2 4-1/2 4-1/2 4-5/8 4-5/8 5 5 5 5-27/32 6-5/8 7 7 7 7 7 7

6 12 12 12 12 21 21 8 8 21 18 18 12 12 14 12 18 18

60 135/45 135/45 135/45 135/45 120/60 120/60 135/45 135/45 120/60 120/60 120/60 135/45 135/45 140/20 135/45 120/60 120/60

0.44 0.64 0.34 0.39 0.34 0.83 0.83 0.54 0.98 0.74 0.93 0.91 0.47 0.45 0.95 1.13 1.13 1.14

31.40 4.50 30.20 17.90 28.60 5.90 6.10 20.20 5.80 7.90 7.20 6.80 32.00 39.90 12.20 10.10 5.90 7.10

4-1/2 5 7 7 7 7 7 7 7 7-5/8 8-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8

API 19B API 19B API 19B API 43 API 43 API 43 API 19B API 43 API 43 API 43 API 43 API 19B API 43 API 19B API 43 API 43 API 19B API 43

Expl. Type

Expl. Load (gm)

Carrier

Charge Type or Name

Charge Case

Min I.D. for Running (in.)

Pressure Rating (psi)

1 hr Temp Rating (°F)

GP JJ JJ GP GP GP GP GP GP GP GP GP GP GP GP GP GP GP GP GP GP GP GP GP

Perfform Steel Steel Steel Perfform Perfform Steel Perfform Perfform Steel Perfform Steel Perfform Steel Perfform Perfform Steel Perfform Steel Perfform Perfform Perfform Perfform Steel

3.75 3.8 3.8 3.75 3.75 4.75 4.75 4.75 4.75 4.75 5 5 5 5 5 5.38 5.38 5.63 5.63 6.75 6.75 7.38 7.38 7.38

20,000 20,000 20,000 20,000 20,000 17,000 17,000 17,000 17,000 17,000 17,000 17,000 17,000 17,000 17,000 17,500 17,500 15,500 15,500 14,500 14,500 12,000 12,000 12,000

330 330 400 400 400 330 330 330 330 400 330 330 330 400 400 330 400 330 400 400 400 330 400 330

BH BH SH SH SH/ LD SH / LD SH SH BH BH SH SH BH Mirage SH Mirage BH Mirage SH LD SH

Steel Steel Steel Steel Zinc Zinc Steel Steel Steel Steel Steel Steel Zinc Zinc Zinc Zinc Steel

4.423 4.423 5.795 5.795 5.795 5.795 5.795 5.795 5.666 TBD 5.969 5.969 7.600 8.379 8.379 8.379 8.379

23,000 23,000 16,000 16,000 16,000 16,000 20,000 20,000 18,000 16,000 17,000 17,000 20,000 11,000 11,000 11,000 11,000

325 400 325 400 325 400 325 400 325 325 325 400 325 325 325 325 325

BH BH BH / LD BH BH / LD SH SH / LD BH BH / LD BH BH / LD SH / LD BH BH / LD BH BH / LD

Steel Steel Zinc Steel Zinc Steel Zinc Steel Zinc Steel Zinc Zinc Steel Zinc Steel Zinc

3.75 3.75 3.75 4.81 4.81 4.81 4.81 4.81 4.81 5.65 5.65 5.65 7.63 7.63 7.63 7.63

20,000 20,000 20,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 13,000 13,000 13,000 13,000

330 330 330 330 330 330 330 330 330 330 330 330 330 330 330 330

UltraJet 3406 PowerFlow 3412 PowerJet 4512 34B HyperJet II 34JL UltraJet PowerFlow 4621 PowerFlow 4621 UltraJet 5008 PowerFlow 5008 43 CleanJet UltraPack II PowerFlow 5918 PowerFlow 6618 51B HyperJet II UltraJet 4505 58C UltraPack 64C CleanPack PowerFlow 7018 PowerFlow 7018

Steel Steel Steel Steel Steel Steel Steel Steel Steel Zinc Steel Steel Steel Steel Steel Zinc Steel Steel

3.86 3.72 5.11 4.97 4.97 5.02 5.02 5.39 5.39 5.34 6.16 6.93 7.25 7.25 7.47 7.95 7.33 7.33

20,000 20,000 12,000 12,000 12,000 15,000 15,000 10,000 10,000 11,000 20,000 20,000 10,000 10,000 10,000 10,000 10,000 10,000

400 400 400 340 400 340 400 340 340 340 400 400 340 400 340 340 340 400

BAKER ATLAS RDX RDX HMX HMX HMX RDX RDX RDX RDX HMX RDX RDX RDX HMX RDX RDX HMX RDX HMX HMX HMX RDX HMX RDX

22.7 22 22 11 11 22.7 22.7 22.7 19 19 26 28 26 28 26 19 19 26 26 32 32 61 39 48

HALLIBURTON / JRC RDX HMX RDX HMX RDX HMX RDX HMX RDX RDX RDX HMX RDX RDX RDX RDX RDX

14 14 28 28 28 28 28 28 20 21 32 32 47 39 39 56.5 56.5

OWEN OIL TOOLS / A CORE LABORATORIES COMPANY RDX RDX RDX RDX RDX RDX RDX RDX RDX RDX RDX RDX RDX RDX RDX RDX

20 11 11 20 29 26 23 17 17 20 19 23 39 39 39 39

SCHLUMBERGER HMX HMX HMX RDX HMX RDX HMX RDX RDX RDX HMX HMX RDX HMX RDX RDX RDX HMX

22.7 14.1 22.0 20.5 22.7 19 19.4 24 30 19 34 34 37 38.3 61 59 51.5 49.5

NOTES: BH = Big Hole, SH = Super Hole, LD = Low Debris, JJ = Jumbo Jet, GP = Gravel Pack, DP = Deep Penetrating, SDP = Super Deep Penetrating KISS = “Kiss the Face” designed to perforate the casing and cement sheath with minimal penetration of the formation

Table 3.12. Several perforating systems commonly used in sandface completions (check with your service supplier for other available charges and systems.) 62

Chapter Three Cased-Hole Sandface Completions

forming downhole operations, gun length and pressure control, perforating without killing wells, mechanical strength and wellbore angle, depth correlation, rigless intervention and gun type. To optimize perforation designs, the pros and cons must be weighed for all gun systems being considered for a specific completion. Gun clearance/centralization. Excessive gun clearance with any perforating gun can result in inadequate penetration, inadequate hole size, and irregularly shaped or “keyed” perforations (Fig. 3.22). Conventional carrier guns normally have adequate penetration in unconsolidated sands unless the cement sheath is unusually thick due to washedout borehole. If necessary, clearance control can be achieved through springtype deflectors, magnets and other methods. Depending on charge and gun design, 0 or 1/2 in. gun-to-casing clearance usually provides maximum perforation penetration and hole size. In some carrier guns, significant changes in hole size result as gun clearance is increased for 0 to 2 in. In such cases, centralization may produce a satisfactory and more consistent hole size. With gun clearance above 2 in., it is usually desirable to decentralize and to orient the direction of fire from the gun. Gun length and perforating without killing wells. Total weight of long gun strings and running or retrieving guns under pressure can restrict wireline, coiled tubing and even tubing-conveyed perforating. However, these limitations can be overcome by a technique referred to as permanent completion perforating (PCP) systems. This technique allows downhole assembly of multiple gun sections to any length with or without a rig, and provides underbalanced perforating of long intervals in one descent. The system can be deployed and retrieved by slickline, electric wireline or coiled tubing. When necessary, gun sections can be retrieved without killing the well. This system can be used to perforate wells without interrupting production. High-angle wells. In high-angle and horizontal wells, wireline may not allow guns to descend unless a tractor is used. Coiled tubing is the preferred conveyance method, unless a horizontal section is so long that helical buckling

Capsule guns

Tubing Casing

Pivot gun Retrievable Enerjet

Standard Enerjet

111/16 -in. OD running

Expendable Enerjet

3.79-in. OD deployed

Carrier guns

1.56-in. HSD gun 4 spf zero phasing

2.0-in. HSD gun 6 spf, 60˚ spiral phasing

2.25-in. HSD gun 6 spf, 60˚ spiral phasing

5.85-in. Bigshot 18 spf, 120˚/60˚ phasing

6 5/8-in. Bigshot 18 spf, 120˚/60˚ phasing

Fig. 3.21. Gun types. Perforating guns are classified as capsule or carrier. A few examples are shown. Capsule guns are conveyed by wireline or slickline in through-tubing operations. Detonating cords are exposed to downhole conditions, so the charges are encapsulated in pressure-proof containers. Expendable through-tubing capsule guns generate debris, which remains in a well after perforating. Carrier, or casing, guns are conveyed by wireline, tubing and coiled tubing and can be designed to retain debris inside the carrier. Detonation occurs inside the carrier under atmospheric pressure.

occurs before the perforating interval is reached. Tractors have also been used successfully to extend the maximum reach of coiled tubing. In many of today’s high-angle and extended-reach wells, there may be no alternative to TCP or PCP. If mechanical pulling or pushing force must be exerted on a gun system, TCP, snubbing, coiled tubing and tractors offer more versatility than electric line and slickline. For long guns like those used in horizontal wells, gunstring design must consider tensile

strength. High-strength adapters and tapered gun strings have been used successfully. Gun bending must also be modeled and addressed. Duration of operations. If intervals are vertical and short—less than 40 ft (12 m)—and perforated in balanced or overbalanced conditions, wireline perforating usually can be performed in a few hours and may be the most efficient method. If the interval is longer or has multiple sections, wireline operations 63

Modern Sandface Completion Practices

0.1 in. - entrance hole 2.5 in. - penetration 0.18 in. - entrance hole 3.7 in. - penetration

used in TCP systems actuate mechanically when a firing pin strikes a pressure-sealed membrane and detonates a primary high explosive. Several techniques can be used to actuate the firing pin: impact from a drop bar, annular pressure, tubing pressure, etc. Well/Reservoir Characteristics

1 11/16 in. - 90° phased gun Cement 0.3 in. - entrance hole 6.0 in. - penetration

7 in. casing 0.3 in. - entrance hole 6.0 in. - penetration

Fig. 3.22. Decreased performance of poorly centered, small-diameter perforating guns in large casing is illustrated by test target results of 1-11/16-in., 90° phased gun fired in 7-in. casing in simulated Berea sandstone. Note extreme variation in hole size and penetration.

Temperature, °F

650 550

PYX

450

HNS

350

HMX

250 150 1

RDX 10

100

1,000

Time, hrs Contact charge manufacturer for recommendations and possible need for systems testing

Fig. 3.23. Time vs. Temperature limits for common explosives used with carrier guns. This chart is valid for the explosive train inside hollow carrier guns only: non-electric boosters, detonating cord, and shaped charges. It is not valid for TCP firing systems, electric detonators, or capsule guns. For more specific information regarding these and other explosive components, contact your perforating service provider.

require more than one trip, which prevents use of underbalance during subsequent gun runs. As well deviation increases, operating time increases, especially if the gun-string weight is low and surface pressure-control equipment is used. When well deviation exceeds about 65°, other conveyance methods like TCP and PCP that require a longer running-in time must be used. If perforating intervals become significantly 64

longer, the overall duration of TCP can be significantly shorter than wireline operations. Additionally, the entire interval can be perforated with underbalance for optimal perforation cleanup. Run-time also has an effect on the explosives (most commonly RDX, HMX, HNS, and PYX) used in the perforating system. Each charge or explosive type has a time/temperature range rating (Fig. 3.23). Since charges are exposed to downhole temperatures for extended periods of time, this rating should be considered when designing a perforating system for particular well conditions. Detonation Methods Two types of detonators are used in perforating guns: electrical detonators or blasting caps, and percussion detonators. Conventional electrical detonators, most typically used with capsule guns, are susceptible to accidental application of power from electric potential differences (EPD). This can constitute a safety hazard, hence appropriate safety precautions should be taken to prevent and control any stray currents that could trigger premature detonation. Percussion detonators that are typically

Underbalanced, balanced, overbalanced and extreme overbalanced (EOB) describe the pressure differential between a wellbore and reservoir before perforating. At one time, perforating was performed with mud or high-density fluids in wells—balanced or overbalanced conditions. Today, in order to minimize or remove perforation damage, underbalanced perforating is more common. An underbalance exists when pressure inside a well is less than the formation pressure. Balanced conditions occur when these pressures are equal. An overbalance occurs when well pressure is greater than reservoir pressure. Extreme overbalance means that well pressure greatly exceeds rock strength—fracture initiation, or breakdown, pressure. Both EOB and fracturing attempt to bypass damage.44 Underbalanced or reverse-pressure. The potential of underbalanced perforating was recognized in the 1960s. Wells perforated with underbalance tended to show production increases. In the 1970s and early 1980s, researchers recognized that the flow efficiency of perforated completions increased when higher underbalance pressures were used. They concluded that post-shot flow was responsible for perforation cleanup and recommended general underbalance criteria.45 Since then, various aspects of perforating have been investigated using field and laboratory data. These studies consistently reinforce the advantages of an initial surge (a few hundred to thousands of psi depending on rock strength and permeability) to erode perforation crushed zones and flush out perforating debris.46 Magnitude and duration of an initial pressure surge are believed to dominate cleanup of crushed-zone damage. Instantaneous flow minimizes fluid invasion, loosens damaged rock and sweeps away rock debris in perforation tunnels (Fig. 3.24). The degree to which material is loosened is primarily a func-

Chapter Three Cased-Hole Sandface Completions

tion of underbalance pressure differential. The high-velocity surge is followed by pseudosteady-state flow, which is less effective because rates and associated drag forces are less than those generated during an initial transient surge. Fluid volume and flow that occur later are believed to be secondary. The underbalance pressures required to effectively clean perforations and reduce permeability damage have been measured in single-shot perforate and flow tests that provide a basic understanding of damage mitigation.47 Immediately after perforating in underbalanced conditions, there is instant decompression of reservoir fluids around a perforation. The dynamic forces—pressure differential and drag—that mitigate permeability damage by eroding and removing fractured formation grains from tunnel walls are highest at this time.48 Underbalanced perforating requires that the well be under control when the gun is fired so that fluid inflow can be handled safely and perforating equipment can be removed if needed. Short intervals can be perforated underbalanced using through-tubing guns run on wireline below a packer. When using these smaller strip or capsule guns, more than four to six shots per foot (SPF) can be obtained by reshooting the same interval. Small guns present centering problems in the larger casing, and in strongly flowing wells they can be blown uphole if cable size and selected underbalance is not properly coordinated. After the first gun is fired, pressure differential can be assured only by flowing existing open holes to draw down internal pressure. In highpressure wells, this requires careful planning and may not even be possible. TCP or PCP guns can be made up in very long lengths to underbalance perforate an entire zone or multiple zones at once. These systems offer the most options for perforating configurations and completion optimization, and are considered the safest way to shoot large intervals underbalanced. Gun assemblies as long as 8,000 ft have been deployed and intervals over 6,500 ft long in a single run have been successfully perforated using TCP techniques. These systems can involve very sophisticated assemblies employing numerous (as many as 52 to date) firing heads.

Casing Cement

Undamaged formation Perforation debris

Formation damage

Crushed and compacted low-permeability zone

Casing Cement

Undamaged formation

Formation damage

Balanced perforating

3,000-psi underbalance perforating

Low-permeability zone and perforation debris expelled by surge of formation fluid

Fig. 3.24. Underbalanced perforating. In an overbalanced or balanced perforation without cleanup and before flow, the tunnel is plugged by shattered rock and perforating debris (top). Production flow may remove some debris, but much of the low-permeability crushed zone remains. The initial surge flow generated by using an adequate underbalance during perforating helps remove debris and erode the crushed zone (bottom).

Underbalance Differential Permeability (md)

King* (psi)

Hsia #1** (psi)

Hsia #2*** (psi)

1 10 100 500 1,000 2,000 5,000 10,000

2,900 1,266 553 310 241 188 135 105

50,600 6,182 755 174 92 49 21 11

17,000 3,392 677 219 135 83 44 27

*∆ P = 2,900 / k 0.36(md) **∆ P = 5.06 x 104 / k 0.913(md) ***∆ P = 1.7 x 104 / k 0.7(md) Table 3.13. Underbalanced perforating guidelines related to underbalanced pressure differential

After firing, TCP or PCP guns can remain on the tubing to serve as a blast joint for inflowing fluids, or they can be dropped to bottom to allow future wireline operations through the tubing. In some applications, the guns are retrieved to the surface. Because tubing above the guns can be run empty or contain any volume of buffer fluid to cushion the blast, various magnitudes of initial pressure differential can be obtained to surge the new perforations clean.49 Options for perforating with underbalance have reached a high degree of sophistication because of hardware for TCP and PCP. Whatever the conveyance method, it is usually possible to perforate with sufficient underbalance (Table

3.13). Practical exceptions when optimal underbalance cannot be achieved are depleted reservoirs, shallow wells or wells with open perforations. For certain conditions, a high underbalance is needed to clean out perforations and generate post-shot flow. With wirelineconveyed guns, this is possible only if anchoring devices are used while shooting to prevent guns from being blown up hole. Anchoring devices are also recommended when the level of underbalance is unknown and guns are exposed to a sudden fluid influx, as for example, when perforating new intervals in formations with differentially depleted producing intervals.50 65

Modern Sandface Completion Practices

Tubing Circulating valve Casing Swab cups Formation sand

Length of perf interval 1 foot +/-

Perforations

Washed zone SWAB cups

Casing

Fig. 3.25. Schematics of perforation wash tools

Overbalanced or positive-pressure. This perforating method simplifies well control because fluid inside the casing overbalances formation pressure and prevents inflow. However, this also holds all perforating charge debris and crushed rock in the perforation, necessitating an additional clean-out operation. For sand control, further clean out is imperative prior to gravel packing, frac packing or injecting consolidating chemicals. Without tubing in the well, the larger more powerful carrier guns can be run on wireline. This may be an efficient and more cost-effective alternative when perforating short intervals. Perforation Cleanout Underbalanced perforating. As previously discussed, underbalanced perforating has been successfully used for cleaning perforations in unconsolidated sands. The method may be most applicable where: • Adequate formation stability permits use of sufficient differential pressure and backflow volume to clean perforation debris and mud from all perforations without sand-up. • Reservoir pressure is near original hydrostatic so that underbalance can be obtained with fluid column. • Perforating is conducted through tubing, limited to one gun run, and followed by consolidation treatment. The rig may or may not remain on location. However, if the rig has been removed, there is a tendency to restrict differential pressure and backflow volume unduly to avoid risk of sand-up. Where 66

reservoir pressure has been depleted, proper design may be difficult because of inaccuracies in estimating actual reservoir pressure at time of perforating.51 Perforation washing. This is a widely used method for removing perforation debris, mud, and formation sand from the perforation tunnel, and from behind the casing (Fig. 3.25). During perforation washing, circulation must be maintained to remove debris from the well. Returns at surface may contain up to 10% sand. Either a “clean” fluid system or fluids with surface filtration systems or a combination of both should be employed for the washing process. Truly clean salt water would normally be lost to the reservoir due to pressure overbalance. However, washed mud, perforation debris, and formation sands and clays entrained by the wash salt water frequently bridge-off the permeable zone and prevent loss. These solids may cause deep permeability damage that is difficult to remove. If bridging does not occur, there will be no support for the cavity formed by the washing operation and the cavity face may cave or slough back against the casing. Soluble bridging material (usually salt, calcium carbonate or oil-soluble resins) used with the brine will permit circulation of debris from the well and support cavity walls to prevent collapse prior to gravel placement. Bridging material will flow from the well during production if it is sized small with respect to gravel pores. Any remaining bridging material can be removed with the proper solvents—lower salinity brine

for salt, acid for calcium carbonate, or produced oil for oil-soluble resins. Use of a non-penetrating fluid for washing may restrict the ability of subsequent fluids to force gravel through perforations and into all cavities behind the pipe, and make it more difficult to obtain a tight gravel pack outside the screen. Therefore, excess fluid may have to be washed from the cavities and/or bridging material solvent may have to be used in conjunction with gravel placement. Care should be taken to prevent swabbing when pulling wash tools. Swabbing action may cause caving of the washed interval. Additionally, precautions should be taken to control the well while retrieving the wash tools to prevent the possibility of a blowout. Acid stimulation. Stimulation using hydrochloric (HCl) and/or hydrofluoric (HF) acids has been used to improve well productivity and injectivity where consolidation treatments or inside gravel packs are applied. Acid treatment is frequently required, particularly when previously mentioned clean-up methods and non-damaging techniques have not been used. Acids have been used effectively in skin removal and some operators believe that perforation debris can be removed or bypassed through acid treatments. Additionally, HCl is used to remove calcium carbonate bridging material. Impairment should be avoided through use of proper fluids and perforation cleaning method. Acid should be applied only to remove unavoidable damage because of the possible disadvantages, including: • Uncertainty that all perforations are open and treated prior to consolidation. • A possible region of reduced permeability in some unconsolidated sands resulting from migratory siliceous fines released as more reactive cementation material is consumed. Production decline after acid treatment is frequently greater than normal. • Reduction in compressive strength of some rock formations in the wellbore vicinity. Use of oil-soluble resin bridging material in conjunction with mechanical perforation clean-up methods may eliminate need for acid, where incompatibilities between acid and formation exist.

Chapter Three Cased-Hole Sandface Completions

Regular mud acid has been effective at volumes of about 50 to100 gal/ft. Spacers should be used (HCl is common) to remove and separate mud acid from any calcium carbonate bridging materials to avoid precipitation of calcium fluoride and from sodium chloride brine to avoid precipitation of sodium fluosilicates.52 Special Perforating Techniques Once thought as simply a means to create holes in steel casing and cement, perforating is a complex element of the well completion design. As wellbore construction and configurations have become more advanced, the design of perforating systems has been brought into better focus by contemporary research and an understanding of basic principles. Advanced perforating systems and techniques have been designed for specialized applications. Three special perforating techniques—oriented perforating, single-trip perforating/ gravel packing, and propellant-assisted perforating—are discussed below. Oriented perforating. The first applications of oriented perforating were in wells with dual or multiple tubing strings. Tools were developed to ensure that guns run in one string of tubing do not perforate other tubulars in a wellbore.53 Today, oriented or selective perforating techniques are becoming more widely used in applications requiring fracturing deviated and horizontal wells, controlling sand production, and solving wellbore instability problems among others. Optimal phasing angles, hole spacing and orientation of perforations facilitate hydraulic fracturing and eliminate the likelihood of sand influx from perforation-tunnel collapse. When perforations are not properly oriented, fractures normally reorient near the wellbore in order to propagate perpendicularly to the minimum horizontal stress, i.e., to align with the maximum horizontal stress. This reorientation near the wellbore creates a complex geometry that can introduce multiple problems: • Increased treating pressures • Increased risk of sudden, near-wellbore, screen outs • Increased risk of multiple fractures • Localized reduced fracture conductivity near the wellbore

• Potential for crushed proppant near the wellbore • Increased risk of proppant flowback • Increased risk of formation sand production. Guns can be oriented using a number of techniques such as: • Mechanical devices • Motors coupled with downhole sensors • Eccentric weights and swivels • Gyroscopes • Wireline orienting tools. Oriented perforating to prevent sand production – Sand prevention incorporates techniques to minimize or eliminate the amount of sand produced and also to reduce the impact of produced sand without mechanical exclusion methods. Oriented perforations may be used to create stable tunnels in poorly consolidated formations thus avoiding sand failure and consequently preventing sand production.54 Additionally, selective perforating can avoid weak zones or formations altogether. If sand production is the main issue to deal with for a given poorly consolidated reservoir, an innovative completion technique using oriented perforating coupled with hydraulic fracturing may be used to minimize or prevent sand production. This technique is based on the fact that a circular hole (i.e., perforating designed to enhance radial flow entry into the wellbore by the spiral phasing of charges in the gun)

should not be introduced to a poorly consolidated formation. However, the hydrocarbon reserve can be reached via a hydraulic fracture. This can be achieved in vertical and horizontal wells, preferably a horizontal well. For a vertical well situation, the well should be drilled close to but not into the sand formation. A 1 ft to 5 ft (0.3 m to 1.5 m) interval is perforated in the boundary layer, then a fracture is created using 180º phasing perforations aligned with the maximum horizontal stress (Fig 3.26). On the other hand, for a horizontal well situation, the well should be drilled in the boundary formation close to, but not into, the poorly consolidated sand reservoir. Place oriented perforations with 0º phasing at the lower side of the horizontal well. Initiate a hydrofracture designed as a tip screenout treatment, using resincoated sand throughout the entire job. The above procedure for sand control is based on the following arguments: 1. Compared to a vertical well, a horizontal well reduces the pressure drawdown for a given rate. The pressure drawdown places increased deviatoric stress on the formation, and if it exceeds the formation strength for a given failure criterion, failure occurs and leads to sand production from the well. 2. Creating a conductive fracture transforms the radial flow into linear flow away from the wellbore and allevi-

Fig. 3.26. Oriented perforating and screenless completions. When combined with oriented perforating and fracturing strategies, novel technologies, such as resin-coated and scaleinhibitor-impregnated proppants (left ), and PropNET fibers (right ), control proppant flowback and sand production to provide effective sand prevention without downhole mechanical screens and gravel packing. 67

Modern Sandface Completion Practices

IRIS dual-valve tool

Upper QUANTUM gravel-pack packer

IRIS dual-valve tool

Screens Bottom packer Perforations

X-Tool explosive gun release

Upper QUANTUM gravel-pack packer Screens

TCP gun Bottom packer

TCP gun Perforating

Gravel packing

Fig. 3.27. Single-trip perforating and gravel packing. A typical assembly includes a TCP gun with an automatic explosive release, a bottom packer, sand-control screens, a gravel-pack packer with a flapper valve, pressure gauges and recorders, firing head and a dual-drillstring test valve. The TCP guns are positioned, fired, released and dropped (left). The assembly is then repositioned so that the screens are across the perforated interval (right). The upper gravel-pack packer is set and gravel is injected behind the screen. The workstring is then disengaged, leaving the packed screens in place. Operations take place in a controlled environment so formations are not exposed to overpressure, LCM or damaging fluids.

ates the fluid convergence of radial flow, ultimately decreasing drawdown pressure for a given rate. 3. Formation failure starts near the wellbore due to the stress concentration created after a wellbore is introduced to the formation. In this method a wellbore does not penetrate the weak formation at all. In addition to oriented perforation, oriented hydrajetting may be considered to create a single continuous initiation path for fracture. In unconsolidated formations, sand consolidation may help as a pre-fracturing stage to 68

ensure creating a fracture rather than ballooning a cavity.55 Single-trip perforating/gravel packing. For conventional gravel packing inside casing, three steps are necessary: 1) set a bottom packer, 2) perforate, and 3) circulate gravel behind gravel-pack screens. Disadvantages include long duration of operations and potential formation damage from fluid loss or lost circulation material (LCM). Designed to help alleviate these disadvantages, perforating guns and gravel pack hardware can now be run in one step. This technique is

a single-trip sand-control method that limits fluid loss, reduces formation damage and saves time (Fig. 3.27). Perforating to control sand production – Sand control utilizes mechanical methods to exclude sand from produced fluids. Perforating for sand control assumes that the production of sand is unavoidable and gravel packing, fracture packs or other mechanical techniques that exclude sand from production flow are needed. Perforating must address adequate underbalance to minimize pressure drop, or skin, and remove loose sand to clean out perforation tunnels for optimal gravel placement and efficient gravel packing. Perforation damage, formation fines and charge debris should be removed before gravel packing. Underbalanced perforating and flow before gravel packing are the best methods to achieve this objective. The maximum underbalance pressure must be selected to avoid perforation collapse and catastrophic sand production during perforating. Perforating with the surface choke open ensures post-shot flow to transport debris into the wellbore. Provisions need to be made to handle transient, finite sand production at surface until the perforations are clean. When pressure drop and flow rate per perforation are low, deeppenetrating charges can be used. Deeppenetrating charges cause less localized damage and debris, and provide a larger effective wellbore radius that reduces pressure drop. As in fracturing applications, perforation diameter needs be 8 to 10 times the gravel diameter. Exposing formations to damaging completion fluids or LCM and chemicals during hydrostatic well-control operations should be avoided. Damage to open perforations was observed in tests on Berea sandstone blocks that were perforated, opened to flow, plugged by LCM and then reopened to flow.56 If a well must be killed, non-damaging brines or mutual solvents are best. In addition to internal gravel packs, perforating plays an important role in external sand-control applications like fracture packing and screenless gravel packs.57 Perforating requirements for fracture packing are the same as for internal gravel packs because it is more important to minimize pressure drop through the pack and control sand production than to create long fractures.

Chapter Three Cased-Hole Sandface Completions

However, efficient proppant placement is required to create an external pack. Big holes with high shot density—12, 16, 18 or 21 SPF—and 60º or 45° phasing maximize flow area and prevent proppant screenout, or bridging, in the perforations. In screenless gravel packs, the formation is consolidated with resin and then fractured. Proppant injected in the fracture prevents the production of formation sand. Because proppant does not fill the perforations, perforating requirements are more like conventional hydraulic fracturing stimulations. The length of perforated interval should be limited. Perforations that do not communicate with the fracture may produce sand and need to be eliminated or minimized. Hole diameter needs to be 8 to 10 times greater than the proppant diameter and perforations with 0° or 180° phasing should be oriented to within 30° of the preferred fracture plane.58 Propellant-assisted perforating. The combined use of propellants and perforating for production enhancement is not new to the petroleum industry, especially for natural completions in competent formations. When used together, the propellant and perforating assembly employs a cylindrical sleeve of gas-generating propellant that is simply slid in place over the outside of conventional perforating guns (Fig. 3.28). It can be run on wireline or in a TCP configuration. The propellant sleeve is ignited by detonation of the perforating charge and, as the propellant sleeve burns, energetic gases are released sending high-pressure shock waves through the casing and into the formation. This method of perforating does not crush the formation rock, therefore reducing formation damage. A paper by Folse et al59 reviews an application for the combined propellant/perforating technique that has been successfully used in unconsolidated sands in the Gulf of Mexico to enhance the placement of proppant during fracpack and gravel-pack treatments while perforating in a balanced condition. According to the case histories, the propellant/perforating technique was used on several formation types; i.e., long intervals, highly deviated, and highly laminated with extreme permeability contrasts, that would traditionally be deemed as high risk for proper sand

placement. In performing this technique, the propellant sleeves are positioned across the lower quality portions of the intervals with low permeability and resistivity to ensure that the perforations in these intervals would be broken down to accept fracturing fluids and proppant during the fracturing treatment consistent with the entire treated interval.60,61 Operators have shown that this technique is effective in both underbalanced and overbalanced perforating situations. With the trend in the industry to reduce cycle time, the elimination of the underbalance/surge process to ensure clean perforations and all the associated rig time in obtaining control of the well following the surge are seen as significant opportunities for rig-time savings. It has also been proven that combining propellant/perforating in a balanced scenario can offer a cost efficient and safe method when used as a near wellbore clean-up tool for pre-frac preparation or high rate water packing. Perforating Summary Today, perforating often encompasses more than traditional running and firing of guns. Perforating systems are an integral part of well completion equipment and completion operations that are designed to perform multiple operations in permanent completions, such as setting packers, pressure testing, perforating one or more intervals and initiating tool functions, all in a single operation. Perforating based on average formation properties and shaped-charge performance is being replaced by a more tailored approach. Because perforating is such a critical element of well productivity, the requirements of each well should be optimized based on specific formation properties. The best way to achieve this is to understand how reservoirs respond to natural, stimulated and sand-management completions. Factors that need to be taken into account include formation compressive strength and stress, reservoir pressure and temperature, zone thickness and lithology, porosity, permeability, anisotropy, damage and fluid type—gas or oil. Perforating systems can be designed using new, sophisticated perforating analysis software programs, which predict perforating efficiency under downhole conditions. To help identify the

Fig. 3.28. The StimGun assembly perforates and stimulates the well simultaneously. It employs a cylindrical sleeve of propellant over a specialty configured, perforating carrier. The pressure wave generated by the perforating charge ignites the propellant. Gas from the propellant enters the newly created perforations, breaking them down and stimulating the formation. 69

Modern Sandface Completion Practices

appropriate gun systems for a specific application, these programs combine modules that estimate downhole penetration, calculate productivity and determine optimal underbalance. With all the tools and techniques that are available to the modern completions engineer, the best perforation designs are always based on specific well requirements to optimize production.

Cumulative retained, %

100 80 60 40 20 D 10 10th percentile (D10) 0 2,000 1,000 500 200 100 50 30 20 Micron

Fig. 3.29. Sand distribution plot from sieve analysis

Fig. 3.30. Effective screen control with coarse, well-sorted material

Fig. 3.31. Eroded screen and base pipe 70

Stand-Alone Screens As discussed in Chapter Two, slotted liners, conventional screens or premium screens can be used alone to control formation sand in open-hole completions. They can also be installed as stand-alone screens in cased holes. As such, only their unique application in cased-hole completions is discussed in the Chapter. Using the D10, or tenth percentile from the sand distribution plot from a sieve analysis, as suggested by Rogers,62 is typical for determining slot width, wire spacing or media rating (premium screens) for a stand-alone screen. The tenth percentile or D10 designation, means that the sieve size would retain 10% of the formation sand and allow 90% to pass through, as illustrated in the sand size distribution plot in Figure 3.29. Here the tenth percentile (D10) size is 785 microns, or 0.030 in. The example in Figure 3.29 applies to sand grains down to 262 microns (0.01 in.) and would retain 77% of the sand. Finer sands and silts would initially pass through the screen. However, as a rubble zone or sand pack develops, they would be trapped by a combination of filtration and bridging on the pore throats of the coarse, well-sorted material. This phenomenon is demonstrated in Figure 3.30 and will likely occur when D40/D90 < 3 and Fines (particles smaller than 44 micron) < 2% by weight.63 In addition, the slotted liner or screen diameter need to be as large as possible. Therefore, stand-alone screen longevity is enhanced by increasing the area open to flow and decreasing annular flow outside the sand exclusion device. This type of design is obviously going to be most effective with very weak, medium-to-coarse- grained, moderately uniform sands that will quickly build up a highly permeable zone around the screen. It is commonly used for protecting pumps in shallow oil wells and especially for heavy oil wells, where technical problems and economics limit the effectiveness of other methods of sand control. Where the sands are somewhat stronger and more uniform, the bridging process becomes increasingly inefficient. At low sand influx rates, most of the grains simply pass through the slots; therefore, it takes a long time for the pack to build up and the slots may become

sand-cut or plugged with grains that are close to the slot size. Moreover, plugging of part of the screen leads to increased velocities and erosion in other slots. To avoid these problems, it is common for screens used in deeper, more uniform sands to be designed with a smaller slot size in order to increase the chances of bridging. If minor or intermittent sand influx is expected, screen openings must be small enough to stop the sand over the majority of the grain size range, so that screen erosion can be avoided before a zone accumulates. Since it is not possible to saw-cut slots below 0.012 in. (305 microns), wirewrapped screens, prepacked screens or premium screens are usually used in this service. Slotted liners and conventional screens are relatively low-cost sand control methods, and are reasonably successful in medium-to-coarsegrained, low-strength sands. Since they may have to be replaced in time, the outside diameter should be selected to permit washover operations. The OD should therefore be at least 1 in. or, preferably, more than 1.5 in. smaller than the production casing drift ID; and centralizers should be collapsible. There are two major problems with the use of plain screens inside perforated casing: • There is a tendency for the screen to be cut-out by sand blasting from a few highly productive perforations during buildup of the pack zone (Fig. 3.31). This can be minimized by slowly bringing the well through the critical sand producing rate. • The perforation tunnels become filled with formation sand, which imposes an additional pressure loss due to the limited cross-sectional area over which linear flow occurs through the cement and casing. In the higher rate oil wells and in gas wells, this not only increases the Darcy skin factor, but may also introduce a rate-dependent skin due to turbulence. These effects can be minimized by perforating at high shot densities with large diameter holes. Both of these problems become increasingly serious as flow rates and gas-liquid ratios (GLR) increase. Therefore, while conventional screens are often effective in low-rate oil wells (and particularly in heavy oil wells producing from highly permeable, coarse

Chapter Three Cased-Hole Sandface Completions

sands), their performance in flowing oil and gas wells is often disappointing. One non-standard application for screens is for keeping marginal, minor sand influx out of sensitive wells (e.g., subsea producers, high-rate gas wells, etc.). In this situation, the perforations are essentially stable and the screen acts as a downhole fitter, forcing what little sand is produced to be deposited in the rathole. This seems to be the logic behind the screens used in the Frigg field in the North Sea, for example.64 However, once the rathole fills up, or sand production becomes significant, gravel packing is often needed. Prepacked screens and premium screens are more suited to this type of service than conventional screens, especially in cased-hole, perforated completions.

Gravel Packing No special drilling operation is required for a cased-hole gravel pack. The casing is cemented conventionally at TD. The completion intervals are then perforated with high density, large diameter perforations capable of penetrating the damaged zone. The perforation damage is cleaned out behind the pipe by back flushing, underbalanced perforating, back surging or perforation washing. The screen is run and the gravel pumped (using the crossover circulating technique) into the perforation tunnels and casing/screen annular area. The key to success is the creation of a high permeability path through the casing, cement and damaged zone to permit effective packing, out against the native formation. The crossover circulating technique is the most common method used to place the gravel in the perforations and around the screen. The gravel-pack equipment and service tools allow circulating the gravel down the workstring above the packer and into the screen/casing annulus below the packer with returns coming back up the washpipe and up the workstring/casing. The fluid used to carry the gravel can either leak off to the formation or be circulated out of the hole through the wash pipe (Fig. 3.32) depending on the position of the service tools and the condition of the perforation in terms of accepting fluid leak off. In theory, open-hole gravel packs result in better productivity than inter-

nal gravel packs, especially at high rates and/or with viscous crude oil. In practice, they are often more difficult to effectively plan and install. Moreover, improved squeeze-packing techniques and perforation/cleanout methods have greatly improved the success of casedhole gravel packs. Cased-hole gravel packing, offers more flexibility, selectivity, planning time and cost/rig-time savings. An illustration of a successfully placed cased-hole gravel pack is shown in Figure 3.33. Cased-hole gravel packs are one of the most common methods for controlling the production of formation sand in oil and gas wells. Cased-hole completions are more popular than openhole gravel packs for several reasons.65 First, if the operator is not aware of a need for sand control when the well is drilled, a perforated casing completion can be installed with the gravel pack being installed later if the need arises. Also, cased-hole completions are often required for the upper zones of multizone completions. In addition, water or gas exclusion is easier in a cased-hole completion, and wellbore stability is more easily maintained. One negative aspect of the cased-hole completion is low productivity unless gravel is placed through and outside the perforations properly. In either type of gravel pack, the gravel-pack sand or substitute must be properly sized if sand is to be controlled and permeability impairment avoided.

Fig. 3.32. Schematic of cased-hole gravel pack

Fig. 3.33. Successfully placed cased-hole gravel pack 71

Modern Sandface Completion Practices

Damaged zone

Void in Incomplete annular pack perf filling

over the screen, should it be necessary to remove it. A successful cased-hole gravel pack requires that the perforations or fractures extending past any near-wellbore damage (as well as the annular area between the OD of the screen and the ID of the casing) be tightly packed with gravel. Because of likelihood of incomplete perforation packing in a single placement process (Fig. 3.34), casedhole gravel packing is sometimes done as a two-stage process. The first stage is packing the perforation tunnels with gravel, which is referred to as a perforation prepack. The second stage is packing the annulus between the screen and the casing ID with the same gravel.

Fig. 3.34. Incomplete perforation packing equals poor communication with native reservior

Perforation Prepacking Several completion techniques have been developed to help alleviate the problems associated with cased-hole gravel packs. One commonly applied technique, which has demonstrated to be quite effective, is perforation prepacking.66 Perforation prepacking can be done below the fracture pressure or above the fracture pressure.

3,000

System analysis

Pwf, psi

2,250

L k = ______ n Lj k j=1 j

∑

1,500

#1 #2

750

#4

#3

0 0

2,500

5,000

7,500

10,000

Production, blpd Case k, md #1 120,000 #2 900 #3 300 #4 150

Q, bpd 4,439 2,121 1,064 609

Skin 0 14.5 40 80

Fig. 3.36. Effect on productivity of formation material partially filling perforations

Fig. 3.35. Prepacked perforations 72

Techniques to do this were discussed in Chapter Two, along with establishing the proper slot width of slotted liners and wire spacing of conventional screens. There is one principle difference in screen designs between openhole and cased-hole gravel packs. The radial difference between the OD of the screen and the casing ID should be at least one inch and in an open-hole that annular distance is two inches. The oneinch clearance inside casing is large enough to reduce the chance of forming a gravel bridge during gravel placement and still allow sufficient room to wash

Prepacking below frac pressure. This process involves placing gravel through the perforation tunnels, into the cavity created at each perforation behind the casing, Figure 3.35. Prepacking controls fluid loss, increases perforation filling efficiencies and decreases drawdown pressure drop through the perforations tunnels by preventing formation sand filling the tunnels. Filling the perforations with gravel is the key to obtaining high productivity from the well. In an unconsolidated formation, any perforation not filled with gravel will be filled with formation sand. Therefore, the greatest potential for flow restriction is at the perforations, where the flow pattern becomes linear instead of radial. A major challenge of packing operations is to transport gravel through the perforations in order to pack the entire area around the perforation tunnels with very high permeability gravel. Pressure drop through the perforation tunnel is minimized if the tunnel is filled with high permeability gravel as opposed to formation sand. Tables 3.14 and 3.15 compare the calculated pressure drops in different perforation

Chapter Three Cased-Hole Sandface Completions

diameters for formation, sand-filled perforations and for gravel-filled perforation tunnels. These tables dramatically emphasize the critical importance of complete perforation filling during the gravel placement process.67 The technique for making these pressure drop determinations is described in the next section. The practical effect of the productivity lost from the increased pressure drop caused by partial filling of perforation tunnels with formation material has been described in a recent publication68 and is illustrated in Figure 3.36. When it is considered that prepacking can be defined as any method that intentionally places gravel into the perforation tunnels and out into the formation, it becomes obvious that several techniques should be available to accomplish this. Filling of perforation tunnels can be accomplished either with a dedicated operation prior to running the gravel-pack assembly, or it can be accomplished by forcing injection into the perforations during gravel packing. So, in evaluating cased-hole, gravelpack completion techniques the distinction becomes: (1) was a dedicated prepack performed, (2) was the prepack performed with the gravel-pack assembly in the hole, or (3) was a circulating gravel pack performed with limited leak-off to the formation. Figure 3.37 shows the open-ended tubing method or prepacking perforations before installing a screen. Tubing can be reciprocated through gravel while a bradenhead squeeze is applied, or a packer can be run to squeeze perforations.69 The applied technique is normally dictated by well parameters such as excessive fluid loss, extended rat hole area, reservoir acid sensitivity, zone length, etc. An additional concern that must be addressed is which carrier fluid was used for the prepacking operation. A choice might be an acid-prepack method (a combination stimulation and sand control procedure that can help yield high productivity). One of the most beneficial aspects of the acidprepack method of sand control is the combination of damage removal, or breakdown by the acid, and the excellent sand control initiated by the prepacking gravel. Some diverting technique may need to be employed to insure coverage of the entire perforated

Flow Rate (bpd/Perforation)

3/8 in. Diameter Perforation

Pressure Drop (psi) 1/2 in. Diameter Perforation

3/4 in. Diameter Perforation

1 10

450 27,760

190 9,280

64 2,091

Table 3.14. Pressure drop in packed perforation with 1,000 md formation sand

Flow Rate (bpd/Perforation)

3/8 in. Diameter Perforation

Pressure Drop (psi) 1/2 in. Diameter Perforation

3/4 in. Diameter Perforation

1 10 25

2 55 272

1 21 99

0.4 6 25

Table 3.15. Pressure drop in packed perforation with 119,000 md 20/40 mesh gravel

interval.70 With damage removed from the formation face and the perforations, the carrier fluid can easily leak-off and allow the gravel to more effectively pack the perforation tunnels. Prepacking above frac pressure. One of the main detriments to prepacking below fracture pressure is that gravel can only be placed into spaces created during the perforating and perforation cleanup operations. If this amount of penetration into the formation does not extend completely through the nearwellbore damaged zone, restricted well productivity will result. To overcome this difficulty, it becomes necessary to remove the damage with acid. As just demonstrated, while this is possible, it is not always easy to accomplish. Another technique to eliminate the effects of the damaged zone is to bypass it rather than to attempt to remove it. This can be accomplished by hydraulically inducing a fracture. Techniques available to create these fractures include a high rate water pack (HRWP) or a full-scale frac pack (discussed later in this Chapter). The HRWP technique was pioneered by Exxon71,72 and later refined by Arco/Vastar (now BP Amoco).73 These early jobs were originally placed in two steps: 1. Braden-head prepack with a high-viscosity slurry pack (15 ppa gravel concentration mixed in 80 lb/1,000 gal HEC). 2. Circulating gravel pack with a low-viscosity water pack. The circulating gravel-packing process places gravel at low concentrations

Packer location

Tubing Cement

Perforations

Perforation tunnel Unconsolidated formation Plug depth Casing

Fig. 3.37. Prepacking perforations with openended tubing

(1 to 2 ppa) into the perforations and around the gravel-pack screen. The gravel is mixed with completion fluid. This is accomplished using a sand injector located on the high-pressure, downstream side of the pumping unit. The sand is inserted in the treating line intermittently in 2 ft3 batches. Pump rates are 2 to 3 bpm. The gravel pack service tool is placed in the circulating position (see Fig. 3.47). The gravel travels down the drill pipe, through a crossover port around a cylindrical gravel-pack screen. 73

Modern Sandface Completion Practices

Damaged zone

Gravel pack

Fracture

Screen

Fig. 3.38. High rate water pack (HRWP) schematic

In the late 1980s, water packs (Step 2 above) were refined through new equipment and placement techniques. Service companies developed more sophisticated blending equipment to proportion gravel and water (brine) at consistent concentrations and in large volumes. Surface equipment is reviewed in Chapter Four. In a HRWP (Fig. 3.38) a fracture with a length between 5 and 15 ft (1.52 to 4.57 m) is created with a low-viscosity, brine carrier fluid. Pump rates are higher than conventional gravel packing operations, but usually lower than for a frac pack. Typical pump rates are in the range of 8 to 12 bpm. Proppant loading is held constant between 1 and 2 ppa, and total job size is typically from 100 to 150 lb/ft, which provides 2-3 lb/ft2 of fracture conductivity. These treatments can be multi-staged to further enhance the ability to effectively treat several sand subintervals with a single treatment. This will better the chances of proppant coverage into all perforations and greatly increase the sand placement behind pipe. The HRWP is designed to be pumped above fracturing pressure, so that a short fracture (<15 ft) [4.57 m] is placed through the damaged zone around the wellbore. Fluid used is generally completion fluid for the pad as well as the carrier fluid. Returns can be eliminated if the well has a deviation less than 60º. A good reference is available to evaluate the various injection pressures recorded over the course of the HRWP operation.74 Usual steps in a HRWP treatment consist of the following: • Pretreatment • Acid treatment • Step rate test • Pad • Proppant stages 74

• Displacement • Screenout • Reversing out. A screenout pressure of 1,000 to1,500 psi is only a result of Darcy’s Law linear pressure loss. As the gravel builds above the highest circulating point in the wellbore, fluid is forced through the pack sand resulting in the pressure increase.75 The following is a method that can be used to estimate the gravel height above the top of the screen when the fluid is in laminar flow. 0.00078 kAP H= µq

Where: H = gravel height above screen, ft P = screenout pressure, psi k = gravel permeability, Darcy A = casing/blank annulus capacity, ft3/foot µ = carrier fluid viscosity, cp q = flow rate at screen, bpm Knowledge of the gravel height above the screen top can aid in determining the pack factor, which is discussed later in this Section. HRWP (a one-step placement technique) should be considered whenever a frac-pack treatment is not possible. Conditions to one-step gravel placement in cased-hole completions as an above-frac-pressure prepacking treatment should include: • Long intervals with small casing sizes (<5-1/2 in. OD) • Frac equipment not available • Weak casing (where there is a risk of casing failure into undesired zone such as water or gas cap) • Zones where height growth jeopardizes the integrity of the completion • Wells where economics are prohibitive (such as injection wells or water source wells) • Areas where HRWP have been proven successful (i.e., acceptable sustained completion efficiency) (wells are typically clean non-laminated sands with little presence of migrating clays and fines). It has been reported that over 50% of the HRWPs can have skin values less than five as compared with 85% of the frac packs. The main difference is in favor of the frac packs with longer sustained productivity and lack of fines

migration into the near wellbore area. In addition, a recent possible improvement in HRWP might be the application of a surface-modification agent to the proppant.76 Halliburton’s SandWedge technology chemically modifies the surface of proppant grains. This increases its porosity and permeability, helps control fines migration and enables the use of larger size proppant for improved pack conductivity. Water Packs As its name suggests, a water pack uses water as a carrier fluid for gravel-pack sand. Because the polymer residue from slurry packing could potentially damage formation permeability, water packs have become a popular alternative to slurry packing (discussed next) in recent years. Water packs can help form very tightly packed annular packs, but they have a high leak-off rate in highpermeability zones, which can result in bridging in the screen/casing annulus. This bridging can then cause premature screenout of the treatment. Although the term water pack suggests that only water is used for proppant transport, lightly gelled slurry (25 lb/1,000 gal HEC) is frequently pumped.77 The danger that zonal isolation may be compromised is possible with high-rate water packs, just as it is with frac-pack completion services. Tracer log data from some waterpacked wells indicate that incomplete entry of the tracer over the entire interval height has occurred, leaving only the high-permeability area of the zone packed. Therefore, wells with formations that can sufficiently resist fracture height growth are candidates for highrate water packing. Since the pumping rate, fluid volume and pressure in this type of completion are large, the tools used must withstand the more severe well conditions. If tools are not properly selected, downhole equipment failures could be caused by collapse and flow erosion. Both the fines in the fluid stream and the return flow rate must be controlled so that the possibility of screen erosion during the packing operation is limited. Slurry Packs The concept of Slurry Pack was developed by Sparlin to avoid the permeability

Chapter Three Cased-Hole Sandface Completions

reduction associated with formation sand/gravel intermixing. The procedure consists of pumping gravel at high concentrations in a viscous transport fluid.78 The slurry is usually batch-mixed in a blender or paddle tank before it is pumped. Although the fluid can be either water or oil-based, hydroxyethyl cellulose (HEC) viscosified brine is the usual choice.79,80 The typical polymer loading is 60 to 80 lb/1,000 gal. In some situations, the gelled fluid is crosslinked so that it creates very high viscosities. The concentrations of gravel usually pumped with slurry-pack fluids are about 10 lb/gal. In certain situations, however, concentrations have ranged from much less than 10 to more than 18 lb/gal. When these high-density fluids are pumped, the fluid and gravel tend to move as a mass. Compared with the low-density conventional gravel-pack fluid, these slurry systems have significantly greater gravelsuspending capabilities. Depending on well conditions, pump rates normally range from 1/2 to 4 or 5 bpm when gravel is placed around the screen. When high-viscosity fluids transport gravel into the completion interval, a reserve volume must be specified. To allow for subsequent resettling, this volume is usually higher than the reserve volume required for low-viscosity fluids. Well conditions affect the gravel reserve volume when viscous fluids are used. Before the gravel is pumped, the service provider should calculate the theoretical amount of gravel required to pack the annulus around the screen and the amount of gravel reserve. Placement should be approximately 100% under ideal conditions. Depending on the additional gravel placed through the perforations, possible bridging in the tubulars or pumping conditions, the amount of gravel placed could differ from the theoretical volume. If the amount of gravel is considerably less, premature bridging has probably occurred. Therefore, before the well is placed on production, gravel must be settled around the screen and additional gravel must be pumped. When high-viscosity fluids circulate gravel around the screen, the pump rate should be low enough that the viscous drag forces do not exceed the gravitational forces once the slurry has reached the completion interval. If the viscous forces become dominant, the gravel will

Fig. 3.39. Void form while slurry packing

be drawn into the screen rather than settling to the bottom of the well. As a result, the gravel will pack radially outward from the screen, possibly resulting in premature indications of a completed gravel pack. This type of packing geometry and sequence is not desirable; ideally, the gravel should dehydrate from the bottom of the completion interval upward. The potential for non-uniform packing is one of the significant disadvantages of slurry packs. Therefore, the actual volume of gravel pumped should be carefully compared to the theoretical volume. This is illustrated in Figure 3.39. If the pumped-gravel volume is much less than the theoretical volume when high-viscosity fluids are used, the gravel should be allowed to settle before additional gravel is pumped for completing the pack. An upper tell-tale screen should be avoided when high-viscosity fluids are used for circulating gravel because gravel will probably screenout on the upper tell-tale. This screenout could prevent gravel placement over the main completion interval. A lower tell-tale screen should be used for slurry packing. This lower tell-tale allows the sandladen slurry to be effectively placed across the payzone to be gravel packed. Because of gravel settling, part of a gravel reserve volume will be filled if well deviations do not exceed approximately 60°. A lower tell-tale screen is usually used with slurry packing. The washpipe is attached to the bottom of the screen section between the lower tell-tale and the primary screen.

Slurry packs are effective in certain cases where only low horsepower pumping equipment is available or batch-mixing equipment is preferred. Frac packing has replaced the application of flurry packing in most cases. Well Productivity It is important to briefly discuss the effects that perforations can have on well productivity, especially in a gravelpacked well. The productivity of a well is usually discussed in terms of a productivity index (PI, or J). The productivity index, J, for a well is defined as the ratio of the flow rate, q, to the difference between the average reservoir pressure, pr, and the bottomhole flowing pressure, pwf as follows: q p r − p wf

J=

bpd psi

The denominator of the above expression, pr – pwf, is referred to as the drawdown. For laminar, radial flow of a singlephase liquid with viscosity, m, in a reservoir of height, h, the relationship between drawdown and flow rate, q, is given by Darcy’s law, as follows: J=

q = p r − p wf

kh 141.2µB ln( re / rw ) − 0.75 + S

[

]

bpd psi

Where: B = formation volume factor, v/v 75

Modern Sandface Completion Practices

108

= 20%

107 = 30%

Inertia coefficient, (ft-1)

106

105

104

103

102 0.1

20/40 U.S. mesh Sand 20/40 U.S. mesh Ottawa Flint 20/40 U.S. mesh Glass Spheres Test points from previous gravel pack tests 1.0

10 100 Gravel permeability, k (Darcy)

1,000

Fig. 3.40. Relationship between inertia coefficient and gravel permeability

Fluid Viscosity Typical gravel concentration Typical pump rate Tell-tale screen used

HEC Gel

Brine

300 - 750 cp 10 - 15 ppg 1 - 4 bpm Yes

1 -2 cp 1 - 3 ppg 4 - 5 bpm No

Table 3.16. Comparison of HEC slurry pack and brine water pack carrier fluids

µ = fluid viscosity at reservoir conditions, cp k = effective permeability of reservoir to fluid, md re = drainage radius, ft rw = wellbore radius, ft A deviation from the logarithmic pressure change with radial distance from the well can be expected in the near wellbore region and is termed skin effect. Commonly, an additional pressure drop or positive skin is observed. This is generally the result of formation damage or ineffective or incomplete perforation of the payzone. Many effects can combine to cause this sort of damage. Some of the most common are: • Completion/workover damage (as a result of plugged perforations, solids deposition in the pores, swollen 76

shales, clay or scale precipitation, water blockage, etc. This results in a zone of reduced permeability around the perforations) • Perforation efficiency (in terms of the length of perforation, shot density, phasing, perforation diameter, and, most critically, the extent and permeability of the crushed zone also affects the skin) • Drilling damage (although commonly cited as the cause of skin, it is much less critical now that high-powered perforating guns can fully penetrate the damaged zone) • Turbulent or rate-dependent nonDarcy skin (which is common in gas wells and high-rate oil wells. This effect is generally linear with flow rate and is best determined by multirate testing. This effect dramatically

increases with partial penetration and is claimed proportional to [h/hp]2) • Pressure losses in the completion (which appears as an additional skin effect-especially in cased-hole gravel packs where both Darcy linear flow effects and non-Darcy effects can be expected) • High liquid gas ratio (> 100 bbl/mmcf in gas wells) • High GOR (> 1,000 scf/bbl in oil wells) • Two or three-phase production in reservoir (Pr > Pbp; Pwf < Pbp) • High drawdown (Pr - Pwf > 1,000 psi) • High flow rate (> 20 bpd/ft) • Inadequately packed perforations (cased-hole gravel pack completions; poor formation/gravel interface due to mixing). Negative skin factor may be caused by: • Zone of increased permeability around the wellbore (due to acidizing, underreaming, sand production, or deep perforations) • Hydraulic fractures (causing linear flow patterns in highly permeable fractures) • Anisotropic reservoirs (causing nonradial flow patterns) • Horizontal/deviated wells (resulting in an increased amount of sandface being exposed compared to a vertical well; essentially this can be considered to be the inverse of partial penetration). Thus, the effect of a gravel pack (and/or the efficiency of the gravelpacking operation from a production viewpoint) is seen in terms of a variation in skin factor. Alternatively, we can look at the ratio or deviation between the well's actual productivity (Ja ) and the ideal productivity of an equivalent fully penetrating open-hole completion with zero skin (Jo ), which can be computed theoretically. Investigations have been done illustrating methods of theoretically calculating the various skin effects, especially for gravel-pack design and performance prediction – the simplest form being the computation of the additional pressure drop over the perforation tunnel under Darcy and non-Darcy conditions.81 Pressure calculations can be made using the following equation and the β-factor pIot (Fig. 3.40) reported by Saucier:82

Chapter Three Cased-Hole Sandface Completions

2  µL   βρ     βρ   -13 ∆p =      +  0.1x10 βρL     A   1.127 k   A    

(

)

Where: A = cross-sectional area of perforation, sq ft B = formation volume factor, v/v β = inertia (turbulence) coefficient, ft -1 (Fig. 3.40) k = permeability of fill material, Darcy L = length of perforation tunnel, ft q = production rate, bpd ρ = fluid density, lb/cu ft µ = fluid viscosity under downhole conditions,cp ∆p= pressure drop, psi The calculated data, shown earlier in Tables 3.14 and 3.15, demonstrate the need for high perforation density when high production rates are desired through small gravel, plus the importance of avoiding formation sand influx into the perforation tunnels. While the cased-hole gravel pack inevitably results in some loss of productivity, the pressure losses across an open-hole pack will probably be less than what would have occurred through the equivalent section of formation prior to underreaming. Maximizing gravel permeability is therefore not so critical in open-hole packs. They have a greater tolerance to inadequate design and installation practices. Carrier Fluid Selection A variety of fluids have been used as gravel-carrier fluids for gravel-packing operations include brine, oil, diesel, crosslinked gels, clarified xanthum gum (XC) gel and hydroxy-ethylcelluse (HEC) gel, and foam. The most commonly used fluids have been brine and HEC gel. Gravel packs performed with brine carrier fluids are referred to as water packs or conventional packs. Gravel packs performed with HEC gel carrier fluids are referred to as slurry packs or viscous packs. Table 3.16 is a comparison of HEC gel (also referred to as slurry pack) and brine, or water-pack characteristics in regards to their use as gravel transport fluids. When using HEC, the gravelpack sand is influenced primarily by viscous forces (i.e., the gravel is suspended by the gel). When using brine

Fig. 3.41

Fig. 3.42

Fig. 3.41. Water pack in gas well - 7,600 ft depth, 51° deviation, 42 ft net perforations Fig. 3.42. Water pack in oil well - 3,600 ft depth, 67° deviation, 76 ft net perforations

as a transport fluid, the gravel is influenced primarily by gravity forces (i.e., the gravel settles quickly). Hence, higher pump rates may be required to cope with settling in some situations as Table 3.16 suggests. Slurry packs, which were introduced earlier in this Section, are used to transport sand concentrations of 4 to 15 ppg. The main advantages to this type of system are that a minimal amount of water is used to pump the slurry and the pumping rate can be slowed so that gravel and formation sand intermixing is minimal. The low leak-off rates and the limited amount of water used in this system can also be a disadvantage. Slurry packing can leave voids in the annulus pack and can allow incomplete perforation tunnel packing. Water packs, pumped at 2 to 5 bpm, use brine as a carrier fluid for gravel. In recent years, water packs have become an increasingly popular alternative to slurry-pack methods using HEC and other polymers that can damage formation permeability. Water packs can form very tight annular packs. One disadvantage of water packs, however, is their high leak-off rate in high-permeability zones, which can cause bridging in the screen/casing annulus. This bridging can cause a premature screenout of the treatment if not used in conjunction with an Alternate Path screen. An alternative to the water pack is the high rate water pack (HRWP),

which is pumped at 5 to 25 bpm and above the frac pressure. This technique will be discussed more completely later. But briefly, it was developed to enhance gravel placement into the perforations to obtain higher completion efficiencies than water packs pumped at lower rates. The main objective of annular gravel placement is to effectively pack the annulus between the screen and the casing or the open hole. For cased-hole completions, as mentioned already, an added objective is to pack the perforations with gravel since the latter significantly improves well productivity and longevity. In addition to perforation packing, the quality of the pack in the screen/casing annulus is important regardless of whether the well is completed open or cased hole. Figures 3.41, 3.42, 3.43 and 3.44 show gravel-pack log examples from actual wells where both water packs and slurry packs were used. These logs indicate complete annular packing when using water packs. The gravel packs performed with a slurry pack show the presence of large voids in the annular pack which, if not repaired, will result in formation sand production. Gravel-pack evaluation techniques are discussed in Chapter Four. Field Evaluation A common approach to qualitatively assess the results of a gravel pack is to 77

Modern Sandface Completion Practices

70 56

50

45

40 30

30 24

26

(6)

(75) (3)

24

10 0

New gas

(140)

20 (208)

Gravel placement, lb/ft

60

65 58

(14)

(82) (7)

Old gas New oil Well type

Old oil

Brine carrier fluid Viscous gel carrier fluid ( ) Number of zones

Fig. 3.43

Fig. 3.44

Fig. 3.43. Water pack in oil well - 12,800 ft depth, 68° deviation, 50 ft net perforations Fig. 3.44. Water pack in oil well - 13,600 ft depth

Fig. 3.45. Perforation pack factor as function of well type

300

Gravel pack factor, lb/ft

250

200

150

100

50

0 .05-.1 .11-.2 .21-.3 .31-.4 .41-.5 .51-.6 .61-.7 .71-.8 .81-.9 .91-.1 1.1-2 2.1-3 3.1-4 4.1-5 Leakoff rate, gpm/perforation

>5

Fig. 3.46. Leak-off rate effect on perforation filling efficiency

determine the “pack factor”. The pack factor is simply a measure of the quantity of gravel placed behind casing during the gravel-packing operations. The pack factor is calculated using a material balance as follows:83 PF =

Vt − Vcp − V s − Vb − Vr Hn

Where: PF = perforation pack factor, lb of gravel/ft of perfs Vt = total amount of gravel pumped during prepacking and gravel packing, lb 78

Vs = total amount of gravel filling the screen and casing annulus, lb Vb = total amount of gravel filling the blank and casing annulus, lb Vcp = total amount of gravel filling casing after prepacking, lb Vr = total amount of gravel reversed out of well after prepacking and gravel packing, lb Hn = net perforated interval, ft

While the pack factor does not provide strong correlation to well performance, it does provide information upon which comparisons of perforation filling efficiencies of different carrier fluids can be made. Figure 3.45 is a presentation of pack factor for four general classes of wells, old and new oil wells and old and new gas wells. This plot indicates that regardless of the well type, water-pack fluids are capable of placing more gravel behind casing than are slurry packs. Similar results can also be recognized as a function of interval length and well deviation. These results combine to offer strong support that water-pack, low-viscosity carrier fluids are actually more efficient in filling perforation tunnels than are the gelled slurry-pack fluids. Figure 3.46 illustrates that, although some scatter is present, there is a benefit of increased injection rates when using brine to carry gravel into perforation tunnels. These data suggest that the best practice for prepacking perforation tunnels, especially when packing below fracture pressure, is to inject the brine/gravel slurry at the maximum rate practical. Because perforation filling with gravel is so important, it is recommended that the prepacking operation be carried out at the earliest possible opportunity (i.e., immediately after perforating). In addition to helping control fluid loss, prepacking immediately after

Chapter Three Cased-Hole Sandface Completions

perforating affords two opportunities to place gravel in the perforations (i.e., during the prepack and during the gravel pack). Although this method may require an additional trip to clean out the well prior to gravel packing, the improved gravel placement typically outweighs the additional cost associated with the additional wash trip. Gravel Pack Methods Various gravel-pack completion methods involve a wide assortment of equipment that remains in the well as part of the completion after the gravel placement operations are complete. The equipment discussed below does not represent all the types that are available, but does represent a typical gravel-pack completion. The equipment design recommendations discussed below are just that – recommendations. It is important to remember that certain well conditions may require compromises in the type and design of gravel-pack equipment that can be run. The compromises must be made in light of the risks they create and certain compromises will be preferable to others. Another important concept to remember is that there may be several different, yet equally effective, ways to complete a well. A singlezone gravel may be equipped as illustrated in Figure 3.47. The sump packer is run with a wireline setting tool and positioned with a casing collar locator (CCL). The sump packer can also be set on pipe with a hydraulic setting tool. When run on pipe, it must be positioned with wireline using a radioactive marker (CCL and RA tag). It is usually set 8 to 12 ft (2.44 to 3.66 m) below the proposed perforations. This point becomes the reference point for subsequent bottom-hole assemblies (perforating guns and gravelpack assembly). The well is typically perforated using tubing conveyed perforating guns (TCP). After perforating, the guns are removed (or can be left in the hole for one-trip perforate and pack technique, which is described next) and the following is run in tandem: • Seal assembly • Gravel pack screen • Blank Pipe • Gravel pack packer • Service tool. The gravel-pack packer is set hydraulically with applied surface

pressure. This is accomplished with a service tool (Fig. 3.48) placed inside the gravel-pack packer. The service tool provides a means to set the gravel-pack packer and a means for directing the fluid flow with respect to the wellbore. One-Trip Perforate and Pack System The one-trip perforate and pack system (Fig. 3.49) provides the versatility and time savings of running a perforating assembly with a retrievable gravel-pack packer/production packer in a single trip. It can be used in applications for gravel packs or frac packs. Since perforating and packing are done in a single trip, rig-time savings can be substantial. This system should be used to perforate intervals up to 50 ft (15.24 m) long with well deviation angles less than 45°. At deviation angles over 45°, spent perforating equipment and debris may not fall completely to the bottom of the well, making operations difficult.

QUANTUM service tool

QUANTUM GP packer

Ported housing Sealbore housing

Circulating (pre-perforating) position. From the bottom up, the components of the one-trip perforate and pack system are the perforating guns, automatic-release drop-bar firing head or pressure-activated firing head, reciprocation-set packer (without an integrated equalizing bypass), bypass valve, lower O-ring sub or seal sub, tell-tale screen, O-ring sub, production screen, blank, ceramic flapper valve and the retrievable gravel-pack assembly. A radioactive marker (RA tag) is normally run one joint above the multi-position service tool. This marker provides a stimulus for the gamma-ray depth correlation tool that is later run on wireline. Perforating position. The downhole assembly previously discussed is run to the desired depth. Wireline is then run through tubing to provide positive depth correlation. The assembly, with the aid of the wireline correlation, is spaced across the zone of interest and the reciprocation-actuated GO packer is set. The bypass valve above the GO packer is opened and diesel or nitrogen is pumped to displace the packed-off area and provide the desired pressure for underbalanced perforating. The bypass valve is then closed to isolate the annulus above the GO packer. When the downhole environment is ready, a drop bar is dropped down the

Locating collar Check valve

Safety shear sub Screen Perforations

Casing Seal assembly

Sump packer

Running in/setting QUANTUM packer

Fig. 3.47. Downhole equipment for single gravel-pack completion 79

Modern Sandface Completion Practices

tubing to fire the perforating guns. Upon firing, the guns are released and fall to the bottom of the hole. A predetermined amount of formation fluids are produced to clean the perforation tunnels. The bypass valve is then reopened and the hydrocarbons are flowed out of the tubing. Before retracting the GO packer the bypass valve is shut and pressure is applied to the annulus. This annular pressure opens the annular bypass valve while rig pull is applied to release the GO packer. The annular-pressure-operated bypass valve prevents a possible fluid lock from occurring in the system. After the GO packer releases, the entire assembly is lowered until the screen is properly positioned across the perforated interval. Then, the GO packer is reset and the gravel-pack packer is set. The downhole tool assembly is now ready for the gravel-pack portion of the perforate and pack application. Squeeze position. The squeeze position of the multi-position service tool allows the gravel-pack media to be pumped downhole into fractures, perforations and the annular pack area. Two functions are actuated by a setting dart that is dropped down the tubing string at the beginning of the squeeze stage. The setting dart first allows the packer to be set and tested against the pressure applied to the annulus. Then, by using rig pull and pressuring the tubing, the dart is forced farther down the tool where it will seat and block the gravelpack ports. Pressuring the tubing string again opens the gravel-pack ports and rig weight is applied to lower the service tool into squeeze position. The setting dart now functions as a plug for gravel packing and as a ball check valve to prevent fluid loss when the tool is in the circulating and lower circulating positions. Lower circulating position. Rig pull is applied to the downhole assembly to move the multi-position tool from the squeeze position to the circulating position. Returns are collected at the screen and flow up the washpipe. Circulating gravel

Reversing out excess gravel

Fig. 3.48. Schlumberger downhole gravel-pack assembly 80

Producing oil and gas

Pack completed. When the gravel-pack portion of the perforate and pack application is completed, the service tool is retrieved from the well. As the washpipe is pulled up hole it releases a prop

Chapter Three Cased-Hole Sandface Completions

from the flapper, allowing the flapper to seat. The formation is now isolated from the wellbore fluids.

Frac Packing Frac packing was first discussed in Chapter Two as it applied to open-hole sandface completions and was briefly discussed in the previous section. Frac packing is a process that involves pumping gravel or proppant into the perforations at rates and pressures that exceed the frac pressure of the formation. The intention is to bypass any near-wellbore damage remaining from the drilling/perforating phase of operations. A procedure referred to as tip screenout (TSO) is used to achieve a high sand concentration in the nearwellbore area. Frac packing is an alternative that should be considered during development planning for fields that produce sand. As a percentage of sand-control treatments and in terms of total jobs, frac packing is growing steadily. Use of this technique increased tenfold—from fewer than 100 jobs per year during the early 1990s to a current rate of almost 1,000 each year. In West Africa, about 5% of sand-control treatments are frac packs, and operators frac pack at least 3% of the wells in Latin America. Advances in stimulation design, well completion equipment, treatment fluids and proppants continue to differentiate frac packing from conventional gravel packing and fracturing. US operators now apply this sand-control method to complete more than 60% of offshore wells (Fig. 3.50). Shell used the term frac pack as early as 1960 to describe well completions in Germany that were hydraulically fractured prior to gravel packing.84 In current usage, frac packing refers to tip-screenout fracturing treatments that create short, wide fractures and gravel packing around sand exclusion screens, both in a single operation (Fig. 3.51). The result is short but wide to extremely wide fractures. While in more traditional, unrestricted fracture growth an average fracture width of 0.25 in. (0.64 cm) would be the norm, in TSO treatments, widths of 1.0 in. (2.54 cm) or even larger are commonly expected. These highly conductive propped fractures bypass formation damage and alleviate fines migration by

Fig. 3.49. Halliburton one-trip perforate and pack system Frac packs 60%

Gravel packs 12%

High rate water packs 28%

Fig. 3.50. US offshore sand control market

reducing near-wellbore pressure drop and flow velocity. In the Gulf of Mexico, frac packing became increasingly popular beginning in the late 1980s. Amoco, now BP, performed five frac-pack completions in the Ewing Bank area during 1989 and 1990 by batch mixing up to 6 lb (2.7 kg) of proppant added (ppa) per gallon of treatment fluid.85 In 1991, ARCO, now BP, performed frac packing in the South Pass area.86 Pennzoil, now Devon Energy, used this technique in the Eugene Island area.87 At about the same time, Shell began frac packing

Tip screen out

Wellbore top view

Fig. 3.51. Frac packing process

inland wells from barges in Turtle Bayou field, Louisiana. Later, Shell expanded the use of this technique in the North Sea and to offshore wells in Borneo, and also to onshore wells in Colombia, South America and northwest Europe.88 Frac-packing success led to increased use, and this technique soon became the preferred sand-control method in the Gulf of Mexico, where several thousand oil and gas leases lie in water deeper than 3,000 ft (914 m). During 1992, BP completed frac packs in Mississippi Canyon Block 109, 81

Modern Sandface Completion Practices

where water depths range from 850 to 1,500 ft (260 to 460 m).89 A few years later, Shell and Chevron used frac packing to develop fields in water up to 3,000 ft (914 m) deep. Technology transfer and frac-packing success in other areas, such as 1.20 Kg/Ke = ∞

Jg/Jo

1.15

Kg/Ke = 25

1.10

Kg/Ke = 4

1.05 Kg/Ke = 2 1.00

0 1 2 3 4 5 6 7 8 9 10 11 12 Thickness of gravel pack, in.

Fig. 3.52. Effect of replacing formation sand with gravel pack

Jg/Jd

3

Kd/Ke = 0.05 Kd/Ke = 0.5 Kd/Ke = 0.1

2

Kd/Ke = 0.2 1 0

1 2 3 4 5 6 Thickness of damage zone, in. Kg/Ke >> 25 ~  Kg = 1,00,000 md, Ke = 1,000 md re = 660 ft, rw = 0.51 ft

Fig. 3.53. Effect of replacing damage zone with gravel pack

Jg/Jd

3

Kd/Ke = 0.05 Kd/Ke = 0.5 Kd/Ke = 0.1

2

Kd/Ke = 0.2 1 0

1 2 3 4 5 6 Thickness of damage zone, in. Lf = 25 ft, frac width = 1 in. Kg = 1,00,000 md, Ke = 1,000 md re = 660 ft, rw = 0.51 ft (perfect fracture)

Fig. 3.54. Effect of damage zone on fracpack productivity 82

Indonesia, the North Sea, the Middle East, West Africa and Brazil, are further expanding the worldwide application of this technique. Fracture stimulation and frac packing in high-permeability reservoirs now represent 20% of the fracturing market.90 The major benefit of a frac pack is theoretically due to forming a high conductivity path through the “critical” damage zone. Examples of how a damaged zone affects the results of a 25 ft (7.6 m) fracture are shown in Table 3.17. Note that the example fracture in a non-damaged 100 md formation will theoretically increase productivity by 83%, but in a 1,000 md formation by only 31%. The fracture does more relative stimulation of low permeability formations than higher permeability formations. However, if formation damage has reduced the permeability by 90% in a 3 ft (0.9 m) thick zone around the wellbore, the 100 md formation will have been stimulated by 625% and the 1,000 md formation by 420%. A major assumption of these example calculations is that a “perfect fracture” is established that (1) has no restriction to flow through the fracture, (2) causes no further damage to the formation, (3) allows production to be in non-turbulent flow through the propped fracture, etc. Means of controlling sand may be significantly different than in a gravel pack. This is because control of formation sand movement in frac packs may be due to the reduction of produced fluid flux into the propped fracture, while a gravel pack must physically stop formation sand. Formation sand may not enter a propped fracture if the velocity of produced fluid flowing from the formation into the proppant is low

enough to prevent fluidization of the sand. However, there are some situations where gravel pack sizing criteria must be used to physically stop sand movement. Comparison of Frac Packs and Gravel Packs Not all frac packs exceed productivity results of all gravel packs. For instance, one company’s gravel pack skin factors in the US Gulf Coast ranged from about -3 to +60 and skins of frac packs from -4 to +26.92 Although most operators have reported improved productivity indexes (PIs) and lower skin factors for frac packs than for gravel packs, it is impossible to know how well these comparison gravel packs were designed and performed in the field. It would be interesting to know why some gravel packs had negative skin factors and others had such extremely high skin factors. Theoretically, successful gravel packs should stimulate well productivity and yield negative skin factors. This is clearly seen in open-hole completions, as underreaming removes some of the near-wellbore formation and damaged zone. Then, this low permeability sand is replaced by high permeability gravel. Figure 3.52 shows that if 6 in. (1.5 cm) of formation sand is removed by underreaming and replaced by 6 in. (1.5 cm) of gravel (Kg/Kc > 25), the resulting well productivity should be increased by more than 10%. Figure 3.53 shows that if the 6 in. (1.5 cm) of formation sand that is removed contains formation damage such that Kd /Ke = 0.05, the well productivity should be increased by more than three times what it would have been without underreaming and gravel packing.

Damage Zone Permeability (md)

Damage (%)

J/Jo K e = 100 md

1 10 50 100 1,000

99 90 50 0 –

50.44 6.25 2.32 1.83 –

Damage (%) 99.9 99.0 95.0 90.0 0.0

J/Jo K e = 1,000 md 327.27 33.57 7.46 4.20 1.31

Assumes: 12.25 in. wellbore, 3 ft thick damage zone, 100 Darcy proppant, 25 ft frac half length, 1 in. frac width, re = 660 ft

Table 3.17. Effect of damage zone permeability when fractures bypass the formation damage. Assumes “perfect fracture” with no damage, turbulence or other restriction. Calculations by Raymond and Binder equation.91

Chapter Three Cased-Hole Sandface Completions

Underbalanced perforating, surging or washing perforations attempt to obtain the same effect in a cased hole as underreaming an open hole. An attempt should always be made to remove as much formation sand and formation damage from outside the casing as possible and pack these voids, or unstressed areas, with high permeability gravel. Restriction to flow through gravel filled perforations should be minimized. Ideally, a frac pack should provide somewhat higher well productivity than a gravel pack, but this depends on many design and field operational factors. To assess the effect of a perfect hydraulic fracture in a formation that has a damage zone near the wellbore, the Raymond and Binder equation93 may be used:  K e   rd   re   ln  + ln    K d   rw   rd  = J d  Ke   re    ln( A) + ln( B) + ln   Kd   Lf 

Jf

Where: ( A) =

( B) =

Factors that favor frac packs. There are several factors that favor the use of frac-pack completions including: • Bypasses near wellbore formation damage • Accelerates production through increased sandface area • Connects thin sand layers • Stimulates low permeability formations • Reduces potential scale problems • Reduces potential fines migration. Fines are mobilized by velocity, viscosity, multi-phase flow and water breakthrough. This is illustrated in Fig. 3.55. The benefit of reduced fines migration is because of the increased sandface area. This reduces the drawdown and fluid velocity, increases the PI, and reduces near wellbore pressure drop. Example: 20 ft zone producing 100 bopd from the entire interval.

 w  K f   rd +     −1  π    K d   rw +  w    K f  −1     π K  

And:

Figure 3.54 shows an example of a 1 in. wide fracture, with 25 ft half length, through a 6 in. thick damage zone (Kd/Ke = 0.05) that results in an increase of more than 3.5 times the productivity of an unfractured well with the damaged zone in place. The same Ke (undamaged formation permeability) and Kf (fracture sand permeability) was used as in the gravel packed example in Figure 3.53. Comparing an ideal gravel pack, with an ideal frac pack indicates that there might not be much difference in productivity results. Consider the productivity increase comparisons shown in Table 3.18. Wider frac widths and longer frac lengths will theoretically increase results of a frac pack, but increased removal of formation damage replaced by increased volumes of gravel packed outside of a cased hole will theoretically improve results of a gravel pack also.

d





 w  K f   L f +   −1  π    K e   rd +  w    K f  −1      π    Ke 

Fig. 3.55. Fines migration



And: Jf = productivity of fractured well (bopd or MMcf/d/psi) Jd = productivity of damaged, unfractured well (bopd or MMcf/d/psi) Ke = permeability of undamaged formation (Darcy) Kd = permeability of damage zone (Darcy) Kf = permeability of fracture proppant (Darcy) rd = radius of damage zone around the wellbore (ft) rw = radius of wellbore (ft) re = drainage radius of reservoir (ft) Lf = half length of fracture (ft) w = width of propped fracture (ft) The above relationship assumes pseudo-steady-state flow, square drainage area, compressible fluid, no turbulence and perfect fracture.

Damage Zone Thickness rd-rw (in.)

Effect of Damage K d /K e

Perfect Open-Hole Gravel Pack Jgp /Jd

Perfect Frac Pack Jfp /Jd

1

1.00 0.10 0.05

1.02 1.22 1.43

1.31 1.56 1.84

2

1.00

1.04

1.31

0.10

1.41

1.78

0.05

1.82

2.30

3

1.00 0.10 0.05

1.06 1.59 2.18

1.31 1.97 2.70

6

1.00

1.11

1.31

0.10

2.05

2.43

0.05

3.11

3.67

Assumes: Perfect gravel pack K g /K e >> 25 ~ ∝, Kg = 100,000 md, K e = 1,000 md, re = 660 ft, r w = 12-1/4 in., Perfect frac pack L f = 25 ft, w = 1 in., K f = 100,000 md, K e = 1,000 md, re = 660 ft, rw = 12-1/4 in. Table 3.18. Comparison of frac pack with gravel pack

83

Modern Sandface Completion Practices

Fig. 3.56. Frac pack (top) vs. open-hole gravel pack (bottom)

A 20 ft length, 20 ft height, “penny shaped”, propped fracture has a total surface area in contact with formation of 1,256 ft and fluid flux is 0.08 bopd/ft. An open-hole gravel pack of 20 ft interval with 1 ft thick pack of gravel around a 1 ft diameter wellbore has a total surface area in contact with formation of 188 ft and fluid flux of 0.53 bopd/ft. This phenomena is illustrated in Figure 3.56.

• Fracturing in a high-angle wellbore interferes with packing of gravel over the entire completion interval • More difficult to do remedial work such as shutting off water or gas • Higher cost than gravel pack • Higher injection pressures and rates are required, especially in long completion intervals • Small casing or tubing restricts pump rates during treatment • Higher casing, tubing, screen, liner strengths needed to reduce collapse risk • Equipment for high pressure pumping not readily available in all locations • Special stimulation vessel needed for offshore locations.

Disadvantages of frac packs. Conversely, there are several factors that do not favor the use of frac-pack completions including: • Frac out of zone (water/oil, water/gas, gas/oil) Gravel pack +5 to +10 excellent +40 and higher are reported

HRWP

Frac Pack

+2 to +5 reported –

0 to +2 normally 0 to -3 in some reports

Table 3.19. Skin values 35 A 30

G B

F

25 H

Skin

20

C

15

D

I

E

10 5 0 -5 Prepacks above frac GOM frac packs

HRWPs W. Africa frac-pacs

GOM frac-packs

Fig. 3.58. Comparison of treatments pumped above formation fracture pressure Fig. 3.57. Frac-pack applications. Frac packing is a viable completion alternative for many wells in reservoirs with sandproduction tendencies. In reservoirs with moderate to high permeability that are susceptible to drilling and completion damage that extends deep into the formation, frac packing and wide tip-screenout (TSO) fractures connect reservoirs and wellbores more effectively. When perforated interval length is limited, frac packing connects more pay with fewer perforations. Frac-pack completions also improve hydrocarbon recovery from low-pressure and depleted reservoirs by minimizing completion skin across the pay interval, thus reducing drawdown and ultimate abandonment pressure. 84

57 frac pack wells

23 HRWP wells

14%

13% 32%

9%

34% 13%

11%

9%

34%

39%

Fig. 3.59. Skin distribution comparison between frac-pack and HRWP completions

Chapter Three Cased-Hole Sandface Completions

Frac packing also may not be economical for low-rate wells, water-source or injection wells that do not produce revenue directly, and reservoirs with limited reserves or homogeneous thick zones where horizontal gravel packing in open-hole is more appropriate.94 In more prolific reservoirs, flow turbulence associated with perforated casing restricts production, so operators often drill and complete open-hole horizontal wells to optimize productivity. Stand-alone screens, open-hole gravel packs, or expandable or other premium screens are sand-control options in these settings, especially for thick reservoir sections. Frac packing in open-hole completions is the next logical step to provide long-term sand control without sacrificing productivity95 (see the “Open-Hole Frac Packing” section of Chapter Two). Frac-pack candidate selection. Experience from more than 4,000 Gulf of Mexico frac packs in formations with permeability’s ranging from 3 md to 3 Darcy helps oil and gas producers identify frac-pack candidate wells (Fig. 3.57). Frac-packing well-completion applications include the following: • Wells prone to fines migration and sanding • High-permeability, easily damaged formations • High-rate gas wells • Low-permeability zones requiring stimulation • Laminated sand-shale sequences • Heterogeneous pay zones • Low-pressure and depleted reservoirs.96 Comparison of Frac Packs and HRWPs Frac packing is a general term applied to process of combining a hydraulic fracture with a gravel pack. An HRWP, which was described previously in this Chapter as a perforation prepacking technique, is usually done above frac pressure as well. In addition, the general term, frac pack, does not specify a carrier fluid, therefore an HRWP is in most instances actually a frac pack method. The principle difference in these two techniques is the placement method: • Frac-pack placement: pump viscosified fluid with “ramped” gravel concentration (typically 1/2 - 15 ppa) at 5 to 40 bpm

• HRWP placement: pump low-viscosity completion fluid with low gravel concentration (typically 1 to 2 ppa) at 5 to 15 bpm. Empirical data reported by Tiner et al,97 condensed and presented in Table 3.19, support the frequent notion that HRWPs have an advantage over gravel packs, but do not afford the productivity improvement of frac packs. This improvement over gravel packs is reasonable by virtue of the additional proppant placed in the perforation tunnels. While not shown in the table, the performance of these completions over time is also of interest. It is commonly reported that production from HRWPs (as in the case of gravel packs) deteriorates with time. By contrast, however, others,98,99 reported that production has progressively improved (skin values decrease) during the first several months following a frac pack treatment. Another study comparing frac packs with HRWPs has demonstrated that, although the fractures generated during a HRWP treatment are significantly shorter than those created during a frac pack treatment, the net result of both of these techniques is that good damage bypass is obtained.100 The parameter selected for comparison of frac pack with HRWP performance was skin. Skin was selected because of the industry acceptance of this parameter and because previous fracpack data available had been reported in terms of skin. Figure 3.58 shows skin data from field data for frac-pack and HRWP completions. Similarly, Figure 3.59 presents pie charts of these same data so that the overall distribution of skins may be evaluated. The elevated skins in Figure 3.58, depicted by points letter A through I, can be attributed to conditions beyond what would normally result from the treatments. Therefore, these nine treatments are eliminated from the comparison. Hence, well productivity resulting from frac-pack treatments is indistinguishable from those reported for HRWP completions. In the majority of situations, the decision concerning which technique to employ should be based upon cost and logistical issues. Even though in the majority of situations these two techniques are interchangeable, because of differences in reservoir properties, fluid properties and pumping practices, there are specific applications that are better suited

for one technique or the other. Table 3.20 lists the benefits and risks associated with a frac pack and HRWP. Hydraulic Fracturing Concepts, Geometry and Rock Mechanics Details of rock mechanics and creation of a hydraulic fracture are beyond the scope of this text. However, certain general principles are assumed to be understood and believed valid for most reservoirs: • Fractures are nearly always vertical (exceptions may be in very shallow wells and in tectonically active areas) • Fractures are oriented perpendicular to the direction of minimum principle stress (in most formations, this is the direction toward the maximum horizontal stress) • Fracture initiation pressure is normally higher than fracture extension pressure • Fracture height and length continue to increase as long as the fluid pressure inside the fracture is larger than the least in-situ principal stress or until a barrier is reached or a sand out obtained. Hydraulic fracturing is most commonly done in strong formations that have permeabilities less than 1 or 2 md, where a contrast between the proppant and formation permeabilities of 10,000 or more is desirable. Fracture lengths of 500+ ft (152.4+ m) and propped fracture widths of 0.2 in. (0.5 cm) or less are common. This is enough for good production results in low permeability formations. There are many unknowns and disagreements on the best means of fracturing strong, low permeability rocks where fracturing has been applied for several decades. For instance, the SPE Monograph Volume 12, Recent Advances in Hydraulic Fracturing, published in 1989,101 states “fracture height is a variable that can be only grossly estimated with today’s technology.” Today, the technology of fracturing has improved in fracture designs for both the software and data needed in fracture design. The sophisticated computer programs used to design, model and evaluate fracture treatments have greatly helped the process, but are often based on certain assumptions and questionable input data that affect the results of 85

Modern Sandface Completion Practices

Low-Permeability formations

Bilinear flow

Fracture with viscous fluid

Fracture with water

High-Permeability formations Fracture with viscous fluid

Proppant embedment

Fracture with water

Formation Proppant Pack

Fig. 3.60. Fracture geometry. In low-permeability formations, viscous fracturing fluids generate long, narrow fractures; less viscous fluids, such as water, leak off quickly and create shorter fractures (top left ). Hydraulic fracturing increases effective completion radius by establishing linear flow into propped fractures and dominant bilinear flow to a wellbore (top right ). In highpermeability formations, fracturing treatments create short, wide propped fractures that provide some reservoir stimulation and mitigate sand production by reducing near-wellbore pressure drop and flow velocity (bottom left ). In low-strength, or soft, formations, proppant concentration after fracture closure must exceed 2 lb/ft2 (10 kg/m2) to overcome proppant embedment in fracture walls (bottom right ).

Frac pack Eliminates risk of not fracturing

HRWP Benefits Non-damaging

• Important for moderately damaged high kh formations

Much greater fracture lengths

Improved gravel-pack quality

• Important for low permeability formations

• Better perforation filling • Better annular packing

Enhanced vertical fracture growth

Gravel transport mechanism

• Important for long intervals of thinly laminated formations

• Concentrate gravel close to wellbore • Do not over displace during multi-stage operations

Higher near-wellbore proppant concentration

Less efficient fluid • Less chance of out-of-zone fracture growth

• Lower non-Darcy skin in high rate wells • Allows for more proppant embedment into formation • Possible mechanism for longer sustained production

Unable to obtain TSO

Risks Inability to fracture

• On-site mini-frac analysis and job redesign needed

• Moderately damaged high kh formations with relatively low viscosity reservoir fluids • Treating high-temperature formations with low-density brine • Hydraulic horsepower limited

Failure of gel system to break

Insufficient height growth

• Proper gel/breaker combination for formation temperature • Laminated sand greater than 50 feet thick

Unfavorable fracture growth

Insufficient fracture length

• Do not attempt to treat multiple sands • Hazardous when close to oil/water or gas/oil contact

• Low permeability formations • Proven “deep” damage

Poor annular growth

Reduced fracture conductivity

• Do not treat intervals with deviations >60° • Can be handled by reducing fluid viscosity at end of job

• Potential for higher non-Darcy skin in high-rate completions

Table 3.20. Benefits and risks of frac packs and HRWPs 86

fracture geometry. Length and height of a fracture are used to calculate the fracture width. A fracture is usually assumed to be elliptical, rectangular or “penny shaped” and both wings are equal length, height and width (Fig. 3.60). Therefore, a logical question is “How much confidence can be given to these computer programs for designing, modeling and evaluating fractures in weak, high permeability formations?” The above question can be answered based upon knowledge of rock mechanics, linear elastic fracture mechanics and laboratory and field based studies published by SPE. The fracture geometry (height, length and width) is uncertain if the rock or soil mechanics properties are uncertain. On the other hand, the fracture geometry can be predicted by software if the rock mechanical properties are known. The rock and soil mechanical properties measured or calculated in the laboratory for fracture designs are: • Young’s modulus (for fracture length, width and pressures) • Poisson’s ratio (for fracture height and formation stress determination) • Fracture toughness (for fracture height and length) • Minimum principal horizontal stress versus depth (for fracture height and pressure) • Proppant embedment (for fracture width and fracture conductivity) • Leak off coefficients (for fluid leak off into formation) • Biot’s poroelastic coefficient (for formation stress determination). If all or most of the above properties are known, successful fracture treatments are expected. All of the above properties are often measured in the laboratory and used to calibrate sonic and dipole sonic logs. During the initial design (see the “Design and Simulation Software” section in Chapter Four) of a frac-packing treatment, completion engineers determine the required fracture geometry based on reservoir conditions, rock properties and barriers to fractureheight growth. Fracture length and, more importantly for high-permeability formations, fracture width enhance well productivity. Fracture width. It is important that the fracture width be large enough to offset the effect of sand embedment in soft

Chapter Three Cased-Hole Sandface Completions

formations and to obtain a high enough fracture conductivity to minimize any turbulent flow through the fracture as fluid nears the wellbore. Fracturing technology indicates that a proppant concentration of 4 lb/ft (5.95 kg/m) should be enough, but gravel packing technology suggests that formation sand may invade 3 to 4 grain thicknesses into a propped fracture, which may be compensated for by providing a minimum of 12 grain diameters. The average diameter of 20/40 U.S. Mesh sand is about 0.025 in. (0.064 cm). Thus, the minimum fracture width should be 0.3 in. (0.76 cm) to allow a 4-grain thickness of uninvaded sand. Obviously, it is best to have a larger fracture width near the wellbore. Laboratory testing can be used to determine the amount of proppant embedment versus closure stress. It is easy to become confused by fracturing literature when proppant loading (lb/ft) is related to fracture width (in.). Theoretically, fracture width can be calculated by the following equation: W = Vb/2Lh Where: W = fracture width (ft) Vb = bulk volume of proppant (ft) L = propped fracture half length (ft) h = propped fracture height (ft) This means the average width of a propped fracture loaded with 4 lb/ft2 would be 0.04 ft, assuming the bulk volume of the proppant after packing under downhole conditions is 100 lb/ft3. Obviously, the bulk density of proppants will be somewhat less than 100 lb/ft3. Assuming the bulk density of a proppant, after compaction and embedment, is 83.3 lb/ft3 makes this an easy conversion, as 10 lb/ft2 loading = 1 in. frac width. An estimate of the amount of embedment in weakly consolidated sand is that it will reduce proppant loading by 2 lb/ft2.102 This is a reasonable estimate, but the actual amount of embedment depends on many factors, primarily rock mechanical properties and closure stress. Embedment in “quicksand” type formations will probably be more and in “friable” type formation may be less than this. Embed-

ment may actually increase slightly as a well is produced and pore pressure declines. Two studies in this area were done by Lacy, et al in recent years.103,104 “Creep” is another phenomenon that will affect fracture width and conductivity as a well is being produced. Creep may be defined as the slow invasion of sand and formation particles into the pores of the proppant from fluid movement and reservoir pressure decline. This is very difficult to assess except in much generalized terms (i.e., it is more likely to be a significant factor in “quicksand” type formations than in stronger formations). Proper underbalanced perforating, surging or washing perforations, combined with erosion caused by proppant being pumped into the fracture at high rates, contribute to achieving wide propped fractures near the wellbore. Ideally a fracture width should be more than 2 in. (5.1 cm) or 3 in. (7.6 cm) near the wellbore. One company specifies frac pack designs of 10 lb/ft2 and other companies are attempting to pack more than 20 lb/ft2. These proppant loadings are averages, and the actual fracture width near the wellbore should be wider than these numbers indicate. Providing the widest possible fracture near the wellbore is the only practical way of minimizing the effects of embedment and creep. Examples of the relative effect of width on well productivities are shown in Table 3.21.

m). The effect of extending a fracture much beyond this length may be insignificant to well productivity, may cause the fracture to extend out of the desired productive zone, and will affect job economics. However, extension of fracture length may aid controlling sand by reducing the velocity of fluid entering the proppant. Designing fracture lengths of 30 ft (9.1 m) to 50 ft (15.2 m) is probably needed to achieve a proper tip screenout and adequate propped width near the wellbore. This TSO and fracture inflation is generally accompanied by an increase in net fracture pressure, the difference between the pressure at any point in the fracture and that of the fracture closure pressure. Thus, the treatment can be conceptualized in two distinct stages: fracture creation (equivalent to conventional designs) and fracture inflation/packing (after tip screenout). Effective frac packing relies on a carefully timed tip screenout to limit fracture length and to allow for fracture inflation and packing. This process is illustrated in Fig. 3.61. Fracture height. Fracture height should increase as the length of the fracture increases, except when high strength barriers exist or where multiple fractures are being generated. A fracture is thought to form two “penny” shaped wings in weak, high permeability sand-

Fracture length. Length is less important than width, because the main benefit of fracturing most high permeability formations is to bypass formation damage. The critical zone where most formation damage occurs is approximately 2 ft (0.6 m) to 5 ft (1.5 m) radially around a wellbore. Thus, the minimum length of a fracture should be 5 ft (1.5

Fig. 3.61. Width inflation with the tipscreenout (TSO) technique at the designed fracture length

Fracture Width (in.)

J/J0 K d = 10 md K e = 100 md

J/J0 K d = 100 md K e = 1,000 md

0.25 1.0 2.0

5.05 6.26 6.71

2.85 4.20 4.85

Assumes: 12.25 in. wellbore, 3 ft thick damage zone, 100 Darcy proppant, 25 ft frac half length, re = 660 ft. Perfect fracture with no damage, turbulence or other restriction. Calculations by Raymond and Binder equation. Table 3.21. Fractures bypass formation damage effect of fracture width 105 87

Modern Sandface Completion Practices

stone unless there are barriers that prevent this. A fracture in reservoirs with sand, shale sequences or with hard layers intermingled with the soft sand layers, may form multiple elliptical fractures that extend deeper than predicted in some layers and shallower in other layers. Logs cannot measure this effect because there may be sand outside the casing throughout all perforated zones. This can have an unpredictable effect on the result of a frac treatment. Minimizing fracture growth in the vertical direction will help reduce the possibility of fracturing out of the zone of interest. Where horizontal barriers do not exist, the fracture height may only be limited by limiting its length.

ity, and more recently, viscoelastic surfactant (VES) fracturing fluids, all are applicable. Frac-packing fluids must have a variety of properties.106 Fluid selection depends primarily on TSO fracturing criteria. Unlike massive hydraulic fracture stimulations in lowpermeability formations, a low leakoff rate, or high fluid efficiency, is less desirable for frac packing. In fact, a somewhat inefficient fluid helps achieve tip screenout and promote grain-to-grain proppant contact from fracture tip to wellbore. However, frac-packing fluids also must maintain sufficient viscosity to create wide dynamic fractures and place high proppant concentrations that ensure adequate conductivity after fracture closure. After tip screenout, fluid systems transport proppant in the lowshear environment of a wide dynamic fracture, but also must suspend proppant under higher shear rates in tubing, around screen assemblies, through the perforations and during fracture initiation and propagation. Fluid viscosity should break easily to minimize formation and proppant-pack damage after treatments. Optimal fluids need to be compatible with formations and chemicals like polymer breakers; they must also produce low friction and clean up quickly during post-treatment flowback. To maximize retained fracture conductivity, operators exercise great care with viscosity breakers or acid treatments after frac packing to optimize post-treatment cleanup for maximum productivity and hydrocarbon recovery. Finally, frac-packing fluids should be

Frac Fluids and Proppants Frac packing represents a marked departure from historical gravel-pack treatments. This trend is evident in the proppants and fluids applied. While the original frac-pack treatments involved sand sizes and clean fluids common to gravel packing, the typical proppant sizes for hydraulic fracturing (20/40 mesh) now dominate. The increased application of crosslinked fracturing fluids also illustrates this trend. Fluid selection. After evaluating reservoir characteristics, engineers choose an optimal fluid for combined stimulation and gravel packing. The polymer-based hydroxyethyl cellulose (HEC) fluids used in gravel packing, hydroxypropyl guar (HPG) fracturing fluids with a borate crosslinked for additional viscosPermeability md-ft

Gas

Oil

<20 20-200 200-700 >700

HEC HEC or Borate Cross Link Fluid Cross Link Fluid

HEC HEC HEC or Borate Borate

Table 3.22. Fluid system recommendation vs. permeability

Temperature °F

°C

<200 200-300 >300

<93.33 93.33-148.89 >148.89

Table 3.23. Fluid system recommendation vs. temperature 88

Gelled Fluid HEC or Borate Borate Zinc or Titanate Crosslink

safe, cost-effective and easy to mix, especially in offshore applications. Fluids based on HEC have many preferred frac-packing characteristics, but also several drawbacks. Systems based on HEC exhibit increased friction pressures compared with delayed crosslinked HPG or VES fluids, and frictional losses become significant in deeper wells or smaller diameter tubulars. In addition, proppant transport characteristics for HEC fluids are not as good as those of crosslinked HPG or VES fluids. High temperatures cause HEC fluids to thin, and viscosity is not as high at low shear rates. High-viscosity crosslinked HPG systems leave some polymer residue, but maximize fracture-height growth in moderate-to-high-permeability formations. They also perform well in longer intervals and transport higher proppant concentrations for greater fracture conductivity. Pumping pressures increase with HPG systems, but service companies can used a delayed crosslinked to reduce tubular friction. Delayed-crosslink HPG fluids start at a lower viscosity and require less hydraulic horsepower to pump downhole. Prior to reaching the perforations, temperature in the wellbore and fluid pH cause the viscosity of these fluids to increase in order to achieve low fluid-leakoff rates. The majority of frac packs are pumped with crosslinked or delayed-crosslink HPG fluids. Viscoelastic polymer-free fracturing fluids, introduced in the mid-1990s, use a VES liquid-gelling agent to develop viscosity in light brines. This type of fluid provides low friction pressures while pumping, enough viscosity at low shear rates for good proppant transport, adequate leakoff rates to ensure tip screenout and high retained permeability for better fracture conductivity. Field data also indicate that fracture confinement using VES fluids is better than with conventional fracturing fluids, which is an advantage when frac-packing near water-bearing zones. These VES systems mix easily and do not require additives such as bactericides, breakers, demulsifiers, crosslinkers, chemical buffers or delayedcrosslink agents. Systems based on VES also are not susceptible to bacterial attack. If wells must be shut in for extended periods before flowback and cleanup, solids-free Viscoelastic poly-

Chapter Three Cased-Hole Sandface Completions

mer-free fluids are recommended to avoid precipitation of damaging polymer materials. Fluids based on HEC and VES systems minimize formation damage in zones with low to moderate permeability, but high leakoff rates and deeper invasion often result in slower recovery of treatment fluids.108 Adding enzyme or oxidizing breakers to frac-packing fluids reduces formation damage and improves well cleanup. Slow-release encapsulated breakers deposited in the proppant pack allow higher breaker concentrations to be used without sacrificing fluid efficiency. In addition to fluid leakoff and friction pressure considerations, shear rate and temperature are critical in selecting frac-packing fluids and polymer concentrations.109 The first frac-pack treatments were performed using the same HEC fluid systems as gravel-packing operations. Later, a shift to more conventional fracturing fluids occurred because of increasing temperature requirements and the need to maximize fracture conductivity in high-permeability formations. Initially, selection criteria for these fluids were similar to those of conventional fracturing applications in which narrow hydraulic fractures in consolidated, low-permeability formations create high shear rates with low fluidleakoff rates. These factors result in breakdown of fluid viscosity and less cooling of formations, and greater polymer concentrations are required to maintain viscosity throughout a treatment. The use of higher polymer concentrations carried over into fracturing and frac-packing designs for high-permeability reservoirs. In frac packing, however, fractures are wider with lower fluid velocities and shear rates. Pretreatment fluid injection also decreases formation temperature near the wellbore. Pumping large volumes of treatment fluid decreases heat transfer from a reservoir, resulting in cooler temperatures inside a fracture. Failure to consider these effects results in use of higher polymer concentrations than actually required. This increases the potential for formation damage and decreases the likelihood of a tip screenout. For example, because of differences in shear rate, a crosslinked fluid with a polymer loading of 20 lb per 1,000 gal

Table 3.25 lists available gravel/proppant sizes. Fracture closure stress increases as the flowing bottomhole pressure decreases (Fig. 3.63) according to the following relationship:

(2.4 kg/m3 ) of base fluid can have the same viscosity in a high-permeability formation as a 40 lb per 1,000 gal (4.8 kg/m3 ) fluid in a low-permeability formation. Proper fluid selection and specification dramatically increase frac-packing efficiency and well productivity.110 Tables 3.22 and 3.23 are some guidelines for choosing a gel system based on formation permeability and temperature.

Fracture closure stress = øin situ - Pwf As the well is produced, the effective stress on the propping agent will normally increase because the value of the flowing bottom hole pressure will be decreasing. The phenomenon of

Proppant selection. The type of proppant chosen to keep fractures open and form a granular filter is an important design consideration. Frac packing success is due, in part, to larger proppant sizes than those commonly used in gravel packing. High concentrations of large, spherical proppants minimize embedment and offset the effects of turbulent flow in propped fractures. Operators use various grain sizes and proppant types (Fig. 3.62), including natural sand, custom-sieved sand, resin-coated sand, intermediate strength man-made ceramic proppants, and high-strength bauxite, depending on formation stress and fracture-closure stress. Table 3.24 shows typical proppants used in frac pack applications and Class Natural Material

Man-made Material

Fig. 3.62. CarboProp 20/40 (intermediate strength proppant)

Proppant Type

Examples

Sand

White sand – SG 2.65 Brown sand – SG 2.65 Resin-coated sand – SG 2.65 Ceramic Light weight ceramic – SG 2.70 Intermediate ceramic – SG 3.20 High strength aluminum oxide Sintered bauxite – SG 3.49

NOTE: SG = Apparent specific gravity Table 3.24. Proppants used in frac pack applications

US Mesh

Natural Sands

Man-made Materials

10/20 12/18 12/20 16/20 16/30 20/40 30/50 30/60 40/60 40/70 50/70

X – X – X X X – X X X

– X X X X X X X – X –

Table 3.25. Available gravel/proppant sizes for frac-pack applications 89

Modern Sandface Completion Practices

Conductivity (md-ft) Closure Stress (psi) 2,000 4,000 6,000 8,000 10,000 12,000 Median diam. (mm) Actual width (mm)

20/40 20/40 EconoProp 20/40 InterProp Sintered Bauxite (12.0 lb/sq.ft.-200°F) (12.0 lb/sq.ft.-200°F) (12.0 lb/sq.ft.-200°F) 36,995 30,568 21,848 13,349 8,225 4,371 0.6460 1.3892

36,672 31,195 23,188 18,292 14,610 10,718 0.6620 1.1207

38,795 32,527 27,194 21,688 15,693 11,175 0.6620 1.0848

Table 3.26. Comparison of proppant conductivity

Proppant

viscosity

Pwf

Fig. 3.63. Fracture closure pressure on proppant

decreasing in situ stress as the reservoir pressure declines was proven conclusively by Salz.111 Proppants for frac packing should accomplish four fracturing objectives: • Provide an effective permeability contrast • Control sand influx and fines migration • Minimize proppant embedment in soft rock • Maintain fracture conductivity without proppant crushing. In the past, gravel-packing considerations dominated proppant selection.112 Gravel packs require gravel, or sand, sized to prevent formation particles and fines from invading the annular pack. The widely accepted Saucier rule dictates that sand, or gravel, particles be five to six times the mean particle diameter of formation grains.113 Fracture permeability and conductivity improve as proppant sizes become larger, but production of formation sand grains and fine particles that reduce pack permeability also increases. Frac packs require proppants sized to optimize fracture permeability. In the early 1990s, operators began evaluating larger sizes of stronger proppants to increase fracture permeability and relative conductivity in high-perme90

ability reservoirs.114 For example, larger 20/40-mesh proppants were used for frac packing instead of smaller 40/60mesh proppants often required for gravel packing. Experience indicated that proppant sizes dictated by gravelpacking criteria could be increased to next larger size for frac packing. Saucier criteria for sizing proppants in relation to formation grain size were relaxed in frac-pack designs because the large flow area of hydraulic fractures mitigates formation failure and sand influx. Balancing the mechanisms of sand production (flow velocity, proppant particle sizes and fluid properties) allows operators to increase fracture conductivity and improve frac-pack performance by using larger proppant sizes. Completing deeper wells with high fracture-closure stresses led operators to use more man-made ceramic proppants because they are stronger and their consistent spherical shape reduces embedment, which also increases fracture conductivity (Fig. 3.64). The majority of frac packs use ceramic 20/40-mesh intermediate-strength proppant (ISP) when reservoirs have good pressure support and closure stresses are not excessive.115 For example, a formation with 1 Darcy permeability would need a proppant with in-place permeability of 10,000 darcies, which means using a proppant size of 5 x 7 US mesh (0.111 x 0.157 in.) or larger. A large size such as this would certainly provide high fracture conductivity and minimal pressure loss through the perforations. However, it would be difficult to efficiently transport, more difficult to pump through perforations without

bridging, more prone to erosion, more susceptible to crushing and less able to prevent embedment and invasion of sand into the propped fracture than smaller proppant sizes. Thus, a compromise must be made between the need for high permeability versus field operating constraints, which favor smaller sized, higher strength proppants and help prevent loss of fracture conductivity, by invasion of formation sand into the propped fracture. Do not attempt to use large proppant for the fracture and small gravel for the pack because there is doubt as to when a tip screenout will occur and when pumping of the gravel should begin. In addition to proppant sizing, the density of the proppant is now considered an important variable as well. Created fracture width and proppant selection determines conductivity and stimulation effectiveness is proportional to conductivity. Therefore, by comparing proppant conductivity at any given closure stress, the most effective proppant can be selected for maximum stimulation. Consider the proppant conductivity listed in Table 3.26. Proppant conductivity at consistent concentrations indicate that more dense/higher strength proppants have significantly higher conductivity only at stresses above 6,000 psi. The Actual width shown at the bottom of the chart is for 4,000 psi closure. This width indicates that there is substantially more width required to hold 12 lb/ft2 of light weight prop versus denser prop. If the created width is held constant then looking at conductivity, will yield a true comparison of achievable conductivity (Table 3.27). When conductivity for equal widths between the proppant types are compared at 4,000 psi closure stress, InterProp has 27% more conductivity than EconoProp. Sintered bauxite has 37% more conductivity than EconoProp. Furthermore, the beta factor for each of the more dense proppants is lower, significantly reducing the effects of nonDarcy flow, by 21% for InterProp and 30% for sintered bauxite. Beta factor is alternatively referred to as the “inertial flow coefficient.” The beta factor is a proportionality coefficient that is determined by laboratory measurements. Beta is essentially a measure of the tortuosity of the flow

Chapter Three Cased-Hole Sandface Completions

path. Beta is determined by flowing realistic velocities through the API conductivity cell116 and solving the following equation for beta to match the observed pressure drops.117

20/40 ISP ceramic 20/40 Ceramic 30/50 Ceramic 20/40 Natural sand 40/60 Natural sand

1,000

Where: ∆p/L= pressure drop per length of proppant pack µ = fluid viscosity ν = superficial fluid velocity k = permeability of porous media β = coefficient of inertial resistance ρ = fluid density It is inappropriate to select proppants based on reference conductivity alone because reference conductivity are measured with a single phase fluid under laminar flow conditions in accordance with API RP 61. Beta factors must be considered as well. In an actual fracture, the effective conductivity will be much lower due to non-Darcy and multiphase flow effects. Finally, to aid in the selection of proppants, refer to the charts in Appendix 1. The first chart is the permeability of a number of proppants that might be used in a frac pack. It illustrates the importance of mean diameter rather than API designation. The second chart shows the over-riding importance of non-Darcy flow on the effective permeability in a high-rate gas flow as related to the beta factor discussed above. The third plot illustrates permeability decreasing with increasing closure stress for several branded proppants. A closure pressure of 4,000 psi is representative of frac-packed wells. Pretreatment Testing Laboratory testing and history matching of previous treatments provide insight into stress profiles and the performance of treatment fluids, but in-situ formation properties vary significantly in high-permeability unconsolidated reservoirs. After developing preliminary stimulation designs, engineers perform a pretreatment evaluation, or minifracture, to quantify five critical parameters, including fracture-propagation pressure, fracture-closure pressure, fracture geometry, fluid efficiency and leakoff.118

Permeability, darcies

∆ρ µν = + βρν2 L k

100

10 0

2

4

6 8 Closure stress, 1,000 psi

10

12

Fig.3.64. Proppant specifications. In the mid-1990s, operators began using larger, stronger and more conductive proppants in frac-pack completions. Man-made ceramic materials have since become the proppant of choice in the US Gulf of Mexico to maintain fracture conductivity at higher closure stress in deeper formations. For example, switching from smaller 40/60-mesh sand (green) to a larger intermediate-strength 20/40-mesh ceramic proppant (yellow) increases proppant permeability and fracture conductivity by a factor of six in laboratory tests at 2,000 psi of closure pressure (inset). An intermediate-strength proppant (ISP) is priced competitively with custom-sieved natural sands.

Conductivity (md-ft) Closure Stress (psi) 2,000 4,000 6,000 8,000 10,000 12,000 Median diam. (mm) Actual width (mm) Beta, atm-sec2/g

20/40 20/40 EconoProp 20/40 InterProp Sintered Bauxite (12.0 lb/sq.ft.-200°F) (14.5 lb/sq.ft.-200°F) (15.4 lb/sq.ft.-200°F) 36,995 30,568 21,848 13,349 8,225 4,371 0.6460 1.3892 0.00037

45,677 38,854 28,882 22,784 18,198 13,349 0.6620 1.3888 0.00029

50,033 41,949 35,071 27,970 20,238 14,413 0.6620 1.3894 0.00026

Table 3.27. True comparison of proppant conductivity

This procedure consists of two tests, a stress test and a calibration test, performed prior to the main treatment to determine specific reservoir properties and establish the performance characteristics of actual treatment fluids in the pay zone. A stress, or closure, test determines minimum in-situ rock stress, which is a critical reference pressure for frac-pack analysis and proppant selection (Fig. 3.65). A calibration test involves injecting actual fracturing fluid without proppant at the design treatment rate to determine formation-specific fluid effi-

ciency and fluid-loss coefficients. Fracture-height growth can be estimated by tagging proppants with radioactive tracers and running a posttreatment gamma ray log. A pressuredecline analysis confirms rock properties and provides data on fluid loss and fluid efficiency. An integral part of pretreatment testing is live annulus monitoring and real-time measurements from downhole quartz gauges to obtain pressure responses independent of frictional pumping pressures. Accurate analysis of the data ensures that the current 91

Bottomhole pressure

Modern Sandface Completion Practices

Fractureextension pressure

Instantaneous shut-in pressure (ISIP) Net pressure Fracture closure pressure Rebound pressure

Increasing Constant Constant Shut in injection injection flowback rate rate

Constant injection rate

Pressure falloff

Time

Fig.3.65. Pretreatment minifracture testing. Stress, or closure, tests involve injecting low-viscosity, non-damaging fluid at increasing rates to initiate a fracture and determine the pressure required to propagate, or extend, fracture length. Fracture-closure pressure is determined by monitoring pressure decline during a slow, constant-rate flowback.

Dynamic fracture

Proppant

Tip screenout

frac-pack design and subsequent treatments achieve wide fractures with a tip-screenout for optimal results. Surface data from pretreatment tests combined with bottomhole injection pressures are history matched using a computer simulator to calibrate the fracturing model and finalize treatment design. Calibrated data from computer analysis are also used to assess stimulation effectiveness during post-treatment evaluations. (See the “Design and Simulation Software” section of Chapter 4.) Treatment design, particularly TSO fracture stimulation, is critically important to successful frac packing. If premature screenout or failure to achieve a tip screenout results in insufficient fracture width to overcome proppant embedment in the formation, well productivity may, at best, be equivalent to that of a conventional gravel pack. Standard frac-packing practice is to redesign treatments on-site after minifracture testing and analysis are complete.119 Frac-Pack Methods/Applications

Perforation Fracture inflation

Cement

Annular opening

Casing Screen

Propped fracture

“External” proppant pack

Fig.3.66. Tip-screenout (TSO) fracturing. In high-permeability reservoirs, fracture stimulations require fluid systems that leak off early in a treatment. Dehydration of the slurry causes proppant to pack off at the fracture tip, halting further propagation, or extension (top). As additional slurry is pumped, biwing fractures inflate and proppant packs toward the wellbore (middle). A TSO treatment ensures wider fractures and improves conductivity by promoting grain-to-grain contact in the proppant pack. This technique also generates enough formation displacement to create an annular opening between cement and formation that becomes packed with proppant. This “external” pack connects all perforations and further reduces near-wellbore pressure drop (bottom). 92

As stated, frac packs are a combination of a fracture treatment and an annular gravel pack. A successful frac pack must not only stop sand movement, but must create a wide fracture that is held open by a high permeability proppant extending through the near-wellbore zone. Importantly, the induced fracture must not make contact with nearby zones that contain unwanted fluids. Control of proppant flowback is important to maintain connection between the fracture and wellbore, maintain fracture conductivity, maintain formation stresses, and prevent wellbore fill and pumping problems. The nature of the completion itself (perforations, liners/screens, etc.) influences proppant flowback. Stability is a strong function of flow rate, particle size, frac width and closure stress. The flowback initiation rate decreases as the closure stress increases and as the fracture widens. Conversely, it increases with the proppant size. Proppant control measures should be employed both during and after the fracturing process. During fracturing, measures can include inner liners/ screens, fiber and bridging techniques, resin coated proppants or surface modifier agents. After fracturing, measures

Chapter Three Cased-Hole Sandface Completions

can include inner liners/screens, in situ resins with external catalyst, or sand “squeeze” with resin or surface modifying agent. Applying sand control measures during fracturing is much more cost effective than remedying problems after the fact. Tip-screenout fracturing. The most common technique of fracturing weak, high permeability formations is the tipscreenout fracture, which was introduced earlier in this section.120 It differs from a conventional hydraulic fracture by forcing an early screenout and creating a short, wide fracture of perhaps 25 to 50 ft (7.6 to 15.2 m) in length and 1 or 2 in. (2.5 to 5.1 cm) in width. The critical elements of a TSO treatment design, execution and interpretation are substantially different than for conventional fracture treatments. In particular, TSO fracturing relies on a carefully timed tip screenout to limit fracture growth and to allow for fracture inflation and packing (Fig. 3.66). In a perfect fracture design the proppant is carried by the frac fluid to the tip of the fracture where it packs just as the fracture has extended to the desired length and height. This generates a true “screenout.” A screenout may occur early if fluid leaks off to the formation faster than predicted. Conversely, a screenout may not occur during the job if leakoff is much slower than predicted. An early screenout is undesirable because it means that the fracture has not achieved its designed length and height. No screenout results in less than designed fracture width and conductivity. Pumping continues after a sandout occurs to “balloon” the fracture and pack it with as much proppant as possible. This creates a wider fracture than can be obtained in stronger formations. TSO fracture widths result in very high conductivity that can only be obtained if screenout occurs, or when there is limited amount of “ballooning” time. Hence, among the most critical parameters for obtaining a successful tip screenout are the fluid spurt loss, leakoff rate and dynamic leakoff profile. Unfortunately, there is not an accurate means of measuring or predicting these fluid loss rates in short frac packs, especially in reservoirs where permeabilities and rock properties change by significant orders of magnitude.

Fracture initiation and propagation in weak formations are affected by the variations of the same properties as in stronger formations, such as: • In-situ stresses • Stratification • Rock strength and properties (such as elastic modulus, Poisson’s ratio, toughness, ductility) • Fluid, pressure and permeability profile in the fracture • Pore pressures. The permeability profile and rock strength of most weak, high permeability formations vary much more than in high strength, low permeability formations. For instance, the permeabilities of weak sandstone commonly vary from near zero in shale and clay strata to higher than one Darcy; whereas, the permeabilities of strong sandstone commonly range from near zero to only 5 or 10 md. Similarly, weak sandstone formations that are candidates for fracpack treatments often have strata or pockets of very strong sandstone, shales or carbonates. Strengths may range from nearly zero to many thousands of psi unconfined compressive strength. Fracture orientation in weak formations is the same as in stronger formations. The static stress fields that force them to always be perpendicular to the minimum principal stress dictate the direction of all fractures. This means that the fracture is usually in the same direction as, and parallel to, the maximum horizontal stress. Typical frac-pack running procedure. Initially, operators performed frac packing in multiple steps—a TSO fracturing treatment followed by wellbore cleanout, installation of sand-exclusion screens and separate gravel-packing operations.121 However, high positive skins and limited productivity indicated damage between the propped fracture and internal gravel pack. Frac packing was simplified into a single operation to further improve well production and reduce operational costs.122 The TSO fracturing treatment now is pumped with screens in place (Fig. 3.67). Gravel packing of screen assemblies is accomplished at the end of a treatment.123 A typical running procedure for a frac-pack treatment is to: • Pick up and trip-in hole with gravel pack assembly.

Tubing Gravel-pack packer

Flapper valve Washpipe

Conventional screens Perforations

Bottom packer

Fig. 3.67. Relatively short perforated intervals accommodate a single completion and frac pack installation using standard screens.

• Set the packer, test packer and pickle pipe. • Perform step rate test (0.5 to 15 bpm), mini-frac test (10, 12 or 15 bpm) and monitor fall-off. • Determine closure pressure, closure time, fluid efficiency, leakoff coefficient and fracture geometry. • Determine optimum fracture size and conductivity. • Determine sand stages, and sizes; then, slow down procedure in case screenout is not evident. • Hold safety meeting to go over procedures with all personnel. • Pump frac treatment. When well screens out, reverse out excess slurry. If screenout is not evident, begin slowing the rate at the predetermined point to induce the final wellbore screenout. • Once fluid loss in under control, pull out of hole. Like conventional gravel packing, fluids and proppants for frac packing are injected through tubing and a 93

Modern Sandface Completion Practices

gravel-pack packer with a service tool in squeeze or circulating configuration (Fig. 3.68). However, to withstand higher pressures during TSO fracturing, service companies adapted standard gravel-packing assemblies. Modifications include increased metal hardness, larger cross-sectional flow areas and minimizing sudden changes in flow direction to reduce metal erosion by fluids and proppants. Annular BOP Annulus surface valve and pressure gauge Service tool Circulating ports QUANTUM gravel-pack packer Crossover ports Ball seat

Ball valve Fluid flow Mechanical fluid-loss control device Washpipe Screens Perforations Temperature and pressure gauge Screens Perforations

Bottom packer

Fig. 3.68. Downhole tools. In gravel packing and frac packing, a service tool directs fluid flow through a gravel-pack packer and around the screen assembly. Squeeze configuration is established by closing the annular blowout preventer (BOP) and the tubing-casing annulus surface valve (left ), or by closing the ball valve downhole (right ). Shutting in the annulus with the downhole ball valve open allows bottomhole pressure to be monitored independent of friction in the tubing. Closing the downhole valve prevents fluid returns to surface and protects weak casing from high pressures; pressure also can be applied to the annulus to offset high pressure in the tubing. Mechanical devices such as flapper valves or formation isolation valve systems prevent excess fluid loss into formations after the service tool is retrieved. 94

Squeeze configuration is used for most frac-pack treatments, especially in wells with production casing that cannot handle high pressures. Circulating position provides a path for fluid returns to surface through the tubing-casing annulus or communication—a “live” annulus—to monitor pressure at surface independent of friction in wellbore tubulars, depending on whether the annular surface valve is open or closed. Friction pressures generated by pumping proppant-laden slurry through tubing and completion equipment often mask true downhole pressure responses when monitoring treating pressure on the tubing. Early service tools used a conventional check valve that prohibited pressure declines from being observed after fracturing. More recent designs of gravel-pack packer tools eliminate the check valve, replacing it with an improved downhole ball valve that allows pressure fluctuations to be monitored in real time during treatments when the ball valve is open. A live annulus allows more accurate evaluation of treatments.124 Frac packing usually begins in squeeze configuration. After tip screenout occurs, establishing circulating configuration ensures complete packing of the screens and grain-to-grain proppant contact. The service tool then is shifted to clean out excess slurry by pumping fluid down the annulus and up the tubing. The amount of upward movement required to shift some service tools pulls reservoir fluids into a wellbore. This swabbing effect can bring formation sand into perforation tunnels before a fracture is completely packed or reduce conductivity between fractures and the internal gravel pack, which can limit frac-pack productivity. Set-down service tools close the downhole ball valve and shift tool configuration with upward movement. This type of tool also is used for deep completions and treatments conducted from floating rigs or drillships. In addition to a variety of reservoir conditions and of fracturing and gravelpacking requirements, treatment execution must address the complexity of completing multiple zones and long intervals. Even the best frac-pack designs end in failure if excess fluid loss into formation causes proppant bridges to form between screens and casing, restricting or blocking annular flow.

Annular proppant packoff, or bridging, results in early treatment termination, low fracture conductivity and an incomplete gravel pack around screens. Placing proppant with sand-exclusion screens in place requires close attention to annular clearances. As frictional pressure increases, there is potential for fluid from slurry in the screencasing annulus to pass through the screens into the washpipe-screen annulus. Fluid bypass worsens as the slurry dehydrates, and proppant concentration increases to an unpumpable state, causing proppant to bridge in the screencasing annulus. Annular blockage near the top of a completion interval prevents continued fracturing of deeper zones or zones with higher in-situ stress and inhibits subsequent packing of the screens. Even a partial flow restriction in the annulus increases frictional pressure drop, restricts rate distribution and limits fracture-height growth across the remainder of the completion interval. Annular voids below a proppant bridge increase the likelihood of screen failure from erosion by produced fluids and fine formation sand.125 Alternate path technology. For homogeneous reservoirs where pay intervals are less than 60 ft (18 m) thick, fractureheight growth typically covers the entire zone. In longer intervals, the probability of complete fracture coverage decreases, and risk of proppant bridging increases dramatically. Long intervals can be split into stages and treated separately. This requires more downhole equipment, such as two stacked frac-packing assemblies (Fig. 3.69), and additional installation time, but increases frac-packing effectiveness. Alternate path technology is also available to gravel pack and frac pack longer intervals (Fig. 3.70). Schlumberger Shunt-tube screens use hollow rectangular tubes, or shunts, welded on the outside of screens to provide additional flow paths for slurry. Exit ports with carbide-strengthened nozzles located along the shunt tubes then allow fluids and proppant to exit below annular restrictions, which allows fracturing and annular packing to continue after restrictions form in the screen-casing annulus. To accommodate higher injection rates for fracturing, shunt-tube screens for frac packing employ slightly

Chapter Three Cased-Hole Sandface Completions

larger tubes than shunt-tube screens for gravel packing. Shunt tubes provide conduits for slurry to bypass collapsed hole and external zonal isolation packers as well as annular proppant gravel bridges at the top of intervals or adjacent to higher permeability zones with high fluid leakoff. If annular restrictions form, injection pressure increases and slurry diverts into the shunt tubes, the only open flow path. This ensures fracture coverage and complete gravel packing around screens across an entire perforated interval.126 The Halliburton Concentric Annular Packing Service (CAPS) is designed to obtain the same results. Fracturing vertical wellbores. Tipscreenout fractures in homogeneous, high permeability formations are thought to form “penny” shaped vertical fractures, which are usually vertical and parallel to the maximum horizontal stress in the formation. Thus, the entire vertical height of the fracture should be in direct contact with the entire wellbore and perforations in a cased hole. Hence, fluids flowing into and being produced from the propped fracture should exit and enter the wellbore uniformly. However, it usually does not work this way because of natural sandstone/shale layers and radial heterogeneities of sandstone reservoirs. The weakest zone will probably be the first to break down and initiate a fracture. Another zone or zones may then break open as injectivity into the first zone is restricted by friction, low permeability barrier or as tip-screenout is approached. However, it is not likely that one continuous propped fracture will be generated from the top to the bottom of a long perforated completion. The result will be that a limited length of only 15 to 30 ft (4.6 to 9.2 m) of a long perforated interval might be in direct contact with the propped fracture. Thick shale beds, longer than ~10 ft (~3.1 m), in a completion interval tend to limit a frac pack to above or below the shale. Even some thinner shale streaks have restricted the height of fractures in weak, high permeability formations. It is often necessary to do two or more separate treatments to stimulate long completions in stratified formations. High treating pressures while initiating, extending and ballooning a fracture usually open some perforations that are

Shunt tubes Tubing

Basepipe

Gravel-pack packer Washpipe Flapper valve AllFRAC screens

Screen Nozzle

Perforations Gravel-pack packer

Casing Shunt tubes Perforations

Screens

Flapper valve Conventional screens Perforations

Bottom packer

Fig. 3.69. Two separate treatments using a stacked-screen assembly to frac pack these longer intervals. Standard screens were used for the lowest zone, which was shorter. Shunt-tube screens were installed to complete the longer upper zone.

filled with mud, sand, gel or solids. This may account for much of the well productivity improvements observed after some frac pack jobs, and is one of the arguments in favor of doing “high rate” gravel packs rather than more expensive frac pack jobs. However, high-treating pressures may also cause the following: • Breaking the cement bond, which may allow communication with unwanted water or gas producing reservoirs. • Initiating a fracture in an adjacent zone. This may be very desirable, as it may contact more oil or gas productive reservoirs, but any fracture that goes out of the target zone may cause early water or unwanted gas breakthrough. A fracture generated into a zone that was not part of the frac plan will take some of the energy

Annular proppant bridge Void

Fracture

Nozzle

Fig. 3.70. Alternate Path Technology. Proppant bridges, or nodes, that form in the screen-casing annulus, commonly as a result of slurry dehydration or premature fracture screenout in zones with lower in situ stress, cause early treatment termination. In wells with conventional sand-exclusion screens, this limits fracture height and frac-pack efficiency. Alternate path technology uses shunt tubes with strategically located exit nozzles welded on the outside of conventional screens (top and middle ). Shunt tubes provide a flow path for slurry that bypasses annular restrictions to allow continued treating of lower intervals and packing of voids around the screens (bottom). 95

Modern Sandface Completion Practices

away from the planned fracture and reduce its width and conductivity. • Branching of the primary fracture within the reservoir may occur when the primary fracture encounters a high strength or low permeability barrier. This is much less likely to occur in short frac packs than in long hydraulic fractures. Fracturing horizontal or deviated wells. If wellbore azimuth is nearly the same orientation of the fracture, a fracture in a non-vertical wellbore will behave in much the same way as a vertical wellbore. However, a wellbore angle of >~15° from vertical that is not in the same plane as a vertical fracture will have limited contact with the fracture. Although multiple fractures may occur, it is unlikely that fractures will be connected to the entire wellbore. That is not to say that this occurs in all wellbores with angles greater than ~15° from vertical. However, more problems are likely at wellbore angles greater than this.127 Discontinuous contact of multiple fractures results in higher velocity of fluid and/or gas produced through gravel-filled perforations, which may significantly restrict production. Therefore, high-shot density perforating is more critical for fractured zones in nonvertical wellbore. The perforation skin effect will be much greater if a limited numbers of perforations are in contact with the fracture. For example: In a well producing 500 b/d from a 50 ft (15.2 m) thick formation with a fracture in contact with only 5 ft (1.5 m) of 6 spf perforations (assuming all fluid is produced from only the fractured zone), the pressure loss through the gravel filled perforations could be 15 times more than if 500 b/d were producing through all 50 ft (15.2 m) of perforations of the unfractured well. This assumes: µ = 1 cp Bo = 1 L = 0.1487 ft Kg = 100 Darcy in 0.5 in. perfs β = 31,623 ft-1 fluid density = 55 lb/ft3. A vertical fracture in a non-vertical wellbore interferes with the packing of gravel in perforations that are not connected with the fracture. Once a frac96

ture is initiated through one point of the completion interval, most, if not all, of the fracture fluid and proppant will flow into the fracture, which reduces the flow of fluid past this point in the wellbore. This may result in a bridge being formed in the screen/casing annulus and loss of sand control beyond the break point. A way to prevent these problems may be to: • Perforate and frac pack only one short zone <30 ft (<9.1 m) • Perforate and frac pack sequentially in <30 ft (<9.1 m) sections • Employ a two-stage frac-pack technique (i.e., frac pack short zones, <30 ft [<9.1 m] each; then wash out the proppant from the wellbore, run the screen and pack gravel in screen/casing annulus) • Employ a wash-down technique for zones longer than 30 ft (<9.1 m) and shorter than 90 ft (27.4 m) gross by fracturing and packing short zones <30 ft (<9.1 m) each; then wash screen into the pack. • Fracture in open hole and run an open-hole gravel pack • Underbalance perforate, surge or wash perforations so that they may be packed with enough gravel to be certain that gravel outside the casing connects all fractures. Perhaps the most successful technique for frac packs in high angle and horizontal wellbores is to use high-density perforating, or slots, and fracturing zones less than 30 ft (9.1 m) at a time. Then, separate them with packers. One paper on the subject of fracture stimulating horizontal wells128 recommends perforating one foot intervals, then creating a large cavity outside the casing before fracturing each interval separately. This technique is also applicable to soft formations, but dual wrapped or prepacked screens should be used to prevent possible sand control and proppant flow-back problems. Another paper129 states that a perforated interval longer than 1.5 times the wellbore diameter of a horizontal wellbore may result in reduced fracture width at the turning point (significantly less than for a perfectly transverse fracture). The result is increased treatment pressure, risk of early screenout and restricted production due to tortuosity. Fracture turning occurs within a few

wellbore diameters away from the wellbore. With a wellbore angle of 45°, the fracture width is reduced by 25% and in a horizontal wellbore the width is reduced by 83%. Width of a single fracture, which transects a horizontal wellbore, is limited by the perforated interval as the fracture path turns to its natural orientation. The fracture width may be reduced by 48% in a 2 ft (0.6 m) perforated interval, by 83% in a 6 ft (1.8 m) interval and by 95% in a 50 ft (15.2 m) interval. Screenless Frac Pack. Placing a resincoated gravel in the perforation tunnels is an optional, but effective, method of controlling sand production. Resincoated gravel is typically pumped as a gel/gravel slurry. Prior to pumping, the gravel is coated with a resin (phenolic, furan, or epoxy). Once the resin-coated gravel is in place, the resin cures to a solid state to form a consolidated gravel filter, removing the need for a screen to hold the gravel in place. Fig. 3.71 is an illustration of a completed well. A number of these screenless frac pack treatments have been completed, apparently with considerable success.130,131 Summary points for considering and performing this type of completion include: • Resin-coated gravel is placed above fracture pressure. • Gravel is underflushed at end of fracture job and allowed to cure, then drilled out. • Must insure all perforations (including those not aligned with the frac) are completely packed with resincoated proppant. • Requires ability to grow into lowstrength layer (no barriers present). • Stability of proppant pack may be questionable, especially in high rate wells. • Cyclic loading weakens proppant pack. • High-risk of premature failure, due to proppant flow back. A tool assembly designed specially for screenless frac pack treatments is the Screenless Single-Trip Multizone (SSTMZ) system. The system provides sand control by installing resin-coated proppant during the pumping process on each of the production intervals, but leaves the casing across those intervals unobstructed except for isolation pack-

Chapter Three Cased-Hole Sandface Completions

ers, which can be used for production management during the life of the well. In addition, the system will allow all stimulation treatments and perforation of all well zones in a single trip (Fig. 3.72). If it is not possible to identify highstrength layers or insufficient information is available to consider a screenless frac pack, use conventional frac-pack methods instead.

Gravel-Packing Method Selection The goal of a gravel pack is to satisfy two criteria: • Provide sand control • Maximize and maintain well performance. The most popular method to accomplish this is in gravel-pack installations. The gravel-pack installations require placement of gravel or proppant around the gravel-pack screen and against the formation face. These placement methods are as follows: High Rate Water Packs (HRWP). These treatments can be pumped at matrix rates, but more commonly at frac rates, depending upon the well conditions. Slurries contain sand (proppant) and completion fluid (or light brine). Proppant is mixed at low concentrations (1 to 2 ppa). No

Slurry Packs. These treatments are pumped at matrix rates. Slurries are typically batch mixed with polymer based carrier fluids. Sand concentrations are typically 8 to 15 ppa. They are used primarily in areas with low horsepower (<250 HHP) applications where batch mixing equipment is preferred. At the present time, <10% of the jobs are placed in this manner in the GOM area. Frac Packs. These treatments are pumped at frac rates. Typical slurries contain proppant and linear or crosslinked polymer gels. Proppant is pumped in stages with subsequent stages of increasing proppant concentration. The philosophy behind the method selection is controversial. Figure 3.73 maps the process between high rate water packing and frac packing. These methods are based upon general guidelines. Slurry packs have become less popular for the most part except in certain cases. The easiest approach is to decide reasons not to frac pack. The following are the reasons commonly used: • Close proximity to water • Pressure limitations in the near wellbore area (i.e., splitting casing into a gas cap) • Marginal economics

Water encroachment risk Yes

Yes No

Gas cap?

Good experience with HRWP’s with sustained low skins No

Yes

Oil No

Zone < 10 ft TVD with > normal reservoir pressure

Yes

No

Weak casing?

Yes

No Yes

Fig. 3.71. Screenless frac pack with resin coated gravel

Gas

Oil or gas well?

Yes

Higher strength sand

Frac equipment available Yes

Yes

Low strength sand

High KH; clean, non-damaged, non-laminated sand No High rate water pack

Perf. MD (>100 ft) inside casing ≤ 5 1/2-in.

Yes 2 step frac pack

No

Frac pack

Fig. 3.73. Method selection of cased-hole sandface completions – frac pack vs HRWP

Fig. 3.72. Screenless single-trip multizone (SSTMZ) tool assembly 97

Modern Sandface Completion Practices

• Fracturing operations compromises the operational success of the completion. All options should be considered before completing a well. The first decision to be made is the selection of an open-hole or cased-hole completion. Actual and perceived risks should be reviewed and the probability to successfully execute the various treatment methods should be weighed. Then, a specific treating option can be selected. The selection of each phase of the completion program should be based upon the characteristics of the specific interval being treated. References 1. Aubert, C., Jr. and Bercegeay, E., “Field Tested Methods Improve Sand Control,” World Oil, January 1971. 2. Maly, G., “Close Attention to the Smallest Job Details Vital for Minimizing Formation Damage,” SPE 5702, 2nd Symposium on Formation Damage, Houston, Texas, January 29-30, 1976. 3. Colle, E.,“Increased Production with Underbalanced Perforation,” Petroleum Engineer International, July 1988, 39-42. 4. Tuttle, R., and Barkman, J., “The Need for Nondamaging Drilling and Completion Fluids,” SPE 4791, First Symposium on Formation Damage, New Orleans, Louisiana, February 7-8, 1974. 5. Howard, S., “Formate Brines for Drilling and Completion: State of the Art,” SPE 30498, Annual Technical Conference & Exhibition, Dallas, Texas, October 22-25, 1995. 6. Krook, G. and Boyce, T., “Downhole Density of Heavy Brines,” SPE 12490 Formation Damage Symposium, Bakersfield, California, February 13-14, 1984. 7. Ezzat, A., “Completion Fluids Design Criteria and Current Technology Weaknesses,” SPE 19434, Formation Damage Control Symposium, Lafayette, Louisiana, February 22-23, 1990. 8. Hall, B., “Workover Fluids, Part 1 – Surfactants Have Differing Chemical Properties That Should be Understood to Ensure Proper Application,” World Oil, May 1986, 111-114. 9. Hall, B., “Workover Fluids, Part 2 – Surfactants Have Differing Chemical Properties That Should be Understood to Ensure Proper Application,” World Oil, June 1986, 64-67. 10. Houchin, L., Dunlap, D., and Hutchinson, J., “Formation Damage during Gravel Pack Completions,” SPE 17166, Formation Damage Control Symposium, Bakersfield, California, February 8-9, 1988. 11. Javora, P., Ali, A., and Bowen, K., “Viscosification of Oil field Brines: Guidelines for the Prevention of Unexpected Formation Damage,” SPE 58728, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 23-24, 2000. 98

12. Scheuerman, R., “Guidelines for Using HEC Polymers for Viscosifying Solids-Free Completion and Workover Brines,” Journal of Petroleum Technology, February 1983, 306-314. 13. Kelco Xanvis Product bulletin. 14. Lau, H., “Laboratory Development and Field Testing of Succinoglycan as a Fluid Loss Control Fluid,” SPE 26724, Offshore European Conference, Aberdeen, Scotland, September 7-10, 1994. 15. Nguyen, H. and LaFontaine, J., “Effect of Various Additives on the Properties of the Clarified XC Polymer System,” SPE 19404, Formation Damage Control Symposium, Lafayette, Louisiana, February 22-23, 1990. 16. Vollmer, D. and Alleman, D., “HEC No Longer the Preferred Polymer,” SPE 65398, International Symposium on Oil Field Chemistry, Houston, Texas, February 13-16, 2001. 17. Nasr-El-Din, H., Al-Mutairi, S., and Al-Driweesh, S., “Lessons Learned from Acid Pickle Treatments of Deep/Sour Gas Wells,” SPE 73703, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 20-21, 2002. 18. Sollee, S., Elson, T., and Lerma,M., “Field Application of Clean Completion Fluids,” SPE 14318, Annual Technical Conference and Exhibition, Las Vegas, Nevada, September 22-25, 1985. 19. Tuttle, R., and Barkman, J., “The Need for NonDamaging Drilling and Completion Fluids,” SPE 4791, First Symposium on Formation Damage, New Orleans, Louisiana, February 7-8, 1974. 20. Brannon, D., Netters, C., and Grimmer, P., “Matrix Acidizing Design and Quality Control Techniques Prove Successful in Main Pass Area Sandstone, SPE 14827, Seventh Symposium on Formation Damage Control, Lafayette, Louisiana, February 26-27, 1986. 21. Filtration Technology Corporation booklet. 22. API RP 13J, “Testing Heavy Brines,” 2nd Edition, March 1996. 23. Martin, A., “Choosing The Right Gun,” Petroleum Engineer International, October 1998 vol. 71, no. 10: 59-72. 24. Naturally occurring or resin-coated sand and high-strength bauxite or ceramic synthetics, sized by screening according to standard U.S. mesh sieves, are used as proppants. Gravel consists of extremely clean, round and carefully sized sand that is small enough to act as a filter and prevent production of formation particles, but large enough to be held in place across productive intervals by a slottedscreen assembly. 25. Behrmann, L., Brooks, J., Farrant, S., Fayard, A., Venkitaraman, A., Brown, A., Michel, C., Noordermeer, A., Smith, P. and Underdown, D., “Perforating Practices That Optimize Productivity,” Oilfield Review, Spring 2000 vol. 12, no. 1: 52-74. 26. Folse, K., Allin, M., Chow, C., and Hardesty, J., “Perforating System Selection for Optimum Well Inflow Performance.” SPE 73762 presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, February 20-21, 2002. 27. Ibid.

28. Pratt, D., Carrera, V., “Performance Patterns for Perforating Charges Optimized in Hard and Soft Materials.” SPE 52203 presented at the SPE Mid-Continent Operations Symposium, Oklahoma City, Oklahoma, March 28-31, 1999. 29. Bell, W., Golian, T., Ellis, R., and Moseley, P., “Predicting Downhole Shaped Charge Gun Performance – Viability of Method,” SPE 60129, 1999. 30. Recommended Practices for Evaluation of Well Perforators, API RP 43, 4th Edition, Aug. 1985. 31. Recommended Practices for Evaluation of Well Perforators, API RP 43, 5th Edition, Jan. 1991. 32. Recommended Practices for Evaluation of Well Perforators, API RP 19B, 1st Edition, Nov. 2000. 33. Halleck, P., and Dogulu, Y., “The Basis and Use of the API RP43 Flow Test for Shaped-Charge Oil Well Perforators,” Journal of Canadian Petroleum Technology, May 1997 vol. 36, No. 5. 34. Pucknell, J., and Behrmann, L., “An Investigation of the Damaged Zone Created During Perforating,” SPE 22811 presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 6-9, 1991. 35. Bartusiak, R., Halleck, P., and Behrmann, L., “Experiments Investigate Underbalance Flow Velocity and Volume Needed to Obtain Perforation Cleanup,” Journal of Petroleum Science and Engineering, 1997 v.17: 19-28. 36. Folse, K., Allin, M., Chow, C., and Hardesty, J., “Perforating System Selection for Optimum Well Inflow Performance.” SPE 73762 presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, February 20-21, 2002. 37. Pucknell, J., and Behrmann, L., “An Investigation of the Damaged Zone Created During Perforating,” SPE 22811 presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 6-9, 1991. 38. Behrmann, L., and McDonald, B., “Underbalance or Extreme Overbalance,” SPE 31083, presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, USA, February 14-15, 1996; also in SPE Production & Facilities (August 1999): 187-196. 39. Pucknell, J., and Behrmann, L., “An Investigation of the Damaged Zone Created by Perforating,” SPE 22811, presented at the 66th SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 6-9, 1991. 40. Swift, R., Behrmann, L., Halleck, P. and Krogh, K., “Micro-Mechanical Modeling of Perforating Shock Damage,” SPE 39458, presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, February 18-19, 1998. 41. Behrmann, L., Li, J., Venkitaraman, A. and Li, H., “Borehole Dynamics During Underbalanced Perforating,” SPE 38139, presented at the SPE European Formation Damage Control Conference, The Hague, The Netherlands, June 2-3, 1997.

Chapter Three Cased-Hole Sandface Completions

42. Klotz, J., Krueger, R. and Pye, D., “Effect of Perforation Damage on Well Productivity,” Journal of Petroleum Technology, November 1974 vol. 26: 1303. 43. Behrmann, L., et al, “Perforating Practices That Optimize Productivity,” Oilfield Review, Spring 2000 vol. 12, no. 1: 52-74. 44. Behrmann, L., Huber, K., McDonald, B., Couët, B., Dees, J., Folse, R., Handren, P., Schmidt, J. and Snider, P., “Quo Vadis, Extreme Overbalance?” Oilfield Review, Autumn 1996 vol. 8, no. 3: 18-33. 45. Bell, W., “Perforating Underbalanced—Evolving Techniques,” Journal of Petroleum Technology, October 1984 vol. 36: 1653-1652. 46. Behrmann, L., et al, “Perforating Practices That Optimize Productivity,” Oilfield Review, Spring 2000 vol. 12, no. 1: 52-74. 47. Behrmann, L., Pucknell, J., Bishop, S., and Hsia, T., “Measurement of Additional Skin Resulting From Perforation Damage,” SPE 22809, presented at the 66th SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 6-9, 1991. Hsia, T. and Behrmann, L., “Perforating Skins as a Function of Rock Permeability and Underbalance,” SPE 22810, presented at the 66th SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 6-9, 1991. Pucknell, J. and Behrmann, L., “An Investigation of the Damaged Zone Created by Perforating,” SPE 22811, presented at the 66th SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 6-9, 1991. Behrmann, L., Pucknell, J., and Bishop, S., “Effects of Underbalance and Effective Stress on Perforation Damage in Weak Sandstone: Initial Results,” SPE 24770, presented at the 67th Annual Technical Conference and Exhibition, Washington DC, October 4-7, 1992. Bartusiak, R., Behrmann, L., and Halleck, P., “Experimental Investigation of Surge Flow Velocity and Volume Needed to Obtain Perforation Cleanup,” SPE 26896, presented at the SPE Eastern Regional Conference and Exhibition, Pittsburgh, Pennsylvania, November 2-4, 1993. Also in Journal of Petroleum Science and Engineering 1997 vol. 17: 19-28. 48. Behrmann, L., et al, “Perforating Practices That Optimize Productivity,” Oilfield Review, Spring 2000 vol. 12, no. 1: 52-74. 49. Suman, G., Ellis, R. and Snyder, R., Sand Control Handbook, Second Edition, Gulf Publishing Company, Houston, Texas, 1991. 50. Behrmann, L., et al, “Perforating Practices That Optimize Productivity,” Oilfield Review, Spring 2000 vol. 12, no. 1: 52-74. 51. Suman, G., Ellis, R. and Snyder, R., Sand Control Handbook, Second Edition, Gulf Publishing Company, Houston, Texas, 1991. 52. Ibid. 53. Almaguer, J., Manrique, J., Wickramasuriya, S., Habbtar, A., López-de-Cárdenas, J., May, D., McNally, A. and Sulbarán, A., “Orienting Perforations in the Right Direction,” Oilfield Review, Spring 2002 vol. 14, no. 1: 16-31.

54. Abass, H., Meadows, D., Brumley, J., Hedayatie, S. and Venditto, J., “Oriented Perforations – A Rock Mechanics View,” SPE 28555, presented at the SPE Annual Technical Meeting, New Orleans, Louisiana, September 25-28, 1994. Sulbaran, A., Carbonell, R. and López-de-Cárdenas, J., “Oriented Perforating for Sand Prevention,” SPE 57954, presented at the SPE European Formation Conference, The Hague, The Netherlands, May 31June 1, 1999. 55. Ibid. Abass, H., et al. 56. Mason, J., Dees, J., and Kessler, N., “Block Tests Model the Near-Wellbore in a Perforated Sandstone,” SPE 28554, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, September 25-28, 1994. 57. Behrmann, L., and Nolte, K., “Perforating Requirements for Fracture Stimulations,” SPE 39453, presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, February 18-19, 1998. 58. Behrmann, L., et al, “Perforating Practices That Optimize Productivity,” Oilfield Review, Spring 2000 vol. 12, no. 1: 52-74. 59. Folse, K., Dupont, R., Coats, C. and Finley, D., “Field Performance of Propellant/Perforating Technologies to Enhance Placement of Proppant on High Risk Sand Control Completions,” SPE 72135 presented at the SPE Asia Pacific Improved Oil Recovery Conference in Kuala Lumpur, Malaysia, October 8-9, 2001. 60. van Batenburg, D., Amor, B. and Belhaouas, R., “New Techniques for Hydraulic Fracturing in the Hassi Messaoud Field,” SPE 63104, presented at the SPE Annual Technical Conference and Exhibition in Dallas, Texas, October 1-4, 2000. 61. El-Bermawy, H. and El-Assai, H., “A Unique Approach to Enhancing Production from Depleted, Highly Laminated Sand Reservoirs Using a Combined Propellant/Perforating Technique,” SPE 68101, presented at the SPE Middle East Oil Show in Baharain, March 17-20, 2001. 62. Rogers, E., “Sand Control in Oil and Gas Wells,” Oil & Gas Journal, November 1, 8, 15 and 22, 1971, 54-68. 63. Tiffin, D., King, G., Larese, and Britt., L., “New Criteria for Gravel and Screen Selection for Sand Control,” SPE 39437. Formation Damage Control Symposium, Lafayette, Louisiana, February 18-19, 1998. 64. Gay, L., “Frigg Field: Successful Sand Control for High Flow Rate Gas Wells,” SPE 7665, AIMMPE, 1978. 65. Penberthy, W. and Shaughnessy, C., “Sand Control, SPE Series on Special Topics,” Volume 1, 1992. 66. Ibid. 67. Gurley, D., Copeland, C., and Hendrick, Jr., J., “Design, Plan, and Execution of Gravel-Pack Operations for Maximum Productivity,” Journal of Petroleum Technology, October 1977, 1259-1266.

68. Mullen, M., Norman, W., and Stewart, B., “Evaluation of Bottomhole Pressure in 40 Soft Rock Frac Pack Completions in the Gulf of Mexico,” SPE 28532, Annual Technical Conference, New Orleans, September 25-28, 1994. 69. Suman, G., Jr., Ellis, R., and Snyder, R., Sand Control Handbook, 2nd Ed., Gulf Publishing, May 1991, 42-50. 70. Mathis, S. and Malochee, S., “Improved Diverter Selection for Acid-Prepack Gravel Pack Completions,” SPE 38188, European Formation Damage Conference, The Hague, June 2-3, 1997. 71. Penberthy, W. ”Design and Productivity of Gravel Packed Completions,” SPE 8428, Annual Technical Conference, Las Vegas, Nevada, September 23-26, 1979. 72. Penberthy, W., “Gravel Placement Through Perforations and Perforation Cleaning for Gravel Packing,” Journal of Petroleum Technology, February 1988, 205-212. 73. Patel, Y., Troncosco, J., Saucier, R., and Credeur, D., “High-Rate Pre-Packing Using Non-Viscous Carrier Fluid Results in Higher Production Rates in South Pass Block 61 Field,” SPE 28531, Annual Technical Conference, New Orleans, Louisiana, September 25-28, 1994. 74. McLeod., H., Jr. and Pashen, M., “Well Completion Audits to Evaluate Gravel Packing Procedures,” SPE Drilling and Completion, December 1977, 228-237. 75. Ledlow, L., Johnson, M., Richard, B., and Huval, T., “High-Pressure Packing with Water: An Alternative Approach to Conventional Gravel Packing,” SPE 26543, Annual Technical Conference, Houston, Texas, October 3-6, 1993. 76 Ali, S., Vitthal, S, and Weaver, J., “Improvements in High-Rate Water Packing with Surface-Modification Agent,” SPE 58755, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 23-24, 2000. 77. Penberthy, W., “Gravel Placement Through Perforations and Perforation Cleaning for Gravel Packing,” Journal of Petroleum Technology, February 1988, 205-212. 78. Sparlin, D., “Fight Sand with Sand-A Realistic Approach to Gravel Packing,” SPE 2649, Annual Fall Meeting, Denver, Colorado, September 28-October 1, 1969. 79. Lybarger, J., Scheuerman, R., and Willard, R., “Water-Base Viscous Gravel Pack System Results in High Productivity in Gulf Coast Completions,” SPE 4774, Symposium on Formation Damage Control, New Orleans, Louisiana, February 7-8, 1974. 80. Rensvold, R. and Decker, L., “Full Scale Gravel Packing Model Studies,” SPE 8074, European Offshore Petroleum Conference, London, England, October 24-27, 1978. 81. Gurley, D., Copeland, C., and Hendrick, Jr., J., “Design, Plan, and Execution of Gravel-Pack Operations for Maximum Productivity,” Journal of Petroleum Technology, October 1977, 1259-1266.

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82. Saucier, R., “Considerations in Gravel Pack Design,” Journal of Petroleum Technology, February 1974, 205-212; Trans., AIME, 257. 83. Welling, R., Jonathan, P., Reijnen, P. and Samuel, A., “Quantifying the Factors Influencing Gravel Placement and Productivity of an Internally Gravel Packed Completion Based on Field Data Analysis,” SPE 30113, European Formation Conference, The Hague, May 15-16, 1995. 84. McLarty, J. and DeBonis, V., “Gulf Coast Section SPE Production Operations Study Group—Technical Highlights from a Series of Frac Pack Treatment Symposiums.” SPE 30471, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 22-25, 1995. 85. Ibid 86. Hainey, B. and Troncoso, J., “Frac-Pack: An Innovative Stimulation and Sand Control Method.” SPE 23777, presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, February 26-27, 1992. 87. Monus, F., Broussard, F., Ayoub, J. and Norman, W., “Fracturing Unconsolidated Sand Formations Offshore Gulf of Mexico.” SPE 24844, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, October 4-7, 1992. Mullen, M., Stewart, B. and Norman, W., “Evaluation of Bottom Hole Pressures in 40 Soft Rock Frac-Pack Completions in the Gulf of Mexico.” SPE 28532, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 25-28, 1994. 88. Wong, G., Fors, R., Casassa, J., Hite, R. and Shlyapobersky, J., “Design, Execution, and Evaluation of Frac and Pack (F&P) Treatments in Unconsolidated Sand Formations in the Gulf of Mexico.” SPE 26563, presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, October 3-6, 1993. Roodhart, L., Fokker, P., Davies, D., Shlyapobersky, J. and Wong, G., “Frac and Pack Stimulation: Application, Design, and Field Experience from the Gulf of Mexico to Borneo.” SPE 26564, presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, October 3-6, 1993. 89. Hannah, R., Park, E., Walsh, R., Porter, D., Black, J., and Waters, F., “A Field Study of a Combination Fracturing/Gravel Packing Completion Technique on the Amberjack, Mississippi Canyon 109 Field.” SPE 26562, presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, October 3-6, 1993; also in SPE Production & Facilities 9, No. 4 (November 1994), 262–266. 90. Ali, S., Norman, D., Wagner, D., Ayoub, J., Desroches, J., Morales, H., Price, P., Shepherd, D., Toffanin, E., Troncoso, J. and White, S., “Combined Stimulation and Sand Control.” Oilfield Review 14, no. 2, Summer 2002: 30-47. 91. Raymond, L. and Binder, G., Jr., “Productivity of Wells in Vertically Fractured, Damaged Formations,” Journal of Petroleum Technology, January 1967, 120-130. 100

92. Stewart, B., Mullen, M., Ellis, R., Norman, W. and Miller, W., “Economic Justification for Fracturing Moderate to High Permeability Formations in Sand Control Environments.” SPE 30470, Annual Technical Conference, October 22-25, 1995. 93. Raymond, L. and Binder, G., Jr., “Productivity of Wells in Vertically Fractured, Damaged Formations, Journal of Petroleum Technology, January 1967, 120-130. 94. Ali, S., Dickerson, R., Bennett, C., Bixenman, P., Parlar, M., Price-Smith, C., Cooper, S., Desroches, J., Foxenberg, B., Godwin, K., McPike, T., Pitoni, E., Ripa, G., Steven, B., Tiffin, D. and Troncoso, J., “High-Productivity Horizontal Gravel Packs,” Oilfield Review 13, No. 2, Summer 2001: 52-73. 95. Ali, S., Norman, D., Wagner, D., Ayoub, J., Desroches, J., Morales, H., Price, P., Shepherd, D., Toffanin, E., Troncoso, J. and White, S., “Combined Stimulation and Sand Control.” Oilfield Review 14, no. 2, Summer 2002: 30-47. 96. Hannah, R., Park, E., Walsh, R., Porter, D., Black, J. and Waters, F., “A Field Study of a Combination Fracturing/Gavel Packing Completion Technique on the Amberjack, Mississippi Canyon 109 Field,” SPE 26562, Annual Technical Conference, Houston, Texas, October 3-6, 1993; also in SPE Production & Facilities 9, No. 4, November 1994: 262-266. Ayoub, J., Kirksey, J., Malone, B. and Norman, W., “Hydraulic Fracturing of Soft Formations in the Gulf Coast,” SPE 23805, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 26-27, 1992. DeBonis, V., Rudolph, D. and Kennedy, R., “Experiences Gained in the Use of Frac Packs in Ultralow BHP Wells, U.S. Gulf of Mexico,” SPE 27379, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 7-10, 1994. 97. Tiner, R. and Ely, J., “Frac Packs – State of the Art,” SPE 36456, Annual Technical Conference, Denver, Colorado, October 6-10, 1996 98. Stewart, B., Mullen, M., Ellis, R., Norman, W., and Miller, K., ”Economic Justification for Fracturing Moderate to High Permeability Formations in Sand Control Environments,“ SPE 30470, Annual Technical Conference, Dallas, Texas, October 22-25, 1995. 99. Mathur, A., Ning, X., Marcinew, R., Ehlig-Economides, C. and Economides, M. “ Hydraulic Fracture Stimulation of Highly Permeable Formations: The Effect of Critical Fracture Parameters on Oilwell Production and Pressure, SPE 30652, Annual Technical Conference, October 22-25, 1995. 100. Mathis, S. and Saucier, R., “Water-Fracturing vs. Frac-Packing: Well Performance Comparison and Completion Type Selection Criteria, SPE 38593, Annual Technical Conference, San Antonio, Texas, October 5-8, 1997. 101. Gidley, J., Holditch, S., Nierode, D. and Veatch, R., “Recent Advances in Hydraulic Fracturing,” SPE Monograph 12, Richardson, Texas, 1989:

102. Stewart, B., Mullen, M., Brown, J. and Norman, W., “Step-Rate, Calibration Injection and Treating Pressure Anomalies in Soft Rock High Permeability Formations: An Explanation Based on Bottom Hole Pressure and Production Results,” SPE 29444, Production Operations Symposium, Oklahoma City, Oklahoma, April 2-4, 1995. 103. Lacy, L., Rickards, A. and Bilden, D. “Fracture Width and Embedment Testing in Soft Reservoir Sandstone,” SPE 36421, Annual Technical Conference, Denver, Colorado, October 6-9, 1996. 104. Lacy, L., Rickards, A. and Ali, S., “Embedment and Fracture Conductivity in Soft Formations Associated with HEC, Borate and Water-Based Fracture Designs,” SPE 38590, Annual Technical Conference, October 5-8, 1997. 105. Raymond, L. and Binder, G., Jr., “Productivity of Wells in Vertically Fractured, Damaged Formations,” Journal of Petroleum Technology, January 1967, 120-130. 106. Hainey, B. and Troncoso, J., “Frac-Pack: An Innovative Stimulation and Sand Control Technique,” SPE 23777, presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, February 26-27, 1992. 107. Morales, R., Gadiyar, B., Bowman, M., Wallace, C. and Norman, W., “Fluid Characterization for Placing an Effective Frac/Pack,” SPE 71658, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 30-October 3, 2001. 108. Monus, F., Broussard, F., Ayoub, J., and Norman, W., “Fracturing Unconsolidated Sand Formations Offshore Gulf of Mexico,” SPE 24844, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, October 4-7, 1992. 109. Morales, R., Gadiyar, B., Bowman, M., Wallace, C. and Norman, W., “Fluid Characterization for Placing an Effective Frac/Pack,” SPE 71658, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 30-October 3, 2001. 110. Ali, S., Norman, D., Wagner, D., Ayoub, J., Desroches, J., Morales, H., Price, P., Shepherd, D., Toffanin, E., Troncoso, J. and White, S., “Combined Stimulation and Sand Control.” Oilfield Review 14, no. 2, Summer 2002: 30-47. 111. Salz, L., “Relationship between Fracture Propagation Pressure and Pore Pressure,” SPE 6870, Annual Technical Conference, Denver, Colorado, October 7-12, 1977. 112. Monus, F., Broussard, F., Ayoub, J., and Norman, W., “Fracturing Unconsolidated Sand Formations Offshore Gulf of Mexico,” SPE 24844, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, October 4-7, 1992. 113. Saucier, R., “Considerations in Gravel Pack Design,” Journal of Petroleum Technology 26, no. 2, February 1974, 205–212. 114. Hainey, B. and Troncoso, J., “Frac-Pack: An Innovative Stimulation and Sand Control Technique,” SPE 23777, presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, February 26-27, 1992.

Chapter Three Cased-Hole Sandface Completions

115. Ali, S., Norman, D., Wagner, D., Ayoub, J., Desroches, J., Morales, H., Price, P., Shepherd, D., Toffanin, E., Troncoso, J. and White, S., “Combined Stimulation and Sand Control.” Oilfield Review 14, no. 2, Summer 2002: 30-47. 116. American Petroleum Institute, “Recommended Practices for Evaluating Short Term Proppant Pack Conductivity,” API RP 61, October 1989. 117. Vincent, M., Pearson, C. and Kullman, J., “NonDarcy and Multiphase Flow in Propped Fractures: Case Studies Illustrate the Dramatic Effect on Well Productivity,” SPE 54630, Western Regional Meeting, Anchorage, Alaska, May 26-28, 1999. 118. Monus, F., Broussard, F., Ayoub, J., and Norman, W., “Fracturing Unconsolidated Sand Formations Offshore Gulf of Mexico,” SPE 24844, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, October 4-7, 1992. 119. Ali, S., Norman, D., Wagner, D., Ayoub, J., Desroches, J., Morales, H., Price, P., Shepherd, D., Toffanin, E., Troncoso, J. and White, S., “Combined Stimulation and Sand Control.” Oilfield Review 14, no. 2, Summer 2002: 30-47. 120. Smith, M., Miller II, W., and Haga, J., “Tip Screenout Fracturing: A Technique for Soft, Unstable Formations,” SPE Production Engineering, May 1987, 95-103. 121. Monus, F., Broussard, F., Ayoub, J., and Norman, W., “Fracturing Unconsolidated Sand Formations Offshore Gulf of Mexico,” SPE 24844, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, October 4-7, 1992. 122. Hannah, R., Park, E., Walsh, R., Porter, D., Black, J., and Waters, F., “A Field Study of a Combination Fracturing/Gravel Packing Completion Technique on the Amberjack, Mississippi Canyon 109 Field.” SPE 26562, presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, October 3-6, 1993; also in SPE Production & Facilities 9, no. 4 (November 1994), 262–266. 123. Ali, S., Norman, D., Wagner, D., Ayoub, J., Desroches, J., Morales, H., Price, P., Shepherd, D., Toffanin, E., Troncoso, J. and White, S., “Combined Stimulation and Sand Control.” Oilfield Review 14, no. 2, Summer 2002: 30-47. 124. Mullen, M., Stewart, B. and Norman, W., “Evaluation of Bottom Hole Pressures in 40 Soft Rock FracPack Completions in the Gulf of Mexico.” SPE 28532, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 25-28, 1994. 125. Ali, S., Norman, D., Wagner, D., Ayoub, J., Desroches, J., Morales, H., Price, P., Shepherd, D., Toffanin, E., Troncoso, J. and White, S., “Combined Stimulation and Sand Control.” Oilfield Review 14, no. 2, Summer 2002: 30-47. 126. Ibid. 127. Weng, X., “Fracture Initiation and Propagation from Deviated Wellbores,” SPE 26597, Annual Technical Conference, Houston, Texas, October 3-6,1993.

128. Hagist, P., Abass, H., Harry, J., Hunt, J., Shunway, M. and Besler, M., “A Case History of Completing and Fracture Stimulating a Horizontal Well,” SPE 29443, Production Operations Symposium, Oklahoma City, Oklahoma, April 2-4, 1995. 129. Ddeimbacher, F., Economides, M. and Jensen, O., “Generalized Performance of Hydraulic Fracture with Complex Geometry Intersecting Horizontal Wells,” SPE 25505, Production Operations Symposium, Oklahoma City, Oklahoma, March 21-23, 1993. 130. Kirby, R., Clement, C. and Asbill. S., “Screenless Frac Pack Completions Utilizing Resin Coated Sand in the Gulf of Mexico,” SPE 30467, Annual Technical Conference, Dallas, Texas, October 22-25, 1995. 131. Putra, P., Nasution, R., Thurston, F., Moran, J. and Malone, B., “TSO Frac-Packing: Pilot Evaluation to Full-Scale Operation in a Shallow Unconsolidated Heavy Oil Reservoir, SPE 37533, International Thermal Operations & Heavy Oil Symposium, Bakersfield, California, February 10-12, 1997.

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Summary Prior to leaving the discussion of downhole operations and moving to a discussion of surface operations and equipment, it might be appropriate to restate the factors that make a successful sand control completion. The true success or failure of a sand control application must always be measured against three related criteria: • Stopping the movement and production of sand • Maintaining maximum well productivity • Paying for treatment costs and realizing a satisfactory return on investment within a reasonable period of time.

102

CHAPTER FOUR

Surface Operations and Equipment Surface Equipment and Techniques • Monitoring and Control • Evaluation Techniques

ll of the sand control techniques, which have been discussed previously in this handbook, employ various types of surface equipment at the rig site, whether offshore or on land. The only possible exception being the installation of a stand-alone screen in an open-hole sandface completion. The costs associated with deploying and using specialized equipment for whatever type of treatment should always be considered during the completion selection and design process. For example, open-hole gravel packing eliminates the cost of cementing and perforating casing. Additionally, an open-hole gravel pack requires considerably less hydraulic horsepower and blending equipment than a cased-hole HRWP or frac-pack. Offshore, a stimulation vessel is usually the only practical way to deliver the surface equipment necessary to perform downhole treatments. Availability and the high cost of stimulation vessels are major considerations in the decision to perform cased-hole HRWP or frac-pack completions offshore. Regardless of location, open-hole gravel packs can be performed at lower cost using more readily available equipment, either installed on an offshore rig or transported to a land wellsite.1 Another example of potential cost savings in offshore operations is to use seawater as the base completion fluid. Because a stimulation vessel can obtain water at sea instead of having to travel back to shore to take on fresh water between frac-pack treatments, the use of seawater as a base fluid minimizes completion costs and valuable rig downtime.2 When considering this option for a frac-pack treatment, formation compatibility must be established and a proper gel system must be specified. The various companies providing stimulation services invest heavily in

A

research and development related to all aspects of well completions, including the equipment used to pump, control and monitor sand control treatments. The following is at best a brief overview of surface operations and equipment requirements necessary to perform various pumping procedures. An overview of the systems used to control, monitor and evaluate sand control treatments has also been included.

Surface Equipment and Techniques Specialized equipment mounted on trucks, skids or offshore vessels is available for all types of sand control techniques. Skid-mounted equipment has become very popular and somewhat of an industry standard because it provides maximum deployment versatility. In most treatments, a blender is used to mix and transfer gravel/proppant and a treating fluid to high-pressure frac pumps. The proppant-laden treating fluid is then pumped through a highpressure manifold to the well. Over time, treatments have grown in complexity involving various flow rates, pressures, proppant concentrations, liquid and dry additives and total volumes of fluid. Service companies employ a wide variety of equipment for various types of well completions. Today, a well treatment, and the equipment required to perform the treatment, is often custom packaged to meet a specific set of job design parameters. There are four basic types of equipment used for both land and offshore sand control treatments: mixing and blending, pumping, proppant handling and monitoring/control. The following discussion is only representative of the many variations of this equipment, which is available from numerous service companies.

Mixing and Blending Equipment Blending equipment is used to prepare the treatment fluid by mixing the correct proportions of liquid and dry chemical additives into the stimulation fluid. Mixing can be done either continuously throughout the treatment or batch-mixed in fracturing tanks before the stimulation treatment. For continuous mixing of the treatment fluid that contains polymer, the base fluid is prepared using a preblender. The preblender is used to mix a liquid gel concentrate with water from tanks. It provides sufficient hydration time to yield the required base-fluid gel viscosity. The hydrated gel is then pumped from the hydration tank to the blender. In addition to the additives, a blender is used to mix gravel/proppant with the treatment fluid. For a low viscosity treatment, such as a water pack or HRWP, gravel can be delivered by a gravel-injection auger that precisely measures feed rates to the mixing tub of a Baker Hi-Rate Gravel Infuser (Fig. 4.1). It can be mixed continuously with a Halliburton Constant Level Additive Mixing (CLAM) system (Fig. 4.2). Both of these units eliminate the necessity of batch-mixing large volumes of low gravel concentration slurries, while allowing the sand concentration to be

Fig. 4.1. Baker Hi-Rate Gravel Infuser 103

Modern Sandface Completion Practices

Fig. 4.6. BJ skid-mounted blender

Fig. 4.2. Halliburton CLAM mixing system

5

10 Rate

2

6

Sand auger

4

Densimeter

1 0 15

Fig. 4.7. Slurry pack batch blender

2 20

25

30

35

40

0 45

e

Elapsed time, min.

i

BHp

Fig. 4.3. Time vs mix ratio/rate plot

Efficiency

3

8 Ratio, bpm

Mix ratio, ppa

4

hA Flow rate

Fig. 4.8. Pump chart – performance curves.3 Head or pressure (labeled hA, black), efficiency (labeled e, green), and brake horsepower (labled i, red ), based on the flow rate.

Fig. 4.4. Halliburton single-skid FracPac blender

Fig. 4.9. Schlumberger 1,200 HHp frac pump

Fig. 4.5. Schlumberger POD II bender 104

Fig. 4.10. Baker SC-1,200 frac pump

ramped as necessary. Comparable equipment is available from several sources. The time versus mix ratio/rate plot (Fig. 4.3) illustrates the accuracy of gravel addition, which is possible with any of these units. When frac packing, blenders such as those illustrated in Figures 4.4, 4.5 and 4.6 are capable of blending and pumping proppant slurry at the designed rates. These units are computer controlled to precisely deliver the solid/liquid ratio at design values throughout the entire job in either ramp or stairstep mode. A slurry pack (high viscosity/high gravel density) gel is prepared with a batch blender like the one in Figure 4.7. Wellsite computers, programmed with predetermined set points for mixture concentrations, are used to control the quality of the mixing process. Regardless of the mixing flow rate, the computers maintain the required slurry concentrations. Operational parameters (i.e., tub level, mixer agitation and pressures) for the blender are also placed under automatic control, thereby minimizing the potential for human error. Pumping Equipment Pumping equipment has evolved from pumps rated at 300 horsepower (hp) to today's pumps rated at 2,000+ hp produced from a single crankshaft pump. The pressure requirements for well treatments have also increased from 2,000 psi to 20,000 psi. Computer controlled, power-shift transmissions synchronize the engine speed with the gear shift so that pump rates before and after the shift are the same. Computer-controlled pumping equipment also allows automatic pressure and/or rate control. It is important to understand that horsepower is a rating of the energy a pump can supply to move fluid. Hydraulic horsepower (HHp) refers to the power actually applied to moving the fluid, assuming there are no efficiency losses in either the pump portion of the unit or the engine that drives the pump. This is not what the manufacturer advertises as the horsepower of the pump. Brake horsepower (BHp) is the power supplied to the pump by the engine and takes into account the pump’s efficiency rating. BHp is the figure that manufacturers list as the "horsepower rating" of

Chapter Four Surface Operations and Equipment

their pumps. A pump chart provides information to determine HHp in conjunction with the following equation: HHp = e x BHp

Where: e = Efficiency ratio All pumps have a corresponding pump chart similar to Figure 4.8. In this chart, note that brake horsepower can and usually does change with flow rate. In addition, as pressure increases, flow rate decreases. It is a good idea to have a pump chart that is as complete as possible. Required flow (injection) rates and pressures required to pump a sand control treatment can be obtained from a number of frac pumps. Figure 4.9 is a 1,200 HHp frac pump from Schlumberger and Figure 4.10 is a 1,200 HHp frac pump from Baker. Figure 4.11 is a BJ skid-mounted frac pump. Similar pumps are available from other service companies. Also, note the following HHp relationship and reference suppliers’ pertinent pump charts to determine the required number of frac pumps for a given sand control treatment: HHp =

(Q × Pw )

Where: Q = Rate, bpm Pw = Pressure, psi Proppant Handling Several methods are used to store, move and deliver proppants to the blender for mixing. Bagged proppant can be manually dumped into a blender or the blender can be fed via a pneumatic delivery system. Larger well treatment designs using ever-increasing quantities of gravel/proppant have necessitated the use of large-volume, field storage bins (Fig. 4.12) and automated blender feed systems. Offshore Equipment For offshore sand control operations, to save the costs associated with building and equipping a stimulation vessel, the required surface equipment can sometimes be mounted on the rig platform. Figure 4.13 illustrates an example equipment layout diagram for an offshore rig.

Acid tank

From rig floor

Pickle return

When a frac pack or HRWP treatment is specified offshore, a specially equipped stimulation vessel may be required to do the job. Major service companies have made large investments in the construction of purpose-built vessels equipped with high-volume mixing equipment, high-pressure pumps and sophisticated monitoring systems. I llustrated are stimulation vessels from Baker (Fig. 4.14), BJ Services (Fig. 4.15), Halliburton (Fig. 4.16) and Schlumberger (Fig. 4.17).

Monitoring and Control Monitoring sand control treatments has progressed from analog pressure gauges, stopwatches and chart recorders to full computer monitoring and control. More than a thousand different parameters can be monitored and recorded during a stimulation treatment. These parameters are not limited to treatment fluids, proppant and addi-

To rig floor HP pump

40.81

C-Pump

Additive pump

Fig. 4.11. BJ skid-mounted frac pump

Blender Holding tank

Sand silo Work box Monitoring unit Cat walk

Fig. 4.12. Proppant silo, which is completely weather proof

Fig. 4.13. Equipment layout diagram for deck of offshore rig 105

Modern Sandface Completion Practices

Fig. 4.17. Schlumberger’s Galaxie stimulation vessel Fig. 4.14. Baker’s RC Baker stimulation vessel

Fig. 4.15. BJ Services’ Blue Ray stimulation vessel

Fig. 4.18. Baker BDAQ skid-mounted control cabin

tives. They can include various parameters used to monitor the equipment performing the treatment. Monitoring the treatment fluids is an essential part of quality control. Primary fluid parameters monitored and recorded during a stimulation treatment include, but are not limited to, pressures, temperatures, flow rates, proppant and additive concentrations (pH, and viscosity). All of these parameters can be plotted or displayed during the job along with real-time calculations of downhole parameters. Equipment parameters, which are monitored and recorded, provide data for future treatment design improvements and diagnosis of equipment problems. The following control equipment is representative of the systems being employed by service companies today for various types of well treatments.

Normalized, NPV

Monitoring and Control Equipment 1.6 1.5 1.4 1.3 1.2 1.1 1.0 0.9 0.8

Optimum frac half length, 40-50

0

Fig. 4.16. Halliburton’s Stim Star stimulation vessel

40 60 80 Frac half length, Xf

Fig. 4.20. Frac length optimization: NPV vs frac half length

Fig. 4.19. Schlumberger FracCAT control and monitoring system 106

20

100

Control rooms on Baker’s stimulation vessels have the following capabilities: • Network communications and remote data transmission via satellite • Full data monitoring capabilities, including Baker SMARTS (Stimulation Monitoring and Reservoir Testing Software) • State-of-the-art data acquisition and display • Backup computer systems. These control units are packaged on a truck chassis for land operations and in skid-mounted configurations (Fig. 4.18) for treatments performed on an offshore rig. The Schlumberger fracturing computer-aided treatment system (FracCAT) comprises hardware and software for monitoring, controlling, recording and reporting all types of fracturing treatments. Its real-time displays, plots, surface schematics and wellbore animations present a clear picture of the treatment as it occurs, providing decisionmakers with real-time detailed job information from the surface to the perforations. During the job, the FracCAT system tracks multiple performance parameters, then compares and displays them against planned values (Fig. 4.19). Using FracCAT, or similar computer-aided technology from other service companies, a treatment design can be executed and tracked in a very precise manner.

Chapter Four Surface Operations and Equipment

The Halliburton TECHCOMMAND Center is a minicomputer-based system designed specifically for stimulation control. This system provides data acquisition, real-time data analysis and direct control of automatic, remote-controlled pumping and blending equipment. TECHCOMMAND offers the following features: • monitors and records more than 1,200 surface treatment parameters including injection rates, additive rates, slurry density, pressures, material inventories and equipment operating status • communicates with a wireline computer logging system via an RS-232 serial port to monitor bottomhole treating pressures and other parameters during treatment so that data can be used to analyze the treatment in real time • monitors real-time minifrac data to provide critical onsite fracturing parameters and, if necessary, data to redesign the fracture treatment onsite • displays the log/log plot of the net bottomhole treatment pressure versus time, to aid in decision making for real-time adjustments to the fracturing treatment • transfers data to a portable computer, if necessary, to interface with stimulation software such as FracProPT (discussed below) • interfaces with fracture design software and FracProPT which can be used in combination to assist in realtime fracture analysis • transfers job data from remote wellsites via satellite to a central technology center, allowing additional stimulation experts to use design/analysis software to make difficult real-time decisions, if necessary. Design and Simulation Frac length optimization, the best objective of an HRWP or frac-pack design, is determined by economics. Well performance is enhanced by the presence of the fracture and the cost of these sand control treatments is determined at various frac half lengths. The incremental income increases with increasing fracture length. At a certain point the frac half length becomes prohibitive due to cost constraints. The cost is expressed as net present value (NPV). The NPV expresses the value

of the reservoir after production over a finite time period. This time period cumulates the discounted incremental income of the project. The investment and operating costs are subtracted from the discounted incremental income to arrive at the net present value.4 Figure 4.20 illustrates such an optimization. Several software packages to assist with the design and execution of sand control treatments are available. Schlumberger, for example, has proprietary software called FracCADE and SandCade. All service companies employ some type of computer-aided design and control software. These packages have several modules, which can perform various functions such as: • Calculating numerous engineering parameters • Simulating innovative pseudo-3D gravel placement • Simulating hydraulic fracturing treatment • Accounting for wellbore hardware for the duration of treatment pumping • Converting surface treatment conditions to bottomhole conditions • Allowing users to graphically analyze step rate tests, injection tests and Gfunction decline to determine fracture closure stress, fracture geometry and fluid leakoff coefficient • Presents log data to graphically define layers and zones • And many more. The following discussion will touch on some of the more popular software programs used by other service companies. Mfrac. Mfrac is a comprehensive design and evaluation simulator containing a variety of options including three-dimensional fracture geometry and integrated acid-fracturing solutions. Fully coupled proppant transport and heat transfer routines, together with a flexible user interface and object oriented development approach, permit use of the program for fracture design, as well as treatment analysis. Capabilities of this program include: • Automatically design a pumping schedule to achieve a desired fracture length and conductivity • Parametric studies and “what-if ” scenarios • Geometry and design optimization for proppant, acid and foam treatments

• Pressure history matching and model calibration in real-time replay • Performs analyses to anticipate fracture behavior (e.g., fracture growth, efficiency, pressure decline, etc.). MFrac uses numerical, state-of-theart, frac-pack and TSO methodologies to design “fully packed” or TSO-type proppant distributions. The modeling techniques used require that the fracture propagation and proppant transport solution be linked in such a way that each can influence the other. Normally, this means that for each time step in the fracture propagation calculation, the proppant transport simulation must be assessed and coupled. This methodology differs substantially from a conventional fracture stimulation approach, which by design tries to prevent proppant screen-outs or bridging. The criteria for automatic TSO and frac-pack designs include: • Designing to a pre-specified fracture length to optimize near wellbore conductivity • Basing the design on a maximum allowable inlet concentration • Designing to achieve a minimum concentration per unit area • Maintaining pumping pressures below a critical maximum pressures. Figure 4.21 illustrates the methodologies for TSO and frac-pack designs and demonstrates that the net-fracture pressure and width both increase with time after a TSO. It also shows the final proppant concentration at the end of the job. FracProPT. This program is the Gas Technology Institute (GTI) fracturestimulation engineering software that is being supported by Pinnacle Technologies. Prior to 1999, earlier versions of FracPro supported by Resources Engineering Systems, Inc. (RES) were used in the industry. The Halliburton version of this software incorporates their extensive fluid rheology and conductivity data and allows the user to "build" a custom fluid. The FracPro fracture design model was the first to go beyond standard simulators by acquiring and analyzing realtime fracturing data during treatment. The program can be used to design fracturing treatments and then acquire downhole data during field operations or information from a treatment 107

Modern Sandface Completion Practices

Fracture length

tso

Methodology Fracture length increases as a function of time up to the point of screenout (tso). After a perimeter screenout is achieved the propagation of the fracture stops and the width increases as a function of the increasing net pressure. In MFrac, these treatments may be automatically designed and a target length can be entered and used as a criteria for the design.

Frac pack tso Fracture length

Tip screeenout

tso

Time The minimum and maximum proppant concentrations are user-specified parameters. Based on these values, the target length and average concentration per unit area entered, the program produces a pumping schedule that meets the criteria specified. For frac packs, an iterative approach is used to determine the time or volume for the maximum proppant concentration (tCmax).

Inlet prop concentration

Inlet prop concentration

Time

tso tCmax

Time

Leakoff rate

For either a tip-screenout or frac pack design the fracture area approaches a state of equilibrium once a screenout occurs (tso). Beyond this point, the rate of leakoff declines. For a TSO design the program allows the pressure to increase by maintaining a constant rate of injection (i.e., ballooning). A frac pack requires a decrease in rate to eliminate excess fluid and produce a stable net pressure.

Injection rate

Leakoff rate

Time

Time The time at which screenout occurs (tso) for both the tip-screenout and frac pack methods is characterized by a prominent rise in pressure. For a TSO treatment, the increase in pressure continues until the end of the job. In a frac pack, the rate is decreased at the time the maximum proppant concentration is reached (tCmax). This creates a stabilization of the net pressure and corresponding fracture volume.

tso tCmax Net pressure

Net pressure

tso

Time

Time Because width is a function of net pressure, their trends appear similar. Notice that “ballooning” is allowed in the tip-screenout example for the duration of the injection period. For the frac pack, on the other hand, width is held constant by allowing the rate to decline to affect the net pressure. This is the most efficient way to produce a uniformly packed proppant concentration throughout the fracture.

tso tCmax Fracture width

Fracture width

tso

Fracture length

Fig. 4.21. TSO vs frac pack methodology 108

Time Depending on which method is used, the prop concentration per unit volume in the fracture will vary. Because “ballooning” is permitted in a TSO design the inlet concentrations required to “pack” a fracture are typically not feasible. For these types of treatments the stages pumped early in a job concentrate near the front of the fracture and result in higher concentrations at the tip (≤Cbank).

Concentration at EOJ

Concentration at EOJ

Time Cbank

tso tCmax

Rate

tso

Rate

Injection rate

Time

Cbank

Fracture length

Chapter Four Surface Operations and Equipment

database to confirm design estimates or perform detailed post-treatment analysis. Onsite pumping schedule changes can be made to optimize the frac design based on formation frac-fluid parameters obtained from the minifrac analysis. Even real-time changes can be easily incorporated while the job is in progress. The ability to design, monitor and analyze the fracturing treatment makes the FracProPT program a versatile model for both minifrac analysis and fracture design, real-time data analysis or when used as a post-frac analysis tool. FracProPT’s integrated fracture picture allows the display of multiple stages and logs (Fig. 4.22). WellWhiz. This is a program that models production from wells with varying completions, such as vertical, deviated and horizontal with or without hydraulic fractures. Optimizing well performance is a vital task, yet existing analytical tools often make gross simplifications in geology or fracture shape, resulting in predictions that can be unreliable and misleading. WellWhiz answers a wide range of key questions such as: • What type of well should be drilled? • Should one consider a vertical well, perhaps with a fracture, or a horizontal well with several fractures? • How much improved production will various types of well completions yield? • What about water influx in a naturally fractured reservoir? WellWhiz uses a numerical simulator to model multi-phase flow in the reservoir and around the well, including in hydraulic fractures, to give an accurate prediction of well production rate and pressure response. Crucially, WellWhiz models non-Darcy flow in fractures and the reservoir, using proprietary laboratory-measured beta factors. Non-Darcy flow can be an important flow mechanism in fractures in a gas well producing at 20 mmscf/d from a 100 ft (30.48 m) fracture height. For example, non-Darcy flow effects in the fracture will result in a reduction in fracture conductivity of up to 90% leading to dramatic over-estimation of a well production potential.

Evaluation Techniques Once a gravel pack or frac pack is in place, it is important to determine or evaluate the effectiveness of many key aspects of the completion operation. A poorly executed treatment may result in early failure of the screen and premature sand production, requiring costly remedial operations. Determination of the treated formation intervals, annular gravel-pack success and pack-assembly placement provides the necessary feedback to make important decisions immediately following the completion. When voids or plugged packs are detected early, remedial action can be taken to help optimize production and prolong the life of the well. Historically, the tools used for treatment evaluations have been conveyed by wireline. Depending on the application, there are now tools available, which can be conveyed by wireline, slickline, tubing and coiled tubing. Additionally, memory-based tools, conveyed at the end of washpipe for logging after completion of the packing operation when coming out of the hole, are growing in popularity.

Gravel-Pack Evaluation A number of logging services and evaluation techniques are available to assess the placement of material in gravel packs. These include: • Density log – a fullbore detector senses gamma rays from a toolmounted radioactive (RA) source. • Dual-Detector Neutron log – changes in the count rate of neutrons emitted by a tool mounted RA source indicate changes in the hydrogen index. • Spectral Gamma Ray “tracer” log – in a single logging operation, spectral gamma measurements can help identify multiple RA isotopes tagged to pumped materials. Density log. The historical wireline tool for gravel-pack evaluation is a porosity log commonly referred to as a density or nuclear density log. The tool consists of a chemical source of gamma radiation and a shielded gamma detector (some tools may have more than one detector, which are callibrated to automatically compensate for borehole size,

Intigrated fracture picture FracproPT layer properties Rockt...

Shale

Stress...

Modul...

Concentration of proppant in fracture (lb/ft≤)

Width profile, in.

Perm... 0 500

10,450

10,475

EB Up ...

10,500

10,525

EB Mid ...

10,550

10,575 EB Low... Shale 10,600

10,625

Proppant concentration (lb/ft≤)

10,650

0 25

StimPlan. This program, developed by NSI, is a fracture design simulator with

Washpipe conveyance reduces rig costs and speeds time to production. It is quickly becoming the conveyance method of choice in deepwater operations due to rig-time cost savings and for horizontal completions where it is sometimes difficult to run wireline tools. It provides immediate results after the washpipe is removed allowing for a quick decision while the pumping equipment is still on location.

special modifications that allow for TSO designs. At tip-screenout initiation, fracture extension is stopped and the program calculates a width increase based on the increase in net treating pressure. This program will analyze complex formations composed of multiple productive layers with varying fluid-loss coefficients.

50

0.50 75

1.0 100

1.5

2.0 125

2.5 150

3.0

3.5 175

4.0 200

4.5

5.0 225

1

0.5

0

0.5

1

Fig.4.22. Example of FracProPT’s integrated fracture picture 109

Modern Sandface Completion Practices

casing diameter and thickness, cement thickness, etc.). Gamma ray emissions bombard the pack and are backscattered to the detector(s). The count rate at the detector is an indication of and inversely related to the bulk density of the borehole and its immediate environment. The gravel and its liquid filled porosity are denser than the borehole fluid alone. Hence a properly packed interval will have a higher density (lower counts) than a packed interval that has voids or “holidays” or where no pack exists at all. Wireline service companies have traditionally provided this log under familiar brand names such as Nuclear Fluid Density (NFD) log, the Photon log, etc. Figure 4.23A illustrates a density log curve indicating a dramatic increase in gamma ray counts in relation to nonpacked intervals. Protechnic’s PackScan Gravel Pack Density Imager is a dual detector density tool specifically designed to measure changes in the bulk density of a gravel-packed annulus (detects voids and top of gravel reserve). The memorybased density tool, which is used as either a stand-alone pack evaluation tool or as a complementary technique in conjunction with radioactive tracers,

identifies small voids in the gravel pack. Since it is unaffected by the presence of radioactive tracers, it can also be used to evaluate proppant placement. Effects of borehole fluid variations and changes in tubular size and geometry are minimized. The tool functions much like other dual-detector density tools. Poor gravel-pack quality or voids will allow more gamma rays to reach the detector. This is seen on the log as a higher count rate response. However, to enable interpretation of the log, it is necessary to superimpose an exact graphic of the well completion hardware over the log presentation (Fig. 4.24). This completion graphic is exact in relative wall thickness and depth. The importance of the well diagram is to determine the difference between count rate increases and decreases that are caused by hardware from those that are caused by changes in the annular pack. Dual-dectector neutron log. Another technique uses the dual-detector neutron log, which employs a chemical source of neutrons and two thermal neutron dectectors, one near (N) and one far (F). The source emits highenergy neutrons which are slowed down (or moderated) by collisions with other

Fluid density

Dual-dectector neutron

RA tracer

GR counts

Counts

GR counts

Sc

A

B

Ir

C

Well schematic Fig.4.23. Gravel-pack log evaluation. Density log plot (A), Dual-detector neutron log plot (B ), and a Tracer log plot (C ) 110

Spectral gamma ray “tracer” log. Perhaps the most commonly used gravel-pack evaluation technique is to tag the gravel with radioactive tracer materials. The materials commonly used are Iridium-92 (Ir) and Scandium46 (Sc). In the past, a single RA agent was used. Today it is more common to use Sc for tagging the packing of the perforations and Ir for tagging the main annular-pack stage. A detector is then run across the packed interval. If the RA agent is uniformly mixed with the gravel, the count rate indicates the presence or absence of gravel pack. The Sc and Ir can be discriminated to assure gravel placement in the annulus and identify the perforated intervals (Fig. 4.23C). HRWP and Frac-Pack Evaluation

N

F

nuclei. The main factor slowing down these neutrons is hydrogen, as found in water or oil, but not gravel. Neutron count rates at the N and F detectors will be high where a good pack is present and low when it is not. This occurs because the neutrons more easily propagate out to the detectors through gravel than through fluid. When the appropriately scaled N and F count rates are overlaid in a well-packed zone, the logs separate in poorly packed intervals. Small variations in the surrounding fluid can cause large variations in the neutron capture cross section. Therefore, the log response is a function of both pack and fluid variations. Figure 4.23B illustrates how the log responds to gravel-packed intervals.

Following an HRWP or frac-pack completion, logs can be run to help evaluate the treatment effectiveness, including determining the height of hydraulically induced fractures, verifying the placement of pack materials and analyzing flow from treated formations. To verify the placement of pumped materials such as fracturing fluid, proppant and gravel, spectral gamma ray or tracer logs (Fig. 4.25, see page 112) are most commonly used. Most logging companies offer some type of tracer tool, for example: • Multiple Isotope Tracer Tool (MTT) (Schlumberger) • Precision Radioactive Isotope Spectrometry Measurement Tool (PRISM) (Baker Atlas)

Chapter Four Surface Operations and Equipment

• SpectraScan Tool (ProTechnics, a division of Core Laboratories) • TracerScan Tool (Halliburton) The treatment materials to be pumped are tagged with radioactive tracers that have dissimilar gamma ray spectra (i.e., Iridium-192, Scandium-46, Antimony-124). Each tracer emits gamma rays of different energies and different intensities than the other tracers. When fracturing, the fracturing fluid may be tagged with one tracer, the proppant with a second tracer and the gravel with a third tracer. Since the tracer tool can distinguish gamma rays in different energy ranges, it can differentiate the tracers after they have been pumped downhole during the treatment. Tracer logs record spectral gamma ray data as a function of depth and therefore can evaluate the vertical distribution of the tagged materials. This allows the total and propped fracture heights to be estimated and voids in the packs to be located. Tracer log data also gives information regarding the approximate radial location of tracers and permits tracers in the borehole to be distinguished from those in the formation. References 1. Corbett, T. and Vickery, E., “Multiple Zone Open Hole Gravel Packing Techniques with Zonal Isolation, IADC/SPE 77214, presented at the Asia Pacific Drilling Technology Conference, Jakarta, September 9-11, 2002. 2. Terracina, J., Parker, M. and Slabaugh, B., “Fracturing Fluid System Concentrate Provides Flexibility and Eliminates Waste,” SPE 66534, presented at the Exploration and Production Environmental Conference, San Antonio, Texas, February 26-28, 2001. 3. Lindeburg, M., “Mechanical Engineering Reference Manual, 10th Ed., Professional Publications, 1997. 4. Voneiff, G. and Holditch, S., “An Economic Assessment of Applying Recent Advances in Fracturing Technology to Six Tight Gas Formations,” SPE 24888, presented at the Annual Technical Conference and Exhibition, Washington, DC, October 4-7, 1992.

Fig.4.24. This PackScan gravel-pack evaluation log identifies good pack through the screen interval with an inconsequential void detected in the blank pipe interval. The top of pack is easily identifiable along withthe change in density at the top of screen.

111

Modern Sandface Completion Practices

Fig.4.25. This tracer log example identifies the location of formation stimulation and the annular pack interval including the top of sand. It also verifies the position of the gravel-pack assembly by identifying the depth of the radioactive markers placed in the assembly near the sump and gravel-pack packers.

112

CHAPTER FIVE

Alternative Practices and Special Techniques Rigless Sand Control Techniques • Specialty Tools and Techniques

good completion design should always emphasize practices that maximize well productivity and help operators realize the most benefit from the selected solutions. The best completion designs are based on specific well requirements. Besides those that have been previously discussed in this handbook, other options to obtain effective sandface completions exist. Several of these alternative practices and special techniques are covered in this Chapter.

A

Rigless Sand Control Techniques Marginal or secondary payzones are often bypassed because of the breadth and cost of services required for remedial or workover operations. New technologies employing small diameter tools and expandable sand-exclusion screens show real promise in expediting the routine application of “rigless” or thru-tubing completions. Accessing wellbores in a workover environment without using a costly conventional drilling or workover rig provides countless new opportunities for maximizing production from these marginal zones. There are four major types of rigless or thru-tubing, sand control techniques: • Chemical – Resins or chemicals are injected into poorly consolidated formations to provide in situ grain-tograin bonding. • Mechanical – These include the use of small diameter or expandable screens, which are designed to be runthrough tubing and then placed inside casing, tubing or other larger screens. These are commonly combined with various hydraulic methods. • Hydraulic – These methods involve applying fracturing techniques, such as HRWP and frac packs, on a well without the aid of a drilling structure. • Chemical/mechanical/hydraulic combination – These completion

methods involve frac packing using resin-coated proppant. This process is also referred to as a screenless frac pack and was discussed in the “Frac Packing” Section of Chapter Three. Wedman, et al, presented a successful application of this technique, in a recent multi-zone completion case history.1 Since hydraulic fracturing and screenless frac packs have been discussed in previous Chapters, only chemical and mechanical thru-tubing, completion techniques will be discussed in this Section. Chemical Methods Chemical treatment techniques are sometimes employed for sand control. These processes are designed to produce a chemical reaction with the formation sand for the purpose of inhibiting its mobility. Two techniques, resin consolidation and steam consolidation, are discussed here. Resin consolidation. This sand control method involves injecting chemicals (usually resins) into the unconsolidated formation to provide grain-to-grain cementation. Cementing the sand grains together at their contact points creates a strong consolidated matrix. Subsequent flushes displace excess resin material further into the formation to clear the pore spaces between grains, allowing the best possible permeability for oil and gas flow. Resin consolidation systems help control sand without mechanical screening devices restricting the wellbore or limiting access to lower producing zones. Ideal for dual-zone completions, these systems permit access to a lower zone without disturbing the upper zone. This is accomplished by consolidating the upper zone and gravel packing the lower zone.

A successful consolidation treatment must provide the additional strength required while maintaining as much formation permeability as possible. Successful consolidation treatments also depend on obtaining complete coverage of all perforations in the payzone. For this reason consolidation treatments are generally performed on short intervals of 15 ft (4.6 m) or less. Perforations are a prime concern in chemical consolidation treatments. Success depends on either all perforations being open to accept the resin or using excess resin so that the interval around any plugged perforation is also treated. In most cases, treating 90% of the perforations will result in a failure rather than a 90% success. Advantages of chemical consolidation include: • Wellbore is left free of obstruction, making this method more adaptable to multiple completions. • Does not require recovery of liners to repair failure of a sand control treatment or recompletion of another zone. • Repair jobs can be attempted without pulling downhole equipment by pumping the chemical down the existing tubing string or by using coiled tubing or hydraulic workover units. • Method is more desirable than gravel packing in monobore or thru-tubing completions. Disadvantages of chemical consolidation include: • Treatment results in reduced formation permeability. • Treatments are generally more expensive on a per foot basis than a gravel pack. • Interval length is limited to 15 ft (4.6 m) at a time. • Materials used are generally hazardous to handle and hard to dispose. • Treatment is subject to deterioration with time. 113

Modern Sandface Completion Practices

Formation water

Oil

Preflush

Formation sand grain A. Oil and formation water before consolidation

B. Preflush miscibly displaces oil and formation water

Resin

Resin solution

Overflush

C. Resin solution displaces preflush

D. Overflush immiscibly displaces resin and activates resin cure

Resin

Oil

alkaline pH steam condensate, which preferentially dissolves sand grains with high-specific surface area. The injected fluids rapidly lose heat to the formation and various cement precipitates with changes in temperature, alkalinity and contact time. The lattice of cement bonds are created by the relatively high-volume and high-velocity steam vapor phase, which quickly dissipates through the near-wellbore region and carries away excess cements and other precipitates so they do not adversely affect formation porosity and permeability. The wells completed with this technique have equivalent or higher productivity and injectivity than wells completed with open-hole, gravelpacked, slotted-liner completions. In addition, steam consolidation significantly lowers drilling and completion costs. It improves fluid entry or injection profile control, provides a low-cost means of eliminating unwanted completion intervals, and provides flexibility to use wells interchangeably as producers or injectors.3 Mechanical Methods

E. Well ready for production

Fig. 5.1. Saturation changes during resin consolidation

The principal behind chemical consolidation is relatively simple - inject resin, coat the formation sand grains, allow the resin to harden and bond at sand-grain contact points, then place the well on production. However, in actual field applications, it is difficult to consistently obtain successful plastic treatments. Not only is proper placement of the materials critical to success, but the materials must be injected into all perforations in the correct sequence: first the preflush and conditioning fluids, then resin, overflushes and activating agents. Figure 5.1 shows the typical steps involved in a resin consolidation. Resins are also finding applications in remedial treatments. If the completion interval is free of any fill inside the casing, the plastic can be injected through the production tubing. In some cases, either small diameter tubing or coil-tubing units are used to clean out the well114

bore and inject the resin. Repeated resin consolidation attempts are not recommended because excessive permeability reduction may occur. In instances where significant sand production has occurred, the well should be prepacked with gravel before the consolidation chemicals are injected or a resin-coated gravel system should be used. Steam consolidation. The use of the hot alkaline/steam sand-consolidation technique to complete wells is based on the geochemical bonding. In this process, unconsolidated formation sand grains are bonded with a lattice of primarily high-temperature, complex synthetic silicate cements and possibly other lower-temperature precipitates, such as silica cements and carbonate scales. The complex silicate cements and other mineral precipitates are created by the high-temperature and high-

There are three basic mechanical methods (Fig 5.2) of rigless sand control completions that involve placement of gravel into the perforations where no returns are taken.4 • The pack-off or squeeze-pack method – which uses a gravel-pack screen with a blank spacer pipe and pack-off or packer seal assembly run thru-tubing. It can be placed inside casing or an existing gravel-pack screen, spaced-out so that the packoff or packer assembly is landed inside the production tubing. • The vent-screen method – which uses two screen sections, separated by blank pipe placed and packed in the casing with production entering the lower section of screen and exiting the upper section. • The wash-down method – which uses a pre-pack (HRWP or frac) with the gravel-pack screen being “washed” into position and sealed or packed-off. This method is applicable for both casing and tubing. Pack-off or squeeze method. In a packoff method gravel pack, a screen, with a length of blank pipe attached to a releas-

Chapter Five Alternative Practices and Special Techniques

ing tool and coiled tubing, is run across the perforations. Once the screen is placed, a ball is dropped and circulated through coiled tubing. The ball will land on the releasing tool forming a seat. When pressure is applied to the ball seat, the releasing tool, attached to the coiled tubing, will be free from the blank pipe and screen. It also opens the circulating port that allows fluids to be pumped through coiled tubing, exiting to the annulus of the blank pipe and casing. A certain set-down weight is necessarily applied on the hydraulic release tool to prevent it from being pushed upward during the squeezing operation. Gravel exits the releasing tool and is packed in the perforation tunnel. When screenout occurs, the excess sand is circulated out. Coiled tubing is then pulledout to surface. Slickline will run the pack-off and anchor assembly to prevent sand that passed through the annulus and the screen from moving upward. 5 Thru-Tubing Systems, Inc. has a similar system (the One-Trip, SqueezePack System). It allows for the deployment and placement of the gravel pack in one trip on coil tubing or jointed pipe. It utilizes a thru-tubing retrievable seal-bore, gravel-pack packer and a two-position, crossover-tool combination. This system contains similar components to that of typical cased-hole, rig-deployed systems. It allows for the setting and testing of both sealing and anchoring components prior to the placing of the gravel-pack proppant. This easily accommodates the identification, removal, and replacement of any failed components prior to producing the well. The system is also designed to handle both low bottomhole pressure and live well applications. Typically, screen, blank pipe, a shear-out safety sub, and a gravel-pack packer/crossover-tool BHA is deployed into the well via coil tubing. The screen assembly is spaced out across the productive interval while blank pipe ties the packer assembly back into the production tubing. Once the assembly is located on depth, a setting ball is pumped around the coil tubing reel and allowed to gravitate on a seat in the crossover/setting tool. Pressure is then applied to the coil tubing and the packer is set and disconnected from the two-position crossover tool. The coil tubing/production tubing annulus is then pressurized in order to pressure test the packer.

Fig. 5.2. Pack-off method (left ). Vent-screen method (center ). Wash-down method (right ).

Once the component setting and testing is complete the gravel pack slurry is pumped down the coil tubing though the packer/crossover tool and out a perforated sub located below the packer. The gravel pack slurry then travels down the blank pipe and screen/casing annulus and into the production perforations until a screenout occurs. Following the screenout, pressure is bled off the coil tubing. The crossover tool is then repositioned into the upper circulating or reverse position by picking up on the coil tubing +- 3 ft (+- 0.91 m). At this time, pumping down the coil tubing is resumed while taking returns up the coil tubing/production tubing annulus, allowing for the removal of any excess gravel-pack slurry remaining inside the

coil tubing or work string. Seal extensions on the crossover tool maintain zonal isolation during this sequence of the operation, thus providing for the removal of the excess gravel-pack slurry even in wells that are under pressured. Once the excess slurry is removed from the well, the crossover tool/running tool assembly and coil tubing are removed. As the crossover tool exits the packer assembly, a sliding sleeve is landed across the ports in the perforated sub isolating the same. Once out of the hole with the coil tubing the well is returned to production. Vent-screen method. This technique has been used for many years in situations requiring remedial sand control. 115

Modern Sandface Completion Practices

The vent-screen technique uses two screen assemblies separated by blank pipes that are placed and packed in casing. Production enters the lower screen section and exits the upper screen section. The screen and blank assembly are run into the hole through the production tubing on electric line (e-line), slickline or coiled tubing and set on the bottom. The dual-screen, thru-tubing assembly does not require the top of the blank liner to be extended into the production tubing. Once the bottomhole assembly (BHA) has been properly located across the perforations, the desired gravel pack is pumped through the coiled tubing and then completely over and around the dual screen, covering the entire screen assembly. The gravel slurry is re-stressed by pumping from the annulus to pack around the lower section of the BHA. Once screenout pressure is observed, the gravel is washed from around the

Fig. 5.3. Vent-screen, rigless through-tubing completion 116

upper screen section, again using the coiled tubing. Production is directed through the lower section of the screen, up the blank pipe and out the top section of the screen (Fig. 5.3). Most of the wells that employ this completion method are plugged-back through tubing to the next zone as soon as the completion depletes or fails. Production and/or formation logs are not always needed because of the limited reserve size. Many operators are using this and similar methods for their primary means of sand control in new well completions due to successes and cost efficiencies on primary as well as plug back completions. Wash-down method. The wash-down method consists of a lower jet shoe, screen, blank pipe and hydraulic disconnect. Inside the screen and blank pipe, an inner tube is spaced, running from the hydraulic disconnect down to

Fig. 5.4. Wash-down, gravel-pack system

the shoe. The system is run on coiled tubing. The first step is to clean out the wellbore to a point approximately 10 to 15 ft (3.05 to 4.57 m) below the perforations. With the wellbore clean, a pack medium is placed across the perforated interval. This pack medium may be sized gravel, ceramic proppant, sintered bauxite or other spherical material. Once placed, the top of the material is “tagged” (radioactively marked) to verify that the perforations are covered. Any excess material is washed out usually with coil tubing to +-10 ft (+- 3.05 m) above the top perforation shot. The screen assembly is run in on coiled tubing and washed-down until properly placed across the perforated interval. A ball is then dropped, and the running tool is disconnected. The coiled tubing is removed from the wellbore, and wireline is rigged-up to install the pack-off and tubing stop or packer assembly on top of the liner.

Chapter Five Alternative Practices and Special Techniques

Thru-Tubing Systems has a washdown gravel-pack system that has several unique features. The system can be deployed on coiled tubing in one trip and does not require subsequent trips into the well to install pack-off or tubing stops. Unlike conventional thru-tubing washdown systems, its sealing and anchoring component allows for failures to be detected and repaired prior to producing the well. This system is frequently employed following frac-pack treatments and in applications where excessive wellbore sloughing hinders normal deployment of conventional gravel-pack hardware. Figure 5.4 illustrates the various positions of this tool system. Thru-tubing circulating gravel pack. The Eclipse Packer Company (recently acquired by Weatherford) offers an alternative method. It is a one-trip, circulating gravel-pack system that is hydraulic-set, retrievable and can be run on coiled tubing or jointed pipe. The design eliminates the need for workstring manipulation to achieve run-in, setting, gravel-packing and circulatingout positions. After placement of the gravel, the packer remains in the wellbore as the production packer. Thru Tubing Systems also offers a similar circulating gravel-pack system, which employs a large-bore, retrievable/inflatable packer and crossover tools combination. It too is designed to be deployed in one trip on coil tubing or jointed pipe. The main feature difference of this system is the ability of the inflatable packer, with a 2:1 expansion ratio, to be deployed through smaller well tubulars and set inside of larger tubing or casing sizes. This feature is beneficial when wellbore restrictions exist that prohibit the use of conventional packer or pack-off systems. In many cases this system will allow for the gravel-pack assembly to be landed in the wellbore below the end of the production tubing, thus not hindering future plug backs. In most remedial applications, the work involves placing a small diameter screen through the tubing and setting the completion into either casing or an existing screen with a greater diameter than the tubing ID. As long as the screen diameter is approximately 1 in. (2.54 cm) smaller than the casing or existing screen diameter, the gravel placement can proceed without undue

concern for premature bridging due to the small annular clearances. However, there are times when it is advantageous to maximize the size of the new screen section to minimize the pressure drop across the new completion. If these applications cause very small radial clearances on the outside of the screen, then premature bridging of the sand particles becomes a major concern. This is particularly true when these clearances get to be as small as 0.25 in. (0.64 cm). The two flow areas, where flow occurs on both sides of the screen, are shown in Figure 5.5. Tests have been run to determine new washpipe size recommendations (Table 5.1). Table 5.2 lists common washpipe sizes. The ratio of outer annulus area to inner annulus area for the newly recommended washpipe sizes is shown in Figure 5.6 as a comparison.7

well followed by tubing patch work needed to remedy tubing/casing communication. Once the tubing straddle or patch work is completed, the guns can be fired hydraulically from the surface with nitrogen and the well returned to production. Guns are fired independent of packer setting, allowing for the packer to be set on wireline or with coiled tubing. Perforating guns can be fired after the slickline or coiled tubing is rigged down and moved off of the well. Thru-tubing frac pack/HRWP. A rigless frac-pack or HRWP system allows sand control across a lower zone via a gravel pack or frac pack and, at the same time, ensures that the completion

Outer annulus area

Casing

Thru-tubing perforating and screen deployment. This system (Fig. 5.7) can be run on coiled tubing, e-line or slickline in one trip, thus saving time and expense of multiple systems. It allows for perforating gun deployment into the

Screen Washpipe

Inner annulus area

Fig. 5.5. Flow areas during gravel transport

Screen Base Pipe Size (in.)

Washpipe Size (in.)

2.375 2.875 3.500 4.000 4.500

1.315 1.900 2.375 2.875 2.875

5.000

3.500

5.500

4.000

6.675

4.500

Table 5.1. Recommended washpipe sizes

Screen Base Pipe Size (in.)

Washpipe Size (in.)

2.375 2.875 3.500 4.000 4.500

1.315 1.900 2.375 2.875 3.500

5.000

4.000

5.500

4.500

6.675

5.500

Table 5.2. Common washpipe sizes 117

Modern Sandface Completion Practices

3.5

0.5-in. common

Outer/liner annulus ratio

3.0 2.5 2.0 1.5

0.25-in. recommended

1.0 0.5 0.0 2.0

0.25-in. common 2.5

3.0

3.5

4.0 4.5 5.0 5.5 Screen base pipe size, inches

6.0

6.5

7.0

Fig. 5.6. Ratio of the annulus area outside of the screen to the annulus area inside of the screen for common washpipe sizes inside of the screen. Comparison for 0.50 in. and 0.25 in. radial clearance between the screen OD and the casing.

“VTA” packer

5-in. 18# isolation tubing Future thru-tubing assembly

“VTA” packer

Flapper 3 1/2-in. blank

3 1/2-in. screen

assembly above the lower zone is optimized for a future thru-tubing gravel pack on an upper zone. The lower zone is packed as normal. If necessary, a spacer assembly and upper packer are stung into the gravel-pack packer and set. To shutoff production from the lower zone and access the upper zone, a thru-tubing bridge plug is set in the blank pipe above the lower zone. The upper zone is perforated. A dual-screen assembly is placed across the upper zone, and an HRWP or frac-pack treatment is performed to place sand in the perforation tunnels and around the screen assembly. Excess sand is washed clear of the upper screen using coiled tubing. The well can then be placed on production. Figure 5.8 is a schematic of the downhole tool assembly. A thru-tubing frac pack, incorporating a vent-screen system, can also be done using releasable “one-trip” TCP guns. In a geopressured well this method could significantly reduce the well completion cost by eliminating the need for high-density completion fluid and a 15,000 psi blowout-preventer (BOP) stack. The TCP guns, with the ventscreen/blank assembly attached, is run in the hole and positioned with a depth verification tool on a workstring. The tubing and production packer are then run, the packer is set and the wellhead is nippledup. The rig then can be released. The TCP guns are fired by pressuring-up at the surface. The guns are released into the rathole, and the ventscreen assembly moves downward into place. The high-pressure frac pack is performed down the production tubing using a wellhead isolation tool/treesaver. Excess proppant above the vent screen can be flowed to surface due to high reservoir pressure. In other cases, it may be necessary to use coiled tubing to washout to the vent screen.8 There are more rigless sand control techniques available than what space allows for discussion here. Information on additional or newer rigless-completion systems can be obtained by contacting any number of service companies.

Bridge plug

Specialty Tools and Techniques 7 5/8-in. casing

Fig. 5.7. Thru-tubing perforating and screen deployment 118

Fig. 5.8. Rigless frac-pack or HRWP system

Discussions in this Section will include selected specialty tools and techniques for sand control including wireline gravel packing, the VibraPak rotary vibration system, multilateral tech-

Chapter Five Alternative Practices and Special Techniques

niques, and systems used with rod pumps and electric submersible pumps (ESPs). While there are numerous special tools and techniques available for achieving various levels of sand control, these are representative of some newer and some unique technologies. Wireline Gravel Pack Perf-O-Log has developed a thru-tubing, wireline gravel-pack (TTWGP) system. It is an alternative to thru-tubing sand-control methods, which were discussed in the previous Section. A TTWGP is deployed with an electric wireline. It can be installed in: • Damaged conventional gravel-pack completions • Zones that have been washed out • Newly perforated zones. Most importantly, the entire procedure can be done under pressure.9 A typical job consists of the wireline plugback (setting the thru-tubing bridge

plug and/or dump bailing cement plug), perforating, screen deployment, conveying the gravel-pack slurry via dump bailers, then placing a cement cap with dump bailers. The screen assembly (Fig. 5.9) consists of (from bottom-up): solid spacer bar (can be cut to desired length on location), screen sections (wire-wrapped or pre-packed), bowspring centralizers, blank joint, vent screen, and retrievable vent-screen cap. At the end of the job, the vent-screen cap is pulled, enabling flow through either the top of the assembly or through the vent screen. Once the assembly exits the tubing and enters the casing, the bow springs expand, thereby centralizing the assembly. The assembly is then placed across the perforated interval on a cement or sand bottom situated directly below the perforated interval as illustrated in Figure 5.10. A gravel-pack slurry, consisting of a suspension agent (sheared and filtered

HEC polymer) and gravel-pack sand is then dumped around the TTWGP, using wireline gravity bailers. The slurry is dumped in-place in its original blended form. The sand, distributed across the zone, is checked via electric-wireline depth control on each trip into the well. Bailer runs of cement are then performed, placing approximately 3 to 4 ft (0.9 to 1.22 m) of cement around the blank pipe to hold the gravel pack in place (Fig 5.11). The cap plug is then removed from the top of the assembly. Hydrocarbons are produced through the gravel-pack sand into the screen, up the blank and out the vent screen or the opened top of the gravel-pack assembly (Fig. 5.12). Vibra-Pak Vibra-Pak technology was pioneered in the early 1980s in California by Solum Oil Tools, now a division of PT Pipa Mas Putih in Indonesia. The technology

Retrievable vent screen cap Electric-line Vent screen Retrievable vent screen cap Bow-centralizer

Retrievable vent screen cap Vent screen

Vent screen Bow-centralizer

Blank pipe

Bow-centralizer Dump bailer

Bow-centralizer

Blank pipe

Cement cap Blank pipe Bow-centralizer

Bow-centralizer Screen Screen

Screen GP sand GP sand Bow-centralizer

Bow-centralizer

Bow-centralizer Perforations on low side 0°-30° Screen

Bow-centralizer

Screen

Screen Bow-centralizer

Bow-centralizer

Spacer pipe

Spacer pipe

Cement TTBP

Cement TTBP

Spacer pipe Fig. 5.9. Wireline gravel-pack components

Fig. 5.10. Gravel slurry around tool string

Fig. 5.11. Cement cap in place 119

Modern Sandface Completion Practices

Vent screen cap removed Vent screen Bow-centralizer Cement cap Blank pipe Bow-centralizer

Screen

GP sand Bow-centralizer Screen Perforations

involves a rotary vibration system in a downhole tool that imparts enough amplitude to move the gravel into hexagonal packing during the gravelpacking period, regardless of fluid viscosity. This action fluidizes the gravel and creates a highly permeable, yet truly high-density primary completion gravel pack free of voids.10 Vibra-Pak has been successfully applied in both open-hole and casedhole completions. Figure 5.13 illustrates two typical gravel-pack completions using this rotary vibration technique. Vibra-Pak tests have shown that in a full-scale, horizontal gravel-packing model the rotary vibration resulted in 100% gravel compaction between the open hole and the liner in a water-pack system. In addition, there was no bridging, no after-pack settling, no voids at the roof of the hole and the vertical perforation tubes were tightly packed with gravel.11 Multilaterals

Bow-centralizer Spacer pipe Cement TTBP

Fig. 5.12. Well producing

Multilateral Classification Level 1 Level 2 Level 3 Level 4 Level 5

Level 6

Drilling more than one drainhole from a primary borehole has become a common industry practice. Multilateral drilling and completion technology is used in both new wells and for reentry applications in existing wells. Multilateral wells can be broadly divided into two groups – those that offer no hydraulic isolation between the laterals (Levels 1-4) and those that do

Definition Open-hole sidetrack or unsupported junction Cased and cemented main wellbore; open-hole lateral or drop-off liner Main bore is cased and cemented; lateral bore is cased but not cemented Main wellbore and lateral are cased, cemented and mechnically connected Cased and cemented main wellbore and uncemented or cemented lateral liner with hydraulic and pressure integrity provided by additional completion equipment inside the main wellbore (packers, seals and tubulars) Cased and cemented main wellbore and uncemented or cemented lateral liner with hydraulic and pressure integrity provided by the primary casing at the lateral liner intersection without additional completion equipment inside the main wellbore

Table 5.3. Technology Advancement for Multilaterals (TAML) classification system 120

(Levels 5-6). The Level-3 and Level-6 systems have emerged as the prime candidates for applications that require no or full hydraulic isolation between the laterals. Level-3 junctions provide a pre-milled window system with a liner tieback. This mechanical junction provides full-reentry access to the main wellbore and the lateral. As full-bore access is available, pumps can be placed below the junction and closer to the reservoir. Level-6 junctions have full-pressure integrity achieved by the main casing string.12 In an effort to provide parity when comparing multilateral systems industry wide, a classification system was developed by Technology Advancement for Multilaterals (TAML), a consortium group comprised mainly of North Sea operators. The classification system divides wells into “levels” depending upon junction functionality. Table 5.3 lists the definitions of the various levels.13 Early Level-3 multilateral-well completions were constructed using a flowthrough guide stock and slotted liner or screen in the lateral, which was anchored to the main wellbore by a liner-hanger packer. Flow was allowed through the flow-through guide stock from the main bore completion, where it became commingled with the lateral production via perforations or slots in the lateral-liner overlap in the main bore. The challenge was to provide a means for allowing main bore reentry. With this increased functionality, Level 3 could be a viable, simple replacement for Level 4, as well as the Level 1 and 2 completions.14 With a focus on simplicity, design iterations led to the development of the Hook Hanger system. The intent was to construct a tool that was mechanically basic (no moving parts) and easy to install. Baker’s Hook Hanger is a liner with a machined window for main wellbore reentry. A “hook” at the bottom of the machined window is used to “hang” the system at the bottom of the casing exit window. Hold-down slips at the top of the system ensure that it is engaged to the main-bore casing. Reentry is achieved using a main-bore or lateral diverter, which orients and locates in the system at the junction, to deflect coiled tubing or coupled pipe into the desired wellbore. With this design, Level-3 multilaterals have full reentry functionality into both the main bore and lateral com-

Chapter Five Alternative Practices and Special Techniques

pletions.15 Fig. 5.14 illustrates a basic wellbore configuration that allows for coiled tubing or other compatible size tool re-entry. These installations begin with a standard horizontal open-hole well with a slotted liner anchored to the main-bore casing. Figure 5.15 is a TAML Level-3 schematic of a Smith MX junction with an open-hole gravel pack. With this system, a one-trip whipstock is used to mill the long, full-gauge window. Here too, the lateral wellbores can be reentered through the production tubing string with size-compatible tools. Additional open-hole drilling, out the lower end of the lateral liner, may be needed to meet completion objectives requiring open-hole slotted liners, conventional screens or premium screens (Fig 5.16). At this point, access to the lower producing borehole is achieved. For a TAML Level 4 completion in a depleted zone, Weatherford’s StarBurst system can be considered. It provides a cemented-liner, tieback junction with main bore production access, as well as production and tool access to the lateral leg or new drainage point. This system is ideal for existing wells in mature fields, particularly where additional nearby reserves can be accessed while still maintaining the original wellbore production. Figure 5.17 uses a hollow whipstock that can be combined with an UltraPak permanent packer to withstand high pressures during well construction. Again, re-entry into the lateral sections can be made with size compatible tools. Sand control installations can be run in both TAML Level-5 and Level-6 wells. However, these types of completions are not yet common place. Rod Pump and ESP Sand Control Techniques Formation sand, frac sand fragments and other abrasive particles, which are roughly 50 microns to 200 microns in diameter, cause most rod pump damage. These particles are small enough to enter the space between a rod pump plunger and barrel, and large enough to cause damage. As the pump cycles, particles are crushed between the two surfaces, scoring the plunger and barrel. This results in the need for premature pump replacement. ESPs are typically damaged by sand production across a

Fig. 5.13. Vibra-Pak completions in an open hole (left ) and a cased hole (right )

HOOK hanger with hold down slips 5.75 in drift into lateral with diverter in place in the HOOK hanger

ESP

2,700 ft MD +/- 4,500 ft long 8-1/2 in. openhole laterals with 7 in. slotted liners 5.50 in. drift into mainbore with diverter in place in the HOOK hanger

Fig. 5.14. TAML Level 3 hanger with hold down slips and slotted liner 121

Modern Sandface Completion Practices

broader particle size range, impacting bearings, impellers and diffusers. Numerous methods have been developed to minimize the impact of sand on wells, which employ various forms of artificial lift. These methods include: • Minimizing the amount of sand entering the wellbore • Minimizing the amount of sand entering the pump • Minimizing impact of sand on pump.

Liner hanger

Whipstock

Float shoe

Packer

Liner hanger

Fig. 5.17. TAML Level 4 with StarBurst system and cemented liner tieback junction

Fig. 5.15. TAML Level 3 with MX junction, screen and gravel pack

Drillpipe 9 5/8-in. casing Centralized lateral liner hangers

Centralized liner joint

8 1/2-in. open hole 7-in. casing

Production packer

Running tool

Float shoe with sealbore sub 3 1/2-in. dual 6-in. open hole prepack screen

Washpipe Expandable flapper

Seal assembly

Fig. 5.16. TAML Level 3 washdown system for stand-alone screens run in a open hole (sized-solids DIF displaced) 122

Fig. 5.18. Conventional rod-pump plunger (left ) and the Farr plunger (right )

Chapter Five Alternative Practices and Special Techniques

Minimizing sand entry into the wellbore must be done during the initial well completion or through implementation of a post completion sand-control treatment (both of which have been covered extensively in this Handbook). Numerous modifications to the conventional sucker rod pump, including the Farr plunger and the Muth dual string system, have been developed to minimize the impact of sand on these pumps.16,17 Filters or membranes, including the Stren PumpGard, and centrifugal sand separators attached to the pump intake can also reduce the amount of sand entering a pump system. Most of the engineered systems and techniques used to prevent abrasive particles from entering a pump have been designed to achieve the following objectives: • Reduce well pulling cost • Increase pump life • Reduce down time • Eliminate stuck plungers • Increase pump efficiency • Reduce pump repair costs. Farr plunger. The connector on the top of a conventional plunger (Fig. 5.18 left), which connects the pull rod to the plunger, is 60 thousands smaller in diameter (OD) than the plunger itself. This connector is tapered downward and outward from where the pull rod connects. The smaller diameter allows for a gap at the top of the plunger. The taper on top of the connector creates a funnel. As the plunger moves upward, the sand (or any solids in the produced fluid) is forced down into the funnel and stuffed inside the gap, pushing abrasive material between the connector and the pump barrel wall. The sand will eventually migrate down between the plunger and the pump barrel wall. This abrasive material starts wearing on the two metal surfaces, creating lower and lower pump efficiencies. Eventually the pump will not move the fluid volumes required and will need to be pulled. The unique aspect of the Farr plunger (Fig. 5.18 right) is the manner in which the sucker rod string is connected to the plunger. The connector, which is thought to create the problems in the conventional plunger, has been moved from the top of the plunger to the bottom of the plunger in the Farr design. Essentially, the Farr design eliminates

the funnel and the wedge, and moves the 60 thousands gap to the bottom of the plunger. Hence, the top of the plunger has only a 2 or 3 thousands clearance between the plunger and pump barrel as opposed to the 60 thousands in the conventional design. Additionally, the angle at the top of the plunger has been reversed to force sand inward as opposed to outward in the conventional design. The likelihood of sand getting between the plunger and pump barrel is greatly diminished, and the plunger now acts like a scraper, cleaning off the pump barrel wall and throwing sand inward as opposed to outward. PumpGard. The PumpGard from Stren, unlike formation sand screens (which were discussed in Chapter Two), brings protection directly to the rod pump, tubing pump or ESP. It consists of a precision 316 stainless steel membrane contained in a protective steel carrier (Fig. 5.19) that installs directly to the pump. The membrane filters production fluid before it enters the pump inlet, preventing sand cutting of the pump. PumpGard intercepts particles in the critical size range (Table 5.4, see page 124). The screen sizes are selected according to well characteristics; however, screens rated at 100 microns are effective for most “general purpose” service applications. For precise specification of micron rating, Stren can process customer-supplied solids samples in it solids characterization laboratory. There are several PumpGard models designed for specific applications. For rod pump applications – PumpGard is available in single or multiple tool configurations. It threads directly to the pump standing valve by universal connections for easy installation and retrieval via the rod string. Pressure drop across the membrane is typically less than 1.0 psi when first installed. For tubing pump completions – The PumpGard HiFlo connects to the seating nipple or tubing string below the pump. The HiFlo Series 400 and 500, for 5-1/2 in. and 7 in. cased wells, provide high capacity. They are hydraulically balanced for service with standard and big-bore tubing pumps. API 25, E30-sized cartridges are the modular building blocks around which these units can be assembled to meet virtually any capacity.

For ESP applications – The PumpGard HiFlo ESP prevents “sand cut” damage and helps maintain pump efficiency. These units are available in capacities up to 20,000 bfpd. Units may be threaded directly to the pump shroud, or for unshrouded pumps, used with standard packers or the Stren ESP Auto-Set sub. This sub automatically inflates to casing to direct de-sanded production into the pump intake, but retracts to tubing collar diameter for easy production tubing removal from the well.

Fig. 5.19. The PumpGard sand-screen membrane filter

123

Modern Sandface Completion Practices

US & ASTM Std. Sieve No. (mesh) 20 30 40 50 60 70 80 100 120 140 170 200 240 270 400 550 800 1,250 – –

Equivalent Opening in. mm microns 0.0331 0.0234 0.0165 0.0117 0.0098 0.0083 0.0070 0.0059 0.0049 0.0041 0.0035 0.0029 0.0025 0.0021 0.0015 0.0010 0.0006 0.0004 0.0002 0.00006

0.841 0.595 0.420 0.297 0.250 0.210 0.177 0.149 0.125 0.105 0.088 0.074 0.063 0.053 0.037 0.025 0.015 0.010 0.005 0.002

841 595 420 297 250 210 177 149 125 105 88 74 63 53 37 25 15 10 5 2

Typical proppant (frac sand)

Table salt Typical pump plunger/barrel tolerance

PumpGard cartridge control point

Table 5.4. Conversion table for standard screens indicating PumpGard particle size control for protection of rod pumps. References 1. Wedman, M., Lynch, K., and Spearman, J., “Hydraulic Fracturing for Sand Control in Unconsolidated Heavy-Oil Reservoirs,” SPE 54628, Western Regional Meeting, Anchorage, Alaska, May 26-28, 1999. 2. Coulter, A. and Gurley, D., “How to Select the Correct Sand Control System for Your Well,” SPE 3177, AIME, Petroleum Engineers, 1971. 3. Hara, P., Mondragon III, J., and Davies, D., “A Well Completion Technique for Controlling Unconsolidated Sand Formations by Suing Steam,” U.S. DOE Oil and Gas Conference, Dallas, Texas, June 28-30, 1999. 4. Freiman, O. and Johnson, K., “Use of the DualScreen Thru-Tubing Sand Control Method,” SPE 28698, International Petroleum Conference, Veracruz, Mexico, October 10-13, 1994. 5. Lee, C. and Darby, M., “Effective Thru Tubing Gravel Pack Methods in Attaka Field,” Asia Pacific Improved Oil Recovery Conference, Kuala Lumpur, Malaysia, October 8-9, 2001. 6. Bell, R., Jr., Morrison, D., and Martch, W., Jr, “Achieving High-Rate Completions with Innovative Through-Tubing Sand Control,” SPE Drilling & Completion, March 2002, 50-53.

124

7. Vickery, E., “Through-Tubing Gravel Pack with Small Clearance: The Important Factors,” SPE 73773, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 20-21, 2002. 8. Ebinger, C., “Rigless Frac Packs Provide Cost Effective Completions,” World Oil, October 2000, 9. Rice, R., Navaira, G., and Champeaux, G., “Through-Tubing Gravel Packs Performed by Electric Wireline – Case History,” SPE 58784, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 23-24, 2000. 10. Solum, J., “A New Technique in Sand Control Using Liner Vibration With Gravel Packing,” SPE 12479, Formation Damage Control Symposium, Bakersfield, California, February 13-14, 1984. 11. Solum, J., “Horizontal Well Gravel Compaction Simulator Tests with Rotary Vibration in a Water Packing System,” SPE 24958, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 26-27, 1992. 12. Betancourt. S., Shukla. S., Sun, D., Asii, J. Yan, M. Arpat, B. and Sinha, S., “Developments in Completion Technology and Production Methods,” SPE 74427, International Petroleum Conference, Villahermosa, Mexico, February 10-12, 2002. 13. MacKenzie, A. and Hogg, C., “Multilateral Classification System with Example Applications,” World Oil, January 1999. 56.

14. Pasicznyk, A., “Evolution Simplifies Multilateral Wells, “ Hart’s E&P, June 2000, 53. 15. Pasicznyk, A., “Evolution Toward Simpler, Less Risky Multilateral Wells,” SPE/IADC 67825, Drilling Conference, Amsterdam, The Netherlands, February 27-March 1, 2001. 16. Muth, G. and Walker, T., “Extending Downhole Pump Life Using New Technology,” SPE 68859, SPE Western Regional Meeting, Bakersfield, California, March 26-30, 2001. 17. Evans, B. and Muth, G., “Increasing Heavy Oil Production Utilizing Dual String New Technology,” SPE 46220, SPE Western Regional Meeting, Bakersfield, California, May 10-13, 1998.

CHAPTER SIX

Next Generation Completion Technologies Candidate Selection • Drill-In and Completion Fluids • Completion Hardware Fracture-Well Connection • Frac-Pack Analysis • Improved Well Test Interpretation Eliminating Hardware • Global Databases ydrocarbons are a non-renewable resource and reserves of this resource are rapidly depleting. Analysts first predicted that the world was running out of oil and gas reserves in 1940. Today’s depleted fields are often being replaced by lower-quality fields and smaller, low-permeability and more complex reservoirs. Larger new discoveries are often in ultra-deepwater, which introduces a whole variety of technological challenges adding to the difficulties of maintaining current reserve levels. In the face of diminishing supplies, industry experts forecast that worldwide demand for oil and gas will grow steadily during this century. The petroleum industry will face increased pressure to provide even larger volumes of reasonably priced oil and natural gas. Success will require operators to lower operating costs, increase production rates and increase over-all recovery from each reservoir. To economically produce the growing number of depleting reservoirs will require significant breakthroughs in technology. Today, completion techniques are more than ever based on economics, and that is how it will remain for the future. Several operational factors will always have a direct impact on completion costs. They include: • Design simplicity • Rig time • Rig floor assembly time • Well depth • Well control problems • Zone spacing and the number of zones to be completed • Bottomhole pressure, temperature and fluids • Availability of surface pumping and blending equipment • Well completion life • Workover costs • Safety considerations

H

Each of these factors contributes to the selection of a suitable, well-specific completion solution. The following are ongoing developments related to completion technologies that may have an impact on some of the above cost drivers.

Candidate Selection Wellbore stability is approached holistically with vertical, highly-deviated, horizontal/multilateral wells and potential fracture treatments, such as HRWPs or frac packs. To reduce drawdown while obtaining economically attractive production rates, proactive well completion and/or workover strategies are critical to wellbore stability and sand production control. Identifying and matching the candidate well’s reservoir characteristics with optimum well completion configuration is critical to economic success. Necessary steps include (1) appropriate reservoir engineering, (2) formation characterization, (3) wellbore-stability calculations and (4) the substantive combination of production forecast with an assessment of sand production potential.

Drill-In and Completion Fluids The next generation of drill-in and completion fluids are being developed. Some envision “smart” fluids that would consider application and formation specific issues affecting wellbore stability and formation damage. New gels, polymers and leakoff-control additives are urgently needed for drilling complicated multilateral wells and for drilling through difficult formations. Non-damaging fluids will be critical to the future of production engineering. Stimulation treatments are often expensive, cumbersome and, at times, unsuccessful (partially due to adverse effects of improper fluids contacting the formation). Production- induced problems, such as inorganic and organic

materials deposition and especially sand production, can be avoided if the formation remains undamaged from contact with fluids and large drawdown is not required for adequate production. Filter cake removal services currently used for simultaneous gravel packing and cleanup in open-hole gravel packs may find similar application in open-hole frac packing. Incorporating aggressive breakers and filtercake removal chemicals into fracturing fluids, without affecting their base properties, would be advantageous to ensure chemical contact with the entire open-hole section during frac-pack treatments. It could also provide a uniform production profile. The increasing use of synthetic oilbase mud, especially in high-permeability reservoirs, will require compatible fracturing fluids. This need will become increasingly important as operators perform more open-hole frac packs. Fluid compatibility, formation wetability and filter-cake cleanup must be addressed in the context of expensive displacement to water-base systems and oilbase fluid handling.

Completion Hardware Completion hardware will be improved in conjunction with other completion developments. There will always be a need to simplify, eliminate or otherwise advance beyond the modified gravelpack hardware currently being used in frac packs. In wells that are more marginal, smaller tools are needed for rigless completions. There is also a need for improved zonal isolation hardware, for the execution of hydraulic fracturing in complex well-fracture configurations and conventional sand control treatments. In fact, lack of appropriate drilling, completion and stimulation hardware is often the limiting factor in 125

Modern Sandface Completion Practices

new completion configurations. Clearly, all fracture treatments must be conducted separately, in stages; consequently, inexpensive and robust zonal isolation schemes are necessary. Zonalisolation hardware is currently available, but it can be expensive and often logistically difficult to use. Alternative techniques to the use of zonal-isolation hardware, such as polymer or sand plugs, are often prone to failure. Application of stand-alone screens will create improvements to long-term productivity. This will involve advancements in the various screen designs and techniques to uniformly collapse the open hole around these devices. Expandable screens will also be used for more sand control applications as installation and expansion procedures continue to improve. Alternate path screens will further improve frac-pack treatment diversion across longer intervals, and multiple temperature gauges with electronic memory placed strategically in the washpipe will monitor slurry diversion to other zones.

Fracture-Well Connection New fracture-and-well interfaces should be developed, which could include the next generation of screens and replacement technologies. Hydraulic fractures are prone to sand production, both from the reservoir and from the proppant pack itself. This problem is particularly prevalent in high-rate wells where, although the reservoir problem may be resolved, the near-well fracture portion may be susceptible to sand production. The current solution, stand-alone screens, should be replaced. Although they are reasonably effective, standalone screens can cause a serious choke effect at the fracture-well interface in these high-rate wells. New consolidation techniques, or perhaps oriented long perforations and alternative sand-exclusion devices, are potential solutions.

Frac-Pack Analysis Frac-pack placement data generally indicate creation of a fracture and subsequent tip screenout, but post-treatment pressure data often indicate positive skin values and some remaining damage. This raises questions about the effectiveness of propped fractures. Computer models, used to manage the data, have been developed to resolve discrepancies 126

between geophysical evaluations, welllog interpretation, fracturing data from frac-packing treatments and well-test pressure analysis. Generating consistent solutions and resolving discrepancies require measurement of multiple parameters within a discipline, and integration across disciplines. Treatment-pressure analysis is based on an understanding of the leakoff process and on the concept of net pressure. Soft formations and their rock mechanics are not yet well understood, and an appreciation of which mechanisms control fracture length and width is more evasive than ever. Many of the debates could be settled by determining the closure pressure, and hence the net pressure, with more confidence. While there is a lot of activity in this area, new results are very limited. Reiterating old ideas is common (flowback or not, two mini-fracs or three, crosslinked fluid or not, step-rate or not, etc.). These ideas are revealing little new information. There is a definite need for innovative thinking here. For example, an independent and possibly direct instrumental determination of closure pressure would be a significant step forward in the engineering of hydraulic fracturing.

Improved Well Test Interpretation For the evaluation of high-permeability fracture treatments, it is imperative to improve the well-test interpretation procedure and to understand the phenomenon of positive apparent skins. The lack of desired (negative) post-treatment skins is still haunting the industry. Well productivity is obviously being improved by frac-packing, but it is not clear whether they could be significantly improved with more aggressive treatment parameters. Would schedules that are more aggressive provide additional benefit, or are the possibilities limited by the choke effect at the perforations? These issues are not clearly addressed by current pressure-transient methods.

Eliminating Hardware New technologies have been recently introduced that promise to speed routine application of rigless completions. Coiled tubing-conveyed fracturing technology is rapidly becoming a viable tool for exploiting bypassed payzones.

This new technology has been applied successfully onshore in multi-layered, low-permeability reservoirs. The next step is to take it offshore. Accessing offshore wellbores in a workover environment and placing a frac-pack or screenless completion in a new zone without using a costly conventional drilling or workover rig opens countless future, cost-saving opportunities. Significant friction reduction with VES fluids may increase application of coiled tubing-conveyed fracturing by allowing this type of rigless completion to be performed at greater depths. In increasing numbers, operators are installing sand-exclusion screens that expand against the borehole wall. Hence, an annular gravel pack is not required to achieve wellbore stability. Expandable screens may also be installed after frac-packing treatments to eliminate internal annular packs. Emerging screenless techniques potentially produce completions with a negative skin and reduce completion costs while maintaining effective sand control. In this case, TSO fracturing and the proppant ring around a wellbore act as a sand filter. However, any area not covered leaves perforations open to produce sand. This technique requires various combinations of oriented perforating, injection of organic resins to hold formation grains in place and resin-coated proppants or fiber technology to prevent proppant flowback.

Global Databases An emerging consensus points to the importance of establishing global databases of formation and other properties, for specific geographic areas and specific activities. The main challenge is not securing funds or even identifying proper intelligence tools. The major obstacle is providing incentives and methods to encourage continuous input of data and the tailoring of data formats to a common standard. Once a database is established, simple interpretive tools can be used to efficiently evaluate a large number of treatments. Estimated fracture dimensions and conductivities could then be compared with results from pressure-transient analysis and production results. Discrepancies could be resolved using a large number of data sets from various independent sources.

APPENDIX ONE

10,000 White sand Brown sand Lightweight ceramic Intermediate ceramic Resin coated

Permeability, D

1,000

100

20/40 10

12/18 16/20

40/60 40/70 30/50

70/140 1 0.0

16/30

0.2

0.4

12/20

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Mean grain diameter, mm

Appendix 1.1. Permeability at 4,000 psi net confirming stress

0

50

100

150

200

250

300

350

0.08

14

Permeability (D) values 0.07 0.06

21

1/K

0.05 0.04

28

0.03

40 52

0.02 0.01

73 295

403

126 221

0 0

10

20

30

40

50

60

MMCFD

Appendix 1.2. Effect of non-darcy flow on permeability (assuming a 100 ft high fracture filled with 4 lb/ft2 20/40 CarboLite at 4,000 psi closure stress at 1,000 psi BHFP at 180°F). 127

Modern Sandface Completion Practices

1,000

20/40 CarboLite

Permeability, Darcy

20/40 EconoProp

100

30/50 EconoProp 20/40 sand

0 0

2,000

4,000

6,000

Closure stress – psi

Appendix 1.3. Permeability vs. closure stress of proppants

128

8,000

10,000

12,000

APPENDIX TWO Chapter One Two

Three

Page No.

Figure No.

4 14 15 15 17 18 18 19 19 20 21 22 22 22 22 22 22 23 23 23 24 24 25 25 25 26 27 27 27 31 32 33 33 36 36 37 37 38 38 39 39 40 40 40 41 41 49 54 54 55 56 58 58 60 61 63 64 64 65 67 68

1.3 2.1 2.4 2.5 2.6 2.8 2.9 2.10 2.11 2.17 2.18 2.19 2.20 2.21 2.22 2.23 2.24 2.25 2.26 2.27 2.28 2.29 2.30 2.31 2.32 2.33 2.34 2.35 2.36 2.42 2.43 2.45 2.46 2.52 2.53 2.54 2.56 2.57 2.58 2.59 2.60 2.61 2.62 2.63 2.64 2.65 3.4 3.8 3.10 3.11 3.13 3.15 3.16 3.19 3.20 3.21 3.22 3.23 3.24 3.26 3.27

Graphic/Data courtesy of: Baker Hughes Incorporated Baker Hughes Incorporated M-I L.L.C. Flo Trend Systems, Inc. Halliburton Baker Hughes Incorporated Core Laboratories Red Wing Perforating Service Red Wing Perforating Service Nagaoka USA Baker Hughes Incorporated Reslink Reslink Reslink con-slot Baker Hughes Incorporated Baker Hughes Incorporated Weatherford International LTD. Halliburton Stren Inc. Schlumberger Weatherford International LTD. Weatherford International LTD. Singa Engineering Smith Services Baker Hughes Incorporated Core Laboratories Topac Instruments Baker Hughes Incorporated Baker Hughes Incorporated Baker Hughes Incorporated Baker Hughes Incorporated Baker Hughes Incorporated Baker Hughes Incorporated Baker Hughes Incorporated Halliburton Baker Hughes Incorporated BJ Services Schlumberger Schlumberger Schlumberger Halliburton Schlumberger Schlumberger Baker Hughes Incorporated Schlumberger Oilfield Review Well Flow International Halliburton Algae Image Archive Dept. of Biological Sciences, Bowling Green St. Univ., Bowling Green, Ohio BJ Services Greig Filters, Inc. Filtration Technologies Filtration Technologies Schlumberger Oilfield Review Schlumberger Oilfield Review Schlumberger Oilfield Review Schlumberger Halliburton Schlumberger Oilfield Review Schlumberger Oilfield Review Schlumberger Oilfield Review 129

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Chapter

Four

Five

Appendix One

130

Page No.

Figure No.

69 70 71 71 72 75 77 77 78 78 79 80 81 81 84 86 89 91 92 92 93 94 95 95 97 97 103 104 104 104 104 104 104 104 105 105 105 106 106 106 106 106 106 108 109 111 112 115 116 118 118 121 121 122 122 122 123 127 127 128

3.28 3.31 3.32 3.33 3.34 3.39 3.41 3.42 3.43 3.44 3.47 3.48 3.49 3.50 3.57 3.60 3.62 3.64 3.65 3.66 3.67 3.68 3.69 3.70 3.71 3.72 4.1 4.2 4.3 4.5 4.6 4.7 4.9 4.10 4.11 4.12 4.13 4.14 4.15 4.16 4.17 4.18 4.19 4.21 4.22 4.24 4.25 5.2 5.3 5.7 5.8 5.13 5.14 5.15 5.16 5.17 5.19 1 2 3

Graphic/Data courtesy of: Computalog/Precision Drilling Corporation Baker Hughes Incorporated Halliburton Schlumberger Baker Hughes Incorporated Baker Hughes Incorporated Baker Hughes Incorporated Baker Hughes Incorporated Baker Hughes Incorporated Baker Hughes Incorporated Schlumberger Schlumberger Halliburton Schlumberger Oilfield Review Schlumberger Oilfield Review Schlumberger Oilfield Review Carbo Ceramics, Inc. Schlumberger Oilfield Review Schlumberger Oilfield Review Schlumberger Oilfield Review Schlumberger Oilfield Review Schlumberger Oilfield Review Schlumberger Oilfield Review Schlumberger Oilfield Review Baker Hughes Incorporated Halliburton Baker Hughes Incorporated Halliburton Halliburton Schlumberger BJ Services Halliburton Schlumberger Baker Hughes Incorporated BJ Services Baker Hughes Incorporated Schlumberger Baker Hughes Incorporated BJ Services Halliburton Schlumberger Baker Hughes Incorporated Schlumberger Meyer & Associates, Inc. Pinnacle Technologies ProTechnics, a Core Laboratories Company ProTechnics, a Core Laboratories Company Halliburton Halliburton Thru-Tubing Systems, Inc. Halliburton PT Pipa Mas Putih Baker Hughes Incorporated Smith Services Halliburton Weatherford International LTD. Stren Inc. Stim-Lab, a Core Laboratories Company (Proppant Consortium) Stim-Lab, a Core Laboratories Company (Proppant Consortium) Stim-Lab, a Core Laboratories Company (Proppant Consortium)

APPENDIX THREE

Contributor Profiles and Acknowledgements The publisher and authors of this handbook greatly appreciate the technical and editorial assistance of the individuals listed in this appendix. Without their cooperation the publication of this handbook would not have been possible. Charles Boatman is a global Dril-N product line champion for Halliburton. He joined Baroid in 1962 as a field engineer. A graduate of Rice University, Mr. Boatman is a member of SPE, AAIDE, API and the Rice Owl Letterman Club. John Cameron, technical manager-Expandable Sand Control for Weatherford Completion Systems in Houston, has 22 years of industry experience. Prior positions include technical manager for conventional well screens at Weatherford and Pall Stratapac, and assignments for Baker Atlas in Aberdeen, Syria, Norway and Abu Dhabi. He graduated from Imperial College at the University of London with a B.Sc. in physics.

Mike Flecker, director of technology for ProTechnics, is responsible for research, development, manufacturing and maintenance of Completion Diagnostics. He provides interpretation training and support to log analysts, sales and field personnel, and global support on special problems related to petrophysical analysis of cased- and open-hole logs. Kent Folse is a global product champion for Halliburton Energy Services Tools, Testing & TCP product service. He holds a BS degree in petroleum engineering from the University of Louisiana at Lafayette. He began his career with Halliburton in 1990.

Bruce Comeaux is Gulf Coast technical manager for BJ Services. He has experience in cementing, sand control and matrix stimulation, and was involved in the evolution of sand control from low-rate gravel packing to frac-packing. He has a BS degree in petroleum engineering from Louisiana State University.

Nicholas Gee, vice president, Weatherford ESS, holds a degree in chemical engineering from Birmingham and an MBA from Warwick Business School. He spent six years with BP in the UK and Norway, followed by positions with Agip, Petroline and Global Marine. He joined Weatherford in 2000 as region manager, NECIS.

Dr. Mike Conway, president of Core Laboratories’ STIMLAB Div., has worked in stimulation research since 1978. He has evaluated fracturing fluid leakoff, proppant conductivity damage, multiphase non-Darcy flow’s impact on effective conductivity and proppant flowback. He holds a BS in pharmacy, MS in pharmacology and PhD in organic chemistry from University of Oklahoma.

Terje Gunneroed is president of ResLink. He earned BSc degrees in mechanical and petroleum engineering, and has more than 20 years of international experience within well construction, production optimization, stimulation, sandcontrol, well intervention and management.

Mary Edwards is Sand Control Product Line technical manager for BJ Services. Earlier, she was responsible for sand control technical support in the Gulf of Mexico and served as Gulf Coast lab manager for Baker Hughes INTEQ and production & facilities engineer with ARCO. She holds a BS degree in petroleum engineering, University of Tulsa.

Brad Hoffman, manager of the Tubing Conveyed Perforating engineering group at Schlumberger’s Reservoir Completions Center, Rosharon, Texas, received a BS in petroleum engineering from Texas A&M University. He worked for Trilogy Oil Corp. before joining Schlumberger as a testing engineer. He has worked in field service, Cased Hole and Perforating Systems.

Brian Evans, Sand Control section leader, joined BJ Hughes in 1983, later rejoining BJ Services to lead sand control research. He has provided engineering support for sand control pumping, including acidizing and gravel packing. He holds a BS in petroleum engineering, Texas Tech University.

Dr. Lewis Lacy is director of Geomechanics for Core Laboratories’ Houston Advanced Technology Center. He holds BS and MS degrees in physics from Virginia Tech and a PhD in applied physics from the University of Tennessee. He has more than 20 years of experience in applying rock and soil mechanics.

Harvey J. Fitzpatrick, Jr., is Sand Control product manager for Halliburton Energy Services. His key interests include integration of technology and completions operations to enhance completion performance. He earned a BS in chemical engineering from Tulane University in 1979.

Stephen P. Mathis is manager of Baker Oil Tools’ Technical Services Group, providing support for sand control tools and pumping. Before joining Baker, he spent 11 years with Exxon Production Research Co. He holds BS and MS degrees in geological engineering from the University of Arizona.

131

Modern Sandface Completion Practices

Paul Metcalfe, vice president of Expandable Technology for Weatherford International, has 15 years of oil industry experience. At Petroline Wellsystems Ltd., he was responsible for development of the first commercial expandable technologies, including expandable sand screens. He worked seven years for Shell International, and is a graduate of the University of Manchester with a B.Sc. in chemical engineering. Mehmet Parlar is business development manager for Schlumberger Sandface Completions-Fluid Systems in Rosharon, Texas. He holds PhD and MS degrees from the University of Southern California, Los Angeles, and a BS from Istanbul Technical University, Turkey, all in petroleum engineering. He has 13 years of industry experience. Hugh Peek is area manager of Routine Rock Properties, US Gulf Coast, with Core Laboratories in Houston. He attended the University of Texas at Dallas, earning a BS degree in geosciences in 1977, joining Core Lab shortly thereafter. He is a member of SPWLA. Dan W. Pratt, vice president of Engineering and Explosives Technology, Owen Oil Tools LP, has spent nearly 25 years in the design and manufacture of oil-field explosives products, more specifically with shaped charges. He holds a BS in mechanical engineering from the University of Texas at Arlington, and 6 US and numerous foreign patents relating to design of perforators/shaped charges. Paul Price is with Schlumberger Sandface Completions. A registered Professional Engineer in Texas, Louisiana and Oklahoma, he holds BS degrees in chemical and petroleum engineering from Mississippi State University and an MS in advanced petroleum studies from IFP in Paris, France. Ed Van Sickle is product line manager for Baker Oil Tools Perforating and Baker Atlas Pipe Recovery in Houston. During 22 years with Baker Hughes, he worked in completion, sand control and pipe recovery operations. He earned a BS in mechanical engineering from the University of Houston. Paul B. Vorkinn is vice president of Marketing for ResLink. He holds a BSc in petroleum engineering and an MSc in chemical engineering, and has 20 years of international experience in well construction, production optimization, sand control, pressure pumping and well intervention. David Walker, Completion Tools Product Line manager, joined BJ Services via a merger with OSCA. He is experienced in sand control, multi-lateral completions and intelligent completion systems, and holds a BS degree in mechanical engineering from the University of Southwestern Louisiana. Donald Wells has 28 years of petroleum industry experience, which includes 10 years of global involvement with sand control. An SPE and CIM member, he is market manager, Oil and Gas, Purolator Facet Inc.

132

R. J. Wetzel, Sandface Completions business development manager for Schlumberger, holds a BS in mechanical engineering from the University of Louisiana at Lafayette and has nine years of experience in the North Sea and Europe and more than 12 years of US-based experience in completions technology, operations and management. Pat York, director of Sales & Marketing, Solid Expandable Tubulars for Weatherford Completion Systems in Houston, has 30 years of oilfield experience. Before joining Weatherford he served in management for Enventure, Halliburton and Dresser Atlas in operations, business development and marketing. He holds a BS in electrical engineering and an MBA from Northwestern State University. The following individuals contributed both their time and talents toward making this publication as successful as possible: Mary Atchison Aileen Barr W.T. Bell Bill Bellenger James Cashion Beth Cunningham Allan R. Duckett Don Dumas Valerie Edwards Mary Fouts James Garner Walt Glover Amy Green Alan Greig Roger Horton David Hubbard J.M. “Johnnie” Jackson Hauke N. Jürgens Kathleen Keeler Paddy Keenan William Lang Debbie Markley

Christine McGhee Bill Miller Brian Minton C. Mark Pearson Robert Picou Lindy Pollard Jimmy Priest Jim Redding Jason Renkes Greg Salerno Kenneth Schmitt Stephen Schubarth Brenda Sharp Richard Sinclair Jim Smolen Phil Snider Jan Stafford C.O. “Doc” Stokley Mark Teel David Weeks Cheryl Willis J'Nette Davis

DIRECTORY

Manufacturing and Service Suppliers A listing of completion equipment, product and service suppliers.

BAKER OIL TOOLS

Executives: Chairman, President & CEO President, US/Mexico Division President, International Division Vice President, Technology

9100 Emmott Road 77040 P.O. Box 40129 Houston, TX 77240-0129 USA Tel: 713-466-1322 Fax: 713-466-2502 www.bakerhughes.com/bot/ Baker Oil Tools provides completion, workover and fishing solutions that help exploration and production companies maximize value from their hydrocarbon-bearing assets. Since its earliest days, the Baker name has been synonymous with excellence in downhole and surface technology, performance and reliability. In the current era of riskier environments and higher stakes, those qualities are more valuable than ever. U.S. Offices: ALASKA Anchorage CALIFORNIA Bakersfield COLORADO Denver OKLAHOMA Oklahoma City TEXAS Houston Odessa Tyler Outside U.S. Offices: AUSTRALIA Canning Vale W. A. NORWAY Tananger UNITED ARAB EMIRATES Dubai UK Egham, Surrey Dyce, Aberdeen VENEZUELA Caracas

907-273-5100 661-327-7201 303-595-3675 405-842-4005 713-625-6800 915-563-7979 903-509-9056

618-9-455-0155 47-51-717000 971-4-8836322 44-1784-477 050 44-1224-223500 58-212-77-2253

BJ SERVICES COMPANY 5500 Northwest Central Drive Houston, TX 77092 USA Tel: 713-462-4239 Fax: 713-895-5851 www.bjservices.com [email protected] BJ Services is a leading provider of cementing, stimulation, completion systems and remedial well services to oil and gas operators worldwide. Operating in 50+ countries, BJ crews deliver best-in-class cement slurries, fracturing fluids, acid systems and production chemicals with state-of-the-art pumps, injection systems or coiled tubing units to provide zonal isolation and optimize production.

US Region Offices: ALASKA Anchorage CALIFORNIA Bakersfield COLORADO Denver LOUISIANA Lafayette New Orleans OKLAHOMA Oklahoma City PENNSYLVANIA Pittsburgh TEXAS Corpus Christi Dallas Houston Midland

J.W. Stewart Kenneth A. Williams David D. Dunlap Mark E. Hoel

907-349-6518 661-831-5084 303-832-3722 337-261-0615 504-299-8200 405-810-1448 412-494-3312 361-882-6177 214-220-9200 713-683-3400 915-683-2781

Outside US Region Offices: BRAZIL Rio de Janeiro 55-21-3410-9909 CANADA Calgary 403-531-5151 MEXICO Villahermosa 011-52-993-3521-444 SCOTLAND Aberdeen 44-1224-401401 SINGAPORE Singapore 65-6-877-8700 UAE Dubai 971-4-2821500

BORDEN CHEMICAL, INC. OILFIELD PRODUCTS 12777 Jones Road, Suite 255 Houston, TX 77070 USA Tel: 281-618-1600 Fax: 281-618-1698 www.bordenchem-oilfield.com [email protected]

CABOT SPECIALTY FLUIDS, INC. Waterway Plaza Two 10001 Woodloch Forest Drive, Suite 275 The Woodlands, TX 77380 USA Tel: 281-298-9955 Fax: 281-298-6190 www.cabot-corp.com/csf [email protected] Cabot Specialty Fluids, a wholly owned subsidiary of the Cabot Corporation, was formed in August 1996 as part of Cabot’s market-focused business model. Serendipity was at work in 1993, when Cabot purchased the Tantalum Mining Corporation of Canada to obtain access to tantalum reserves for Cabot’s Performance Materials division. Not only did we obtain tantalum reserves, but also we obtained some 82 percent of the worlds known reserves of pollucite, a mineral rich in cesium. Today, CSF’s 158 employees manage the mining and production of cesium chemicals, tantalum and spodumene. Executives: President Marketing

William J. Lang Norman P. Kenney

CARBO CERAMICS INC. 6565 MacArthur Blvd. Suite 1050 Irving, TX 75039 USA Tel: 972-401-0090 Fax: 972-401-0705 www.carboceramics.com [email protected] For a quarter century, ceramic proppants manufactured by CARBO Ceramics have helped make oil and gas wells around the globe more productive. The uniform shape and consistent size of CARBO proppants create a more permeable pathway for oil and gas to flow into the wellbore, resulting in greater productivity and financial return. Executives: President & CEO Sr. Vice President & CFO

C. Mark Pearson, Ph.D. Paul G. Vitek

Borden Chemical is the world’s leading provider of resin coated sands and ceramics for use as propping agents in oil and gas wells. With more than 2 decades of research and development experience, Borden offers a full line of products specific to the sand control and associated Frac Pack marketplace under its BorPac‚ product line. Executives: Business Development Manager Marketing Manager

Daryl Johnson Jason Renkes

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Modern Sandface Completion Practices

CHAMPION TECHNOLOGIES INC. SPECIAL PRODUCTS DIVISION 3355 West Alabama - Suite 400 Houston TX 77227-7727 USA Tel: 713-627-9011 Fax: 713-623-4652 www.champ-tech.com Special Products is the wholly owned specialty chemical division of Champion Technologies, Inc. We provide chemical products and technologies specifically targeted to oilfield service companies. We have based our business philosophy on satisfying customer needs in a cooperative environment, working closely with our customers’ research and development groups to create cost-efficient solutions that work. Executives: Chairman of the Board Director Special Products

Steve Lindley Elwin Myers

CON-SLOT SCREENS INTERNATIONAL GMBH Graue Riethe No. 2 WITTINGEN Lower Saxony D-29378 Germany Tel: 49-05831-8021 Fax: 49-05831-7643 [email protected] con-slot Screens is a world leading company specialized in application design and manufacturing fusion-welded wire screen products and accessories. The company is active in the fields of downhole completions of crude oil and natural gas production wells as well as injection stimulation wells, and also downstream processing screens, groundwater exploitation, many industrial process applications from potable and industrial water treatment, domestic and industrial waste-water treatment, mining washeries, paper pulp processing, to chemical and petro-chemical processing. Associated companies and representatives around the world gaurantee the close contact and fast assistance in solving the problems of our customers. Executives: General Manager Assistant Manager

Hauke Newton Juergens Andreas Dawed

CORE LABORATORIES 6316 Windfern Houston, TX 77040 USA Tel: 713-328-2673 Fax: 713-328-2150 www.corelab.com [email protected] Core Laboratories is a leading provider of proprietary and patented reservoir description, production enhancement and reservoir management services for the global petroleum industry. These services enable the Company's clients to optimize reservoir performance and maximize hydrocarbon recovery from their producing fields. The Company has over 70 offices in more than 50 countries and is located in every major oil-producing province in the world. The Company provides its services to the world's major, national and independent oil companies. Executives: CEO & President COO Sr. Vice President, 134

Dave Demshur Monty Davis

President Reservoir Management President, ProTechnics, A Division of Core Lab President, Petroleum Services, A Division of Core Lab President, Integrated Reservoir Solutions, A Div. of Core Lab President, Owen Oil Tools, A Div. of Core Lab President, Stim Lab, A Div. of Core Lab U.S. Offices: Core Lab Instruments TEXAS Houston Core Lab Petroleum Services ALASKA Anchorage CALIFORNIA Bakersfield COLORADO Aurora LOUISIANA Broussard New Orleans TEXAS Corpus Christi Garland Houston Midland Core Lab Reservoir Technologies TEXAS Houston Houston Integrated Reservoir Solutions TEXAS Houston Owen Oil Tools LOUISIANA Broussard Houma Scott Shreveport NEW MEXICO Farmington TEXAS Corpus Christi Ft. Worth Houston Pearland Pencor LOUISIANA Broussard TEXAS Houston Promore TEXAS Houston ProTechnics CALIFORNIA Bakersfield COLORADO Denver Trinidad LOUISIANA Scott NEW MEXICO Albuquerque Farmington OKLAHOMA Oklahoma City Tulsa

Jim Gresham Tom Hampton Steve Lee Randy Miller Jeff West Mike Conway

713-328-2673 907-562-2939 661-392-8600 720-532-2666 337-837-8616 504-733-6583 361-289-5457 972-926-4900 713-328-2673 915-694-7761 713-339-1616 713-328-2673 713-328-2673 337-837-0021 958-868-7010 337-984-1181 318-220-9009 505-324-9068 361-241-9575 817-551-0540 713-328-2673 281-993-9991 337-839-9060 713-328-2673 713-328-2673 661-399-4994 303-757-6222 719-846-1685 337-264-1958 505-888-0144 505-326-7133 405-848-6296 918-742-0590

TEXAS Alice Ft. Worth Houston Kilgore McAllen Midland Tyler UTAH Vernal WYOMING Casper Rock Springs Stim-Lab OKLAHOMA Duncan

361-668-3382 817-332-9607 713-328-2673 903-984-4223 956-664-1972 915-563-5879 903-581-4598 435-789-6621 307-237-1140 307-362-2030 580-252-4309

Outside U.S. Offices: Core Lab Instruments UK Dyce, Aberdeen 44-1224-421-000 Core Lab Petroleum Services ANGOLA Luanda +244 2 441-980 AUSTRALIA Perth 61-8-9353-3944 BRAZIL Rio de Janeiro 55 21 3868 9888 CANADA Calgary 1 403 250 4000 Edmonton 1 780 468 2850 Estevan 1 306 634 7379 Grand Prairie 1 780 532 4047 Mount Pearl 1 709 747 2673 CHINA Shekou 86-755-2669-1696 COLOMBIA Bogota 57-1-674-0400 EGYPT Cairo 20-2-272-9972 INDONESIA Balikpapan 62-542-63627 Jakarta 62-21-780-1533 Surabaya 62-31-397-2651 KAZAKHSTAN Aksai 7-311-33-93050 Aytrau City 7-3122-228-775 MALAYSIA Darul Ehsan 60-3-5031-0088 MEXICO Reynosa 52-899-925-6364 Villahermosa 52-993-352-2000 Villahermosa 52-993-314-1273 PAKISTAN Karachi 92-21-589-7750 TRINIDAD Marabella 1-868-658-0681 UAE Abu Dhabi 971-2-5-554-428 Dubai 971-4-883-5070 UK Dyce, Aberdeen 44-1224-421-000 VENEZUELA Barcelona 58-281-275-2815 Maracaibo 58-261-757-4611 Core Lab Reservoir Technologies CANADA Calgary 1-403-571-1555 MEXICO Ciudad del Carmen 52-938-383-1860 Poza Rica 52-782-824-0882 Reynosa 52-899-925-6364 Villahermosa 52-993-352-2000 UAE Abu Dhabi 971-2-5-554-428

Directory

UK Croydon 44-208-253-4000 VENEZUELA Maracaibo 58-261-721-1269 Integrated Reservoir Solutions U.K. Redhill 44-173-785-2390 Owen Oil Tools AUSTRALIA Thebarton 61-8-8152-0244 CANADA Brooks 1-403-362-2633 Calgary 1-403-571-2400 Edmonton 1-780-449-2021 Grand Prairie 1-780-539-0506 Lloydminster 1-780-871-0670 Redcliff 1-403-548-2888 Red Deer County 1-403-340-1017 Slave Lake 1-780-849-9789 CHINA Beijing 86-10-6434-9501 MEXICO Cuidad del Carmen 52-938-383-1860 Poza Rica 52-782-2-91-05 Reynosa 52-899-23-41-25 Villahermosa 52-993-52-20-00 OMAN Muscat 968-503-639 THAILAND Amphur Muang 66-74-33-4070 UAE Dubai 971-4-394-6889 UK Dyce, Aberdeen 44-1224-421-000 Promore CANADA Calgary 1 403 264 4246 Edmonton 1-780 988-5105 VENEZUELA Cuidad Ojeda 58 65 318 872 Maracaibo 58-261-757-4611 Pencor KAZAKHSTAN Aksai 7-333-558-4028 U.K. Dyce, Aberdeen 44-1224-421-000 Reading 44-1189-637-479 ProTechnics AUSTRALIA Gerringong 61-2-4234-0996 CANADA Calgary 1-403-269-2055 Grand Prairie 1-780-538-2144 Red Deer 1-403-340-8850 INDONESIA Jakarta 62-21-780-1533 MEXICO Villahermosa 52-993-502245 UK Dyce, Aberdeen 1-44-1224-421-068 VENEZUELA Caracas 58-212-238-6525 Stim-Lab CHINA Beijing 86-10-6434-9501

GREIG FILTERS, INC. P.O. Box 91675 Lafayette LA 70509 USA Tel: 337-237-3355 Fax: 337-233-9263 www.greigfilters.com [email protected] Established in 1982, Greig Filters specializes in completion fluid filtration. Worldwide sales of filtration equipment includes GFI Model Vertical Pressure Leaf Diatomaceous Earth Filter packages that set the standard for DE filtration equipment.Pakages include VPL, cartridge filters and pumping equipment on a single skid. GFI designs multiple size and combination cartridge filter units and oil removal equipment. Executives: Owner Manager

Alan Greig Tammy Roy

GRUPO ROYSO, C.A. Carretera Via La Toscana Maturin Edo, Monagas Venezuela Tel: 58-291-6437203 Fax: 58-283-6435501 [email protected]

Francisco Monagas

HALLIBURTON ENERGY SERVICES 10200 Bellaire Blvd. Houston TX 77072 USA Tel: 281-575-3000 Fax: 281-575-4995 www.halliburton.com Halliburton, founded in 1919, is one of the world's largest providers of products and services to the petroleum and energy industry. U.S. Offices: ALASKA Anchorage CALIFORNIA Bakersfield COLORADO Denver LOUISIANA New Orleans OKLAHOMA Oklahoma City TEXAS Dallas Midland WYOMING Evansville Outside U.S. Offices: BRAZIL Rio de Janeiro INDONESIA Jakarta

52-931-01100 234-53-231-798 7-095-755-8300 44-1224-795-001 971-2-676-3635

M-I L.L.C. P.O. Box 42842 Houston, TX 77242-2842 USA Tel: 281-561-1300 Fax: 832-295-2660 www.midf.com [email protected] M-I is a leading supplier of drilling and completion fluid products/systems, services and equipment to the worldwide petroleum industry. Its SWACO division is the world’s leading provider of pressure control, solids control, rig instrumentation and waste management equipment and services for the worldwide petroleum drilling industry. Executives: Eastern Hemisphere Vice President, Completion Fluids Western Hemisphere Vice President, Completion Fluids

Grupo Royso is dedicated to oil field service – oil well cementing (plug and abandont), oil well stimulation services, hot oil services, high and low pressure pumping services, trucking services and oil tool rental services. Executives: Operation Manager

MEXICO Villahermosa NIGERIA Lagos RUSSIA Moscow SCOTLAND Aberdeen UAE Dubai

907-344-2929 661-393-8111 303-308-4227 504-593-6700 405-231-1800 972-418-4230 915-682-4305 307-265-2105

55-21-3974-0000 62-21-780-11-00

Pete MacKenzie Dan Douglass

NORTON PROPPANTS, INC. 5300 Gerber Road Ft. Smith, AR 72904 USA Tel: 479-782-2001 Fax: 479-783-9984 www.nortonproppants.com [email protected] Norton Proppants, Inc., a Saint Gobain company, manufactures quality ceramic proppants globally for the oil & gas industry for use in hydraulic fracturing and sand control operations. We have been the industry’s right choice since 1973 when we manufactured our first man-made ceramic proppant, Sintered Bauxite, at the request of the Exxon Corporation. Executives: Business Unit Manager Sales & Marketing Manager

Tom Duncan Roy Webber

RED WING PERFORATING SERVICE, L.L.C. 5357 Goodrich Rd. Crowley, LA 70526 USA Tel: 337-788-1666 Fax: 337-788-1777 www.redwingintl.com [email protected] Established in 1996, Red Wing Perforating Service L.L.C. is unique in that we are the only independent pipe perforating and slotting service on the Gulf Coast. We can perforate and/or slot pipe with your custom designed hole or slot pattern to achieve desired open area. While our service area is global in nature, the approach to business is always personal. Executives: President General Manager

Tim Zaunbrecher Gerard Zaunbrecher 135

Modern Sandface Completion Practices

RESLINK 1121 Buschong Road Houston, TX 77039 USA Tel: 281-227-9854 Fax: 281-227-6834 www.reslinkus.com [email protected] Reslink specializes in sand control solutions for openhole completion of oil and gas wells. Innovation, risk minimization and thorough product qualification are essentials of Reslink’s product development and manufacturing. Based in Norway and the USA, Reslink provides technical expertise and delivers products meeting customer requirements; Simple, Robust and Reliable. Executives: CEO and President Norway President USA President Africa Executive Vice President Africa Vice President Marketing

Ole S. Kvernstuen Terje Gunneroed. Dapo Oshinusi Dr. Onuoha E. Ibe Paul B. Vorkinn

SCHLUMBERGER OILFIELD TECHNOLOGIES 5599 San Felipe, Suite 1600, Houston, TX 77056 USA Tel: 713-513-2448 Fax: 713-513-2008 www.slb.com/oilfield Schlumberger has been providing the energy industry with oilfield technology and service since 1927, the year the company introduced the then revolutionary technique of wireline logging for evaluating oil and gas wells. Today Schlumberger offers a comprehensive range of advanced technology and value creating services covering oil and gas companies’ full spectrum of needs, from pore to pipeline. Executives: Chairman and Chief Executive Officer Andrew Gould Vice President, Oilfield Technologies Satish Pai Vice President, Oilfield Marketing Rod Nelson President, Well Services Mark Corrigan Marketing Mgr, Well Services Daniel D. Domeracki President, Well Completions Zaki Selim Marketing Mgr, Well Completions Maarten Propper Service Areas and GeoMarkets: NORTH/SOUTH AMERICA Alaska 907-273-1700 Canada 403-509-4000 US Gulf Coast 504-592-5275 US Land 281-285-8500 Argentina, Bolivia, Brazil, Chile 55-21-3824-6926 Mexico, Central America 52-55-5263-3000 Peru, Colombia, Ecuado 57-1-376-50-05 Venezuela, Trinidad and Tobago 58-212-9074800 CONTINENTAL EUROPE AND AFRICA Continental Europe 39-02-5754-2208 Scandinavia 47-5194-6000 Caspian 44-207-576-6705 Russia, Sakhalin 7-095-935-8200 United Kingdom 44-1-224-385600 Algeria, Morocco, Tunisia 213-21-92-22-40 Nigeria 234-1-2612679 West and South Africa 244-2-310-357

MIDDLE EAST, ASIA AND AUSTRALIA Saudi Arabia, Kuwait, Bahrain, Pakistan 966-3-857-3440 Egypt, Syria, Sudan, Jordan 20-2-380-7780 UAE, Qatar, Yemen, Oman 9712-633-3600 India 91-11-26108354 Libya 218-21-3350060 Iran 98-21-877-2474 Australasia 61-8-9420-4800 60-3-2166-7788 Brunei, Malaysia, Philippines China, Korea, Japan, Taiwan 86-10-6474-6699 Indonesia 62-21-522-7050 Thailand, Myanmar, Bangladesh 66-2-937-0700

SMITH SERVICES A BUSINESS UNIT OF SMITH INTERNATIONAL, INC 16740 Hardy Street Houston, TX 77032 USA Tel: 281-443-3370 (800-877-6484) Fax: 281-233-5425 www.smith.com [email protected] Smith Services offers a range of drilling optimization tools, fishing services, completion and production enhancement products. Technologies such as multilateral junction systems, borehole enlargement, liner hangers and production packers are brought together to deliver improvements in wellbore construction efficiency and a reduction in the cost of reservoir exploitation. Executives: Smith Services President Completion Systems Vice President

STREN INC. 15045 Woodham Dr. Houston, TX 77073 USA Tel: 281-820-0202 Fax: 281-820-5909 www.stren.net [email protected]

Executives: President Applications Engineer

3621 Ridgelake Drive, Suite 200 Metairie, LA 70002 USA Tel: 504-833-2074 Fax: 504-833-2075 www.thrutubingsystems.com [email protected] Thru-Tubing Systems, Inc. is an engineering, manufacturing, and service company specializing in thru tubing workover, completions, and sand control systems. TTS offers a variety of thru tubing sand control and packer systems designed to be deployed on either coil tubing or wireline. TTS has developed many innovative applications designed to allow the oil and gas operator to successfully conduct thru tubing wellbore remediations using coil tubing and/or wireline. Executives: President Engineering Manager

Danny Teen Robert Picou

TUCAN PETROLEUM SERVICES, C.A. Ave. Intercomunal, El Tigre El Tigre Edo. Anzoategui 6050 Venezuela Tel: 58-283-2552064 Fax: 58-283-2550704 [email protected] Tucan is dedicated to oil field service – oil well cementing (primary and secondary), oil well stimulation services, gravel pack services, high and low pressure pumping services, wireline services, oil tool rental services (packers). Executives: General Manager

Williams Cedeno

WEATHERFORD INTERNATIONAL LTD.

Stren is an international engineering and manufacturing company serving key industries, including the petroleum production industry, from its Houston manufacturing facilities since 1988. A recognized leader in rod and ESP pumping systems optimization, Stren manufactures effective, cost efficient sand control equipment for rod, ESP pumping and well completion sand control liner with installations in most major petroleum producing basins worldwide. Kenneth J. Schmitt Stan Burton

TBC-BRINADD 4800 San Felipe Houston, TX 77056 USA Tel: 713-877-2700 Fax: 713-877-2604 www.tbc-brinadd.com [email protected] A global, wholesale distributor and manufacturer of non-damaging additives for drill-in, completion and workover fluid systems. TBC-Brinadd utilizes its ISO 9001 certification to supply value-added service to their customers. Executives: President CEO

136

Richard Werner Roger Matheson

THRU-TUBING SYSTEMS, INC.

Jay Dobson Bert Wolford

515 Post Oak Blvd., Suite 600 Houston, TX 77027 USA Tel: 281-873-6686 Fax: 281-876-1531 www.weatherford.com [email protected] Weatherford Completion Systems (WCS) provides a full range of completion products and services, including cased hole and liner systems, solid expandables, intelligent well systems and expandable and conventional screens for sand control. President, Weatherford Completion Systems Vice President, Liner Systems Vice President, Expandable Sand Screens (ESS) Vice President, Well Screens Director Sales & Marketing, Solid Expandable Tubulars Vice President, Solid Expandable Systems Technical Manager, Expandable Sand Control Senior Research Advisor U.S. Offices: ALASKA Anchorage

Stuart Ferguson Kevin Trahan Nick Gee Bill Rouse Pat York Paul Metcalfe John Cameron Tracey Ballard

907-561-1632

Directory

CALIFORNIA Bakersfield Long Beach Paramount Ventura COLORADO Denver Greeley LOUISIANA Houma Lafayette New Orleans Shreveport MISSISSIPPI Laurel NEW MEXICO Farmington Hobbs OKLAHOMA Oklahoma City Tulsa Woodward Yukon TEXAS Andrews Big Lake Bridgeport Corpus Christi Dallas Denver City Houston Levelland Longview Midland Odessa Snyder UTAH Vernal WYOMING Casper Hurricane Powell Rock Springs Outside U.S. Offices: ARGENTINA Buenos Aires AUSTRALIA Malaga BRAZIL Rio De Janeiro CANADA Calgary CHINA Beijing COLOMBIA Santafe de Bogota FRANCE Senlis INDONESIA Jakarta ITALY Ortona MALAYSIA Kuala Lumpur MEXICO Reynosa SINGAPORE UAE Dubai UK Aberdeen VENEZUELA Caracas

661-746-1391 562-426-6863 562-808-1193 805-643-1279 303-893-0287 970-339-9747 504-851-0600 337-893-0231 504-679-9700 318-221-4338 601-649-1183 505-326-5141 505-939-1717 405-773-1100 918-299-9655 580-254-3229 405-577-5590 915-523-9091 915-884-2354 940-683-2244 361-904-0300 972-702-9222 806-592-3827 281-873-6686 806-894-6653 903-759-3601 915-563-7957 307-754-7234 915-573-3376 435-789-7121 307-234-7011 304-562-5724 307-754-9554 307-362-1883

WELL FLOW INTERNATIONAL 600 Kenrick, Suite B-14 Houston, TX 77060 USA Tel: 281-448-2900 Fax: 281-448-0199 www.well-flow.com [email protected] Well Flow International manufactures specialty chemicals and engineered products used in the completion of oil and gas wells. The company’s origin was with the development of DIRT MAGNET. The company has since expanded its product line to include other varieties of surfactants, solvents, scale dissolvers, formation scale and damage removers and casing cleanup tools. Executives: President CEO

Paul Kesterton Paul Bell

WELL COMPLETION TECHNOLOGY 7903 Alamar Houston, TX 77095 USA Tel: 281-859-6464 Fax: 281-855-3004 www.wcthou.com [email protected] Founded in 1986, Well Completion Technology was created to provide well completion consulting services and related technical training to the petroleum industry. Our capabilities include: Training Management/ Coordination, Technical Training, Technical Tours, On Site Job Supervision and Project Management, Equipment Trading, Well Completion Design and Technical Consulting on all aspects of Well Construction and Production. Executive: President

William K. Ott, P. E.

54-11-5077-0000 61-8-9249-7900 55-21-2266-8900 403-279-9300 86-10-6561-9009 571-616-1130 33-344-322-402 62-21-5273050 39-085-905161 603-2168-6000 52-899-923-0145 65-778-8323 9714-3312999 44-1224-225200 58-212-265-6544

137

INDEX Abrasive wearing, 60 ABS filter cartridge, 54-55 Absolute filter, 53 Absolute rated, 53 Acid, 14, 17-18, 30, 33, 36, 47-48, 51, 59, 66-67, 73-74, 88 Acid solubility, 30 Acid soluble, 14, 18 Acid stimulation, 66 Acid treatment, 47, 66, 74 Acidizing, 3 Acidizing treatments, 3 Acid-prepack method, 73 Acids, 11, 14, 16, 48, 66 Acid-soluble, 14, 18 Acoustic collar, 9 Acoustic transducers, 9 Agglomerates, 48 Alpha wave, 35-36 Alpha-beta wave principle, 37 Alternate path screens, 39, 126 Alternate path technology, 36, 38, 94-95 Aluminum oxides, 30 Ammonium chloride, 18 Amphoteric, 46 Anionic, 46-47 Anionic surfactants, 46 Anisotropic reservoirs, 76 Anisotropy, 69 Annular blockage, 94 Annular bridge, Annular flow, 18, 70, 94 Annular pack, 20, 37-38, 40, 77, 80, 90, 110, 112 Annular pressure, 50, 64, 80 Annular ring, 20-21 Annular voids, 94 Anticipated flow rates, 2 API fluid loss data, 48 Asphaltene/paraffin deposition, 7 Available flow area, 5 Average grain size, 26, 28-29 Azimuth, 96 Back surging, 71 Backflow volume, 66 Bactericide, 57 Baffle cups, 16 Bailed sand samples, 27 Bailer, 2, 119 Base completion fluid, 103 Base fluid, 14-15, 49, 89, 103, 125 Batch mixed, 97 Batch-mixing equipment, 75 Beta coefficient, 54 Beta ratio, 53-54 Beta wave, 35-37 Beta-rated cartridge, 54 Bicarbonate, 45 Biocide, 45, 49 Biopolymer, 48

Biot's poroelastic coefficient, 86 Blast joints, 10 Blender, 104 Blending equipment, 74, 103, 107, 125 Borehole stability, 12, 27 Bow-spring centralizer, 31-32, 119 Braden-head squeeze, 73 Brake horsepower, 104-105 Breakable polymers, 14 Breaker soak, 17 Breakers, 17, 38, 48-49, 88, 125 Breaking fluid, 14 Bridge matrix permeability, 52 Bridging agent, 14, 49 Bridging material, 11, 14, 66 Bridging particle, 13 Bridging pill, 16 Bridging salt, 17 Bridging theory, 20 Brine, 13-14, 16-17, 30- 33, 35-36, 43-51, 55, 66, 74-75, 77-78, 86, 97 Brine carrier fluid, 74 Brine completion fluid, 13 Brinnell hardness of the rock, 3 Bromide brines, 18, 44 Bubble point method, 55 Buffer fluid, 65 Bulk density, 87, 110 Bypass valve, 79-80 Calcium brine, 45, Calcium carbonate, 66-67 Calcium chloride, 18, 46 Calcium sulfate, 45 Caliper log, 32 Capillary pressure, 1, 51 CAPS, 38, 40, 64, 95 Capsule guns, 60, 63-65 CarboLite, 30, 127 Carbonate, 13, 45, 66-67, 114 Carrier guns, 60, 63-64 Cartridge filters, 52-56 Cased-hole frac packing technique, 35 Cased-hole gravel pack, 71-72, 76-77 Casing collar locator, 79 Casing scraper, 53 Catastrophic sand production, 68 Cationic, 46-47 Cellulose--polymer-specific enzymes, 48 Cement filtrate, 11 Cementation, 1-2, 4, 6, 66, 113 Cementing, 5, 10, 17, 24, 48, 103, 112, 131 Cesium formates, 44 Channeling, 10, 16-17, 54 Charge performance, 59, 62, 69 Charge type, 59 Chemical additives, 103 Chemical buffers, 88 Chemical consolidation, 6-7, 113-114 Chemical degradation, 48 Chemical soak, 17

Choke effect, 126 Circulating fluid, 2 Clay content, 2, 60 Clay stabilization, 26 Closing sleeve, 16, 36 Closure stress, 87, 89, 90, 91-92, 106, 128 Coberly equation, 52 Coil tubing, 24, 33, 115-117, 134 Coiled tubing, 2, 17, 36, 61, 63, 109, 113, 115-118, 120-21, 126 Completion fluid, 7, 11, 13, 43-46, 49-56, 61, 73-74, 96, 102, 118 Compressible fluid, 83 Compressive strength, 2-4, 7, 66, 69, 93 Conditioning fluid, 114 Conductive tunnels, 59 Connate water, 3 Contamination, 36, 45, 50-51, 58 Conventional core analysis, 27 Conventional core barrels, 26 Conveyance method, 56, 61, 63, 65, 109 Core, 3-4, 26-27, 29 Core flow, 29 Coring, 26 Correction algorithms, 49 Corrosion inhibitor, 47 Creep, 87 Critical zone, 87 Crosslinked fracturing fluids, 88 Crosslinked gels, 77 Crosslinked pill, 17 Crosslinked polymer gels, 97 Crosslinkers, 88 Crossover assembly port, 16 Crossover circulation technique, 33 Crossover method, 31 Crossover tool, 31-32, 36, 40, 114-115 Crushed zone, 60-61, 65, 76 Crystallization curve, 46 Crystallization points, 44-46 Crystallization temperature, Cup-type service packer, 31 Damaged zone, 6, 13, 70, 73-74, 76, 82-83 Darcy flow, 109, 127, 131 Darcy skin factor, 70 Darcy's Law, 5, 47, 74-75 DE filter cycle, 50 DE filter unit, 54 DE presses, 56 Debris, 11, 31, 43, 53, 60, 64 Delayed crosslink agents, 88 Demulsifiers, 88 Density, 4, 9, 13-14, 16-18, 25, 27, 31-32, 43-45, 50, 58, 60-61, 64, 71, 75-76, 87, 90, 96 Density log, 109-110 Depth verification tool, 118 Design/analysis software, 107 Determination of particle size distribution, 57-58 139

Modern Sandface Completion Practices

Determining slot width, 70 Detonating cord, 59-60, 64 Detonation methods, 59, 64 Deviated holes, 11 Deviated wellbores, 59 Deviatoric stress, 67 Diatomaceous earth, 52, 54-55 Diatomaceous earth filters, 55 Diatoms, 54-55 DIF, 12-14, 18, 23-24, 33, 36, 122 Dilatant sand formation, 12 Dilation of the formation rock, 8 Dimensionless skin factor, 7 Dipole sonic log, 86 Directional wells, 33 Dirty fluid, 21, 56-57 Displacement, 11-12, 15-18 Double-tube core barrels, 26 Downhole erosion, 10 Downhole exclusion device, 23 Downhole filter, 21, 24, 42 Downhole sand monitoring systems, 9 Downstream sand injection, 33 Drag forces, 3, 9, 65, 75 Drainage radius, 5-7, 76, 83 Drawdown, 3-6, 9-10, 14, 67-68, 72, 75-76, 83-84, 125 Drill-in fluids, 10, 13-14 Drilling fluid, 14-16, 21 Drilling mud, 7, 27, 43-45, 49-51, 53 Dual-detector density tools, 110 Dual-screen prepack, 21 Dynamic leakoff profile, 93 Eccentric annulus, 16-17 Efficiency ratio, 105 Elastomers, 44 Electric submersible pump, 40 Embedment, 40, 86-88, 90, 92 Emulsifying, 44 Emulsion, 46 Enhance radial flow entry, 67 Enzyme, 14, 16, 89 Epoxy resin, 96 Erosion, 2, 8-11, 16-21, 23-24, 30, 38, 60, 70, 74, 87, 90, 94 Erosion monitoring, 8 Ester, 49 Evaluation simulator, 107 Expandable sand screen design, 24 Expandable screens, 7-8, 16, 112, 126 Expendable guns, 61 Exploiting bypassed payzone, 126 Extended production test, 3 Extreme overbalanced, 64 Extruded pipe dope, 49 Field evaluation, 77 Field-scale testing, 35

140

Filter, 13-18, 20, 22, 24, 31, 36, 38-40, 42, 45, 49, 51-52, 53-58, 89, 96, 122, 124-126 Filter cake, 14-17, 31, 36, 38, 40, 49, 55, 125 Filtrate, 56 Filtration, 129, 133 Filtration guidelines, 51 Filtration polymers, 16 Fine migration, 5, 7, 39, 60, 74, 81, 83, 85, 90 Fines, 2-3, 5, 7, 18-20, 25, 30, 39, 42, 60, 66, 68, 70, 74, 81, 83, 85, 90 Finite element analysis, 5 Firing pin, 64 Fish eyes, 15, 48 Flow back testing, 14 Flow convergence, 19 Flow efficiency, 5, 7, 64 Flow erosion, 74 Fluid density, 16, 44-45, 77, 91, 96, 110 Fluid displacement, 16, 49 Fluid filtration, 14, 24, 26, 40, 43, 51 Fluid flow, 2-3, 5, 14, 16, 57, 79, 94 Fluid invasion, 14, 61, 64 Fluid leakoff, 89, 95, 107, 131 Fluid loss, 13-15, 17, 25, 33, 36, 43-45, 47-49, 68, 72-73, 78, 80, 91, 93-94 Fluid loss coefficient, 93, 107 Fluid loss control, 15, 33, 47, 49 Fluid saturation, 27 Fluid spurt loss, 93 Fluid velocity, 36, 83, 91 Fluid viscosity, 2-3, 74, 76-77, 86, 88-91, 120 Fluid volume, 65, 74 Fluid/fluid compatibility, 45, 125 Fluid/formation compatibility, 13-14, 45, 103 Fluid/slurry densities, 17 Fluid loss, 13-15, 17, 25, 33, 36, 38, 43-47, 68, 72, 78, 88, 91-94 Foam treatments, 107 Formates, 13, 44 Formation compaction, 7 Formation consolidation, 2 Formation cores, 27 Formation damage, 5,7, 11-12, 14, 17, 25, 33-48, 51, 59, 61, 68-79, 76, 81-83, 87, 89, 98-100 Formation erosion, 16 Formation grain size, 19, 28 Formation sand sampling, 18, 26 Formation sand size distribution, 18 Formation skin damage, 33 Formation stress, 5, 86, 89 Frac fluid, 93 Frac packing, 10, 30, 38-39, 43, 61, 66, 75, 81-85, 87-90, 92-94, 97, 104, 113, 125 Frac pressure, 36, 72-73, 77, 80, 85 Frac pack, 7, 40, 42, 73-74, 81-87, 89, 91-94, 97, 105, 109, 108-113, 117-118

Frac-pack technique, 39, 96 Fracture closure stress, 89, 107 Fracture, 8, 24, 38-40, 59-61, 64, 66-69, 72-74, 78, 81-83, 85-96 Friable, 26, 32, 86 Full-closure core catcher system, 26 Full-hole-volume of completion fluid, 50 Full-scale frac pack, 73 Functional tendencies of surfactants, 46 Furan resin, 96 Gamma ray spectra, 111 Gamma-ray depth correlation tool, 79 Gas aphrons, 14 Gas propellant fracturing, 81 Gas-liquid ratio, 70 Gel pills, 47 Gel strengths, 17 Gel system, 86, 89, 102 Gelled fluids, 17, 30, 75, 78, 88 Gelled slurry-pack fluids, 78 Geochemical bonding, 114 Geomechanical numerical models, 5 Glass beads, 30 Grain density, 27 Grain size distribution, 26-27 Grain-to-grain Bonding, 113 Gravel bridges, 31, 95 Gravel pack, 1-2, 10-12, 20, 24, 26, 29-31, 33-43, 51, 66, 68, 71-73, 75-77, 79, 82-85, 92-94, 96-97, 103, 109-111, 113-119, 122-124, 126 Gravel pack evaluation techniques, 77, 109 Gravel packing, 1, 7-8, 10-11, 16, 19, 21, 24-25, 30, 33-36, 38-39, 43, 45, 51, 53, 61, 66-68, 71-72, 74, 78-79, 85, 87-90, 93-95, 103, 110, 113, 118, 125, 131 Gravel placement, 25, 31-36, 38, 66, 68, 72-75, 77, 79, 107, 110, 117 Gravel size determination, 28 Gravel slurry, 30, 36, 78, 96, 116, 119 Gravel-pack screen, 79 Gravel-packing method selection, 97 Gravimetric analysis, 53, 57-58 Gun clearance/centralization, 63 Gun design, 59, 61, 63 Gun orientation, 9 Gun size, 59, 61 Halide brines, 44 HCI acid, 48-49 Heavier weight completion fluids, 47 HEC, 14, 17, 33, 47-49, 73-74, 76-77, 88, 119 HEC slurry pack, 76 Hexagonal packing, 120 High rate water packing, 31, 69, 97 High shear rate, 48 High shot density, 9, 61, 69 High-angle wells, 14, 26, 63 High-flow capacity, 21

Index

High-pressure frac pumps, 103 High-pressure pumps, 105 High-shot density, 96 High-viscosity high-density gravel slurry, 31 High-viscosity high-density slurry, 25 High-volume mixing equipment, 115 Hole spacing, 67 Hole stability, 24, 33 Hook hanger system, 120 Horizontal AllPAC screens, 38 Horizontal gravel pack, 35-37 Horizontal gravel-packing, 34, 120 Horizontal holes, 11 Horizontal open-hole, 22, 24, 37, 121 Horizontal stress, 67, 86-86, 93-94 Horizontal wells, 13-14, 20-21, 24, 34-35, 37-38, 63, 67, 85 Horizontal/deviated wells, 24, 38, 76, 96 Horizontal/multilateral wells, 125 Horsepower rating, 104 Hot spot, 18 Hot/alkaline/steam sand-consolidation technique, 114 HPG, 48, 88 Hydrates, 46, 48 Hydraulic fracture, 59-60, 67, 83, 85, 88, 93, Hydraulic fracturing, 38, 67, 85, 88, 107, 113, 125-126 Hydraulic horsepower, 50, 86, 88, 103-104 Hydraulic jets, 59 Hydraulic setting tool, 79 Hydraulic shear, 14, 55 Hydraulic shearing device, 15 Hydraulic workover unit, 113 Hydraulic-fracture stimulation, 61 Hydrochloric acid, 66 Hydrofluoric acid, 66 Hydrostatic, 66 Hydrostatic balance, 44 Hydrostatic pressure, 14, 17, 40, 44, 47 Hydroxy-ethylcelluse, 77 Hydroxypropyl guar, 48, 88 Impairment, 6, 11, 34-35, 66, 71 In situ sand consolidation,10 Induced damage, 59, 61 Inertial flow coefficient, 90 Inflatable packers, 32 Inflow area, 8, 19-20, 23-24 Inflow control devices, 21 Inflow damage, 60 Inflow performance, 24, 59-60 Influx, 7-8, 39, 44, 65-66, 70-71, 77, 90, 109 Injection rates, 78, 94, 107 Injectivity, 59-60, 66, 95, 114 In-line sand cyclone, 9 Inside-casing gravel packing, 8 Interface, 11, 18, 25, 50, 53, 76, 107, 127 Interfacial tension, 46, 50

Intergranular friction, 1 Intermediate strength proppants, 89-91 Internal gravel packs, 68, 71 Intervals, 4, 8-9, 17, 25-26, 31, 38-39, 63-66, 69, 71, 74, 79, 84, 86, 88, 93-96, 109-110, 113-114, 126 Invert emulsion mud, 46 Iridium, 110-111 Iron sulfide scale, 45 Isolation plug, 36 Isopropanol, 48 Jet perforating, 59 Kerosene, 48 Kozeny's method, 52 Laboratory core analysis, 4 Laboratory core test scatter, 48 Laboratory-measured beta factors, 109 Laminar, 49, 74-75, 91 Laminated sand, 12, 39, 85-86 Laser-optics, 27 Laser particle size analysis, 118 Log/log plot, 107 Lost circulation material, 68 Low filtrate, 14 Low fracture gradient, 24 Low gravel permeability, 29 Matrix, 2-3, 14, 23, 44, 46, 52, 61, 113, 131 Median grain size, 26, 29 Memory-based tools, 109 Mercury injection, 51 Mesh gravel, 30, 73 Metal liners, 20, 59, 60 Metal mesh, 23, 56 Mfrac, 107 Micro-bubbles, 14 Micro-emulsified oil, 51 Microgels, 48 Micron membrane, 58 Milling, 43 Mineralogy screening, 27 Minifrac, 91-92, 107 Mini-frac test, 93 Minifracture, 91-92 Minimum horizontal stress, 67 Mix ratio/rate plot, 104 Mixing flow rate, 104 Monitoring and control equipment, 106 Monitoring systems, 9, 105 Monobore completion, 113 Mud cake, 25-26, 34, 50, 53 Mud filtrates, 11 Multi-cartridge filter housing, 54-55 Multilateral completion, 23 Multiphase flow, 5, 91 Multiple zone completion, 25 Multi-position service tool, 79-80

NaCl, 13-17, 44 Nephelometric turbidity units, 57 Neutron logs, 4 Nominal filters, 53 Nominal median pore size, 55 Non-Darcy, 39-40, 76, 86, 90-91, 109, 127, 131 Nonionic, 46 Non-penetrating fluid, 66 Nuclear density log, 109 Oil-based mud, 13, 49 Oil-soluble resin, 66 Oil wetting, 46 One trip tool, 32 One-trip perforate and pack system, 79, 81 One-trip TCP gun, 118 Open-channel flow, 20 Open-hole gravel packing, 8, 24, 31-32, 35, 38, 103 Open-hole horizontal completions, 21 Optimal gravel placement, 68 Optimal screen wire spacing, 21 Optimum sand control, 29 Oriented hydrajetting, 68 Oriented perforating, 8-10, 67, 126 OSU (Oklahoma State University) F-2 standard, 54 Overbalanced, 43, 47, 63-65, 66-69 Overbalanced pressure, 47, 66 Over-the-top system, 31 Over-the-top tool assembly, 31 Oxidizer, 14, 17 Oxidizing agents, 48 Oxidizing breakers, 89 Pack damage, 31, 88 Pack factor, 74, 78 Pack-assembly placement, 109 Packer/crossover tool assembly, 31 Pack-off method, 114-115 Pack-off seal assembly, 114 Pad, 39, 74-75 Paddle tank, 75 Paraffin, 7, 51 Particle contamination, 58 Particle count, 52-54, 58 Particle distribution, 13-14, 17 Particle invasion, 49, 51 Particle removal efficiency, 55 Particle removal efficiency testing, 52 Particle size, 13, 15-16, 24, 50-54, 57-59, 90, 92, 122, 124 Particle size distribution, 53-54, 58 Particle-size analysis, 27 Particulate impairment, 51 Perforated intervals, 61, 93, 110 Perforating, 8-11, 43, 48-49, 53, 59-61, 64-73, 80, 87, 96, 103, 117, 119, 126 Perforating analysis software program, 69 141

Modern Sandface Completion Practices

Perforating charges, 59 Perforating damage, 7, 60 Perforating debris, 11, 64-65 Perforating for sand prevention, 7 Perforating gun systems, 60 Perforating to control sand production, 66 Perforation efficiency, 76 Perforation orientation, 9, 61 Perforation prepacking, 72, 85 Perforation skin, 61, 96 Perforation tool orientation, 8 Perforation tunnel, 1-2, 11, 24, 45, 51-52, 59-60, 64, 66, 68, 70-73, 77-78, 80, 85, 94, 96, 114, 118 Perforation wash tool, 52, 66 Perforation washing, 43, 66, 71 Perforation/cleanout methods, 71 Permanent completion perforation, 63, 68 Permeability, 2-3, 5-10, 12-14, 17, 23-27, 29-30, 34, 38-40, 43, 45, 47-48, 51-52, 59-61, 64-66, 69, 71-72, 74, 76-77, 82-96, 113-114 Permeability impairment, 6, 71 Permeability profile, 93 Permeability recovery, 8 Permeability reduction, 6-8, 14, 48, 51, 74-75, 114 Permeable formation, 14 Phasing, 9, 58, 61, 67, 69, 76 Phasing perforation, 67 Phenolic resin, 96 Pickle pipe, 93 Pill material, 16 Pipe base, 20-21, 23 Pipe dope, 49, 51 Pipe rams, 50 Pipe-based screens, 21 Pipe-wall cleaning, 50 Plastic treatments, 114 Plastic viscosity, 49 Pleated absolute cartridge, 54 Pleated cylinders, 54 Plugged slot, 20 Plugging, 2, 5, 7-8, 14-15, 18-21, 24, 26, 29, 30, 32, 42, 44-45, 52-53, 68, 70 Plugging ratio, 20 Poisson's ratio, 86, 93 Polymer, 12-18, 25, 35, 44, 47-49, 51, 55-56, 74-75, 77, 88-89, 99, 103, 119, 125-126 Polymer fluid system, 17 Pore fluid compressibility, 61 Pore openings, 14, 23 Pore pressure, 2-3, 87, 93 Pore space, 5, 23, 39, 51, 113 Pore throat, 5, 20, 39, 49, 51-52, 58, 70 Pore throat bridge, 52 Pore throat plugging, 20 Porosity, 4, 24, 27, 52, 61, 69, 74, 109-110, 114 Porosity log, 109 Porous cake, 56 142

Porous metal fiber, 23 Port collars, 31-32 Positive tool positioning, 31 Post-completion isolation, 16 Post-treatment analysis, 109 Post-treatment flowback, 89 Potassium chloride, 15 Potassium formate, 13 Practical solids loading, 57 Preblender, 103 Precipitates, 20, 43, 45, 114 Precipitation of calcium fluoride, 67 Precipitation of sodium fluosilicates, 67 Pre-frac preparation, 69 Pre-fracturing stage, 68 Premature annulus bridges, 38 Premature bridge, 40 Premature sand production, 109 Premature screenout, 74, 77, 95 Pre-milled window system, 120 Premium screens, 14, 19-21, 34, 70-71, 85, 121 Prepacked screens, 20-21, 30, 34, 70-71, 96 Pressure calculations, 50, 76 Pressure decline analysis, 87, 90, 92, 94, 107 Pressure differential, 3, 47, 61, 64-65 Pressure drawdown, 3-5, 67 Pressure drop, 2, 5-7, 11, 19, 29, 32-33, 40, 54, 56, 59, 61, 68, 72-73, 76-77, 83, 86, 91, 94 Pressure leaf, 56 Pressure-activated firing head, 65, 68, 79 Pressure-depleted formation, 43 Pressure-transient method, 126 Pretreatment, 74, 89, 91-92 Primary fracture, 96 Producing interval, 2, 65 Producing rate, 70 Producing water cut, 1 Production packer, 31-32, 79, 117-118 Production screen, 12-15, 79 Productivity index, 6-7, 75, 82 Propagation, 88, 91-93, 107 Propellant sleeve, 69 Propellant/perforating technique, 69 Propellant-assisted perforating , 69 Propellants, 69 Proper size gravel, 26, 28 Proppant, 8, 38-40, 42, 59-60, 67, 69, 74, 81-82, 85-97, 103-105, 107-108, 110-111, 115-116, 118, 124, 126, 128 Proppant conductivity, 90-91 Proppant control, 92 Proppant embedment, 86-87, 90, 92 Proppant flowback, 67, 92, 126 Proppant particle size, 90 Proppant screenout, 67 Proppant selection, 89-91 Proppant sizing, 90 Proppant stages, 74 Proppant transport characteristics, 88

Proppant transport solution, 107 Proppant-laden gels, 59 Propped fracture, 39-40, 81-82, 84-87, 89-90, 93, 95, 111, 126 Propped fracturing, 8, 10 Propping agent, 89 Pseudo-3D gravel placement, 107 Pump rate, 10, 18, 30, 35, 39, 50, 73-77, 84, 104 Pumping practices, 85 Radial flow, 5, 47, 67-68, 75, 76 Radial flow geometry, 5 Radioactive marker, 79, 112 Radioactive tracer material, 110 Radioactive tracers, 91, 110 Ramp mode, 104 Rate exclusion, 9 Rathole, 71, 118 Recessed plate press, 55-56 Remedial operations, 2, 109 Removal of formation damage, 33, 83 Reservoir compaction, 7 Reservoir connectivity, 59 Resin, 8, 10, 15, 21, 27, 30, 36, 66-67, 89, 92-93, 96-97, 113-114, 126 Restricted flow, 29 Retrievable packer, 36 Reverse circulation, 31, 50, 53 Reverse-pressure, 64 Rheology, 12, 16, 49, 107 Rigless completion, 125-126 Rigless intervention, 63 Rigless sand control completions, 114 Risk assessment, 8 Robust zonal isolation schemes, 126 Rock failure, 3-4 Rock mechanics, 85-86, 126 Rock strength, 2, 59, 64, 93 Rod-based screens, 21 Rod-based, wire-wrapped screen, 21 Rotary vibration system, 118, 120 Salinity, 11, 16-17, 45, 66 Salt crystals, 13 Sand arch, 3 Sand bridge, 20, 39 Sand detector technology, 9 Sand disposal, 10 Sand embedment, 86 Sand erosion, 8, 10 Sand exclusion, 7, 14-16, 18-21, 23-24, 30, 39, 70, 81 Sand exclusion device, 14-16, 18-21, 23-24, 30, 39, 70 Sand exclusion philosophy, 7 Sand exclusion techniques, 16, 24 Sand failure, 24, 67 Sand fill cleanout, 43 Sand filling the annulus, 25 Sand grain impacts, 9

Index

Sand grains, 2-3, 9, 14, 17, 25, 27, 28, 51, 70, 90, 113-114 Sand influx, 7-8, 39, 67, 70-71, 77, 90 Sand injector, 33, 73 Sand life cycle, 8 Sand management, 7-9 Sand packing, 10 Sand particles, 10, 20, 23, 48, 51, 117 Sand placement, 11, 69, 74 Sand prediction analysis, 7 Sand production, 1-11, 21, 24, 38-39, 58, 61, 67-69, 73-75, 84, 90, 96, 109, 114, 125-126, 131 Sand retention characteristics, 23 Sand screens, 20, 123 Sand size distribution plot, 28, 68 Sand size optimization, 28 Sand transport, 8 Sand traps, 8 Sand-cut, 9, 122 Sanding risk, 8-9 Sand-management completions, 69 Saucier rule, 90 Saucier's technique, 29 Scale inhibitor, 45 Scale precipitation, 7-8, 13, 76 Scale problems, 83 Scandium, 108-109 Scope of filtration, 52 Screen characteristics, 19 Screen cleaning, 16 Screen deployment, 117-119 Screen design, 21, 23-24, 30, 38, 73, 126 Screen erosion, 8, 24, 70, 74 Screen failure, 18, 94 Screen opening size, 19 Screen out, 67 Screen plugging, 18, 24, 30, 32 Screen standoff, 16 Screen wire-spacing design, 21 Screenless completions, 67 Screenless frac packing, 30 Screenless gravel packs, 68-69 Screenless single-trip multizone, 97 Screenout, 6, 38, 67, 69, 74-75, 77, 81, 84, 87-90, 92-93, 95-96, 109, 115-116, 126 Screenout pressure, 74, 116 Screens, 7, 8, 10, 14, 16, 18-21, 23-24, 38, 30-31, 34, 36-40, 68, 70-72, 81, 85, 92-96, 113, 121, 123-124, 126 Secondary payzone, 113 Secondary placement, 35 Selective and oriented perforating, 10 Selective perforating, 8-9, 67 Selective perforating practices, 9 Selective perforating techniques, 67 Set-down service tool, 94 Shaped charges, 59-61, 64 Shaped-charge design, 59, 61 Shear force, 3 Shear rate, 17, 48, 88-89

Sheared microgels, 48 Sheared polymer, 15 Shielded gamma detector, 109 Shot density, 9 59, 61, 69, 76, 94 Shots per foot (SPF), 63 Shunt tubes, 37-38, 40, 94 Shunt-tube screen, 94-95 Sidewall cores, 26-27 Sieve analysis, 18, 23, 27-29, 70 Silica cements, 114 Silica material, 30 Silt, 18, 27, 52, 70 Single salt brines, 46 Single-screen prepack, 21 Single-shot perforate, 65 Single-trip gravel packing, 65, 68 Single-trip perforating, 67-68 Single-trip sand control method, 68 Sintered bauxite, 30, 89-91, 116 Sintered metal mesh layers, 22 Sintered metal powder, 23 Sintered-laminates screen, 23 Situ stress field, 9 Sized bridging solids, 17 Skid-mounted equipment, 101 Skin effect, 76, 96 Skin factor, 6-7, 70, 74, 82 Slickline perforating, 61 Slot factor comparison, 19 Slot induced flow convergence, 19 Slot plugging, 20 Slot rows, 19 Slot width, 15, 18-21, 28, 70, 72 Slotted liners, 8, 14, 16, 18-21, 30, 34, 70, 72, 121 Sloughing, 13, 25, 32, 40, 117 Slurry, 11, 17, 25, 31-32, 34, 38, 55-56, 73-75, 77-78, 92-97, 104, 115-117, 126 Slurry pack, 25, 73-75, 77-78, 97, 104 Slurry skid, 56 Slurry skid manifold, 56 Slurry-pack technique, 32 Snubbing units, 61 Soak solution, 17-18 Sodium bromide brines, 18 Sodium chloride, 17-18, 67 Sodium formate, 44 Solids invasion, 6, 14, 45 Solids-free brines, 42, 44 Solids-free pills, 17 Solids-laden fluid (mud), 43 Soluble bridging material, 66 Soluble bridging solids, 16 Solvent treatment, 26 Solvent wash, 49 Sonic log, 4, 86 Sorting coefficient, 18 Sorting factor, 23, 29 Spacer fluids, 11 Spacer pill, 50 Special core analysis, 27

Special filters, 8 Special perforating techniques, 59, 65 Spectral core gamma, 27 Spectral gamma ray data, 111 Spectral gamma ray logs, 109-111 Spiral phasing, 66 Square drainage area, 83 Squeeze configuration, 94 Squeezed perforations, 50 Squeeze-packing techniques, 71 Stabilizing the formation sand, 35 Stable arch concept, 1 Stable filter cakes, 13, 17, 38 Stable pack, 53 Stable tunnels, 67 Stable wellbore, 36 Stacked frac-packing assembly, 94 Stainless steel lattice screen, 23 Stair-step mode, 104 Stand-alone completion, 15, 18, 21, 24-25, 42 Stand-alone completion assemblies, 24 Stand-alone liners, 24 Stand-alone screen, 13, 18-21, 37, 39, 70, 85, 103, 122, 126 Standard crossover circulation tool system, 33 Standard displacement, 50 Static bottomhole pressure, 40 Steam consolidation, 113-114 Steam flood techniques, 3 Steam injection, 26 Steel-wing centralizer, 32 Step rate test, 74, 93, 107 Stimulation design, 81, 91 Stimulation treatments, 7, 27, 97, 125 Stimulation vessel, 84, 103, 105-106 Stratification, 93 Sulfate, 45 Sulfate-reducers, 45 Sump packer, 79 Surface density, 44-45 Surface density completion fluid, 45 Surface equipment, 1-2, 50, 74, 103, 105 Surface filtration systems, 66 Surface modifier agents, 92 Surface pressure-control equipment, 64 Surface sand deposition, 8 Surface schematics, 106 Surface tension forces, 3 Surface-modification agent, 74 Surfactant spacer, 49-50 Surfactant sweep, 50 Surfactants, 13, 46-47, 51 Surge, 40, 61, 64-65, 69, 96 Surge flow, 61, 65 Surging, 23, 31, 71, 83, 87 Suspended solids, 15, 49-50, 54, 57-58 Swab pressure, 40 Swabbing, 31, 66, 94 Swabbing effect, 94 143

Modern Sandface Completion Practices

Swelling clay, 7 Synthetic oil-based DIF, 38 Synthetic oil-based mud, 13, 49 Tagged, 109, 111, 116 Tagging proppant, 91 Tangential forces, 17 Tell-tale screen, 31-32, 36, 75-76, 79 Terminal pressure drop, 54 Test particles, 54 Theoretical flow rate, 7 Theoretical modeling, 8 Theoretical productivity, 24, 25 Theoretical volume, 75 Thermal neutron log, 110 Thermal stability, 48 Thief zone, 24-25, 33 Three-dimensional fracture geometry, 107 Thru-tubing bridge plug, 118-119 Thru-tubing circulating gravel pack, 117 Thru-tubing completion, 113 Thru-tubing, wireline gravel pack, 119 Tight filter cake, 38 Tip screenout, 67, 81, 87-90, 92, 93 Tortuosity of the flow path, 90 Tracer logs, 110-111 Transient surge, 65 Transient, finite sand production, 68 Treating fluids, 11, 43 True crystallation temperature, Tubing, 2, 10, 16-17, 21, 23-24, 31, 33, 36, 49, 51, 59, 61, 63-67, 73, 79-80, 84, 88, 93-94, 109, 112, 114-121, 123, 126 Tubing conveyed perforating gun, 78 Tubing guns, 61, 65 Tubing straddle, 117 Tubing-conveyed perforating, 61, 63 Turbidimeter, 58 Turbidity, 57 Turbidity testing, 58 Turbulent flow, 10, 16, 50, 82, 87, 89 Turbulent non-Darcy skin, 76, 86 Two-phase flow, 5 Two-stage frac-pack technique, 96 Unconsolidated core analysis, 27 Unconsolidated formation, 27 Unconsolidated formation samples, 27 Unconsolidated rock, 1 Unconsolidated sands, 1, 10, 27, 63, 66, 69 Underbalance pressure differential, 65 Underbalance/surge process, 69 Underbalanced perforating, 63-66, 68, 71, 79, 83, 87 Underbalanced perforating guidelines, 65 Underflushed, 96 Underlying drainage, 23 Underream, 25, 31-33, 76-77, 82-83 Underreamed hole, 32 Underreaming, 25, 33, 76-77, 82 Uniformity coefficient, 18, 23, 29 144

Velocity of the reservoir fluid, 3 Vent-screen cap, 119 Vent-screen method, 114-115 Vertical fracture, 86, 94-95 Vertical leaf pressure filter, 55-56 Vertical open-hole well, 32, 38 Vertical wells, 31 VES fluid, 89, 126 VibraPak rotary vibration system, 118 Viscoelastic polymer-free fracturing fluid, 88 Viscoelastic surfactant, 88 Viscosifier, 17 Viscosity, 2-7, 16-17, 25, 30-34, 47-49, 53-54, 73-78, 82, 85-86, 88-89, 91-92, 103, 106, 120 Viscous polymer gels, 47, 49 Viscous transport fluid, 75 Volumetric methods, 8 Volumetric response, 44 Wash solution, 17-18 Wash tool, 16, 33, 36, 52, 66 Wash-down method, 114-116 Wash-down technique, 96 Washing perforations, 53, 83, 87 Washing the pack, 33 Washouts, 11 Washpipe conveyance, 109 Washpipe screen, 37 Water packing, 29, 69, 74, 97 Water packs, 74, 77, 97 Water soluble, 14, 48-49 Water-based completion fluids, 45 Water-bearing zones, 88 Water-soluble additives, 33 Water-soluble salts, 43-44 Water-wet fines, 5 Wedging of out-of-size gravel, 30 Well geometry, 116 Wellbore animation, 106 Wellbore cleanout, 93 Wellbore clean-up tool, 69 Wellbore flow restrictions, 6 Wellbore geometry, 17 Wellbore-stability calculations, 125 Wellhead isolation tool/treesaver, 118 Well-log interpretation, 126 Well-test pressure analysis, 126 Wetting phase, 5 Wire spacing, 20-21, 23, 30, 70, 78 Wire-wrapped screens, 7, 16, 18-21, 34 Wireline, 4, 59, 61, 63-67, 69, 79, 107, 109-110, 116-119 Wireline gravity bailers, 119 Wireline-logging, 4 Wireline orienting tools, 67 Wireline plugback, 119 Wireline setting tool, 79 Wireline-conveyed guns, 65 Wire-wrapped screens, 7, 16, 18-21, 34

Workover fluids, 10, 43, 47 Workover strategies, 125 Xanthan gums, 48 Xanvis, 14, 48 XC gel, 48-49 XC polymer, 48 Yield point, 50 Yield stress, 17, 38 Young's modulus, 86 Zonal isolation, 8, 24, 74, 95, 111, 115, 125-126 Zone spacing, 125

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