Downhole Testing Services

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Downhole Testing Services

© Schlumberger 2000 Schlumberger 225 Schlumberger Drive Sugar Land, Texas 77478 All rights reserved. No part of this book may be reproduced, stored in a retrieval system, or transcribed in any form or by any means, electronic or mechanical, including photocopying and recording, without prior written permission of the publisher SMP-7086-2 An asterisk (*) is used throughout this document to denote a mark of Schlumberger. Aflas® is a registered trademark of Asahi Glass Co., Ltd. Lee Jeva® is a registered trademark of Lee Company. Viton® is a registered trademark of DuPont Dow Elastomers L.L.C.

Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Schlumberger Reservoir Completions Center . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Flopetrol Johnston–Schlumberger downhole tools history . . . . . . . . . . . . . . . . . . . . . . . . . . . Seal Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Downhole environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Recommended elastomer compounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Typical Downhole Test String Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Packers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FlexPac system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FlexPac packer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FlexPac hold-down tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PosiTest packer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-stroke PosiTest packer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Compression-set PosiTest packer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Positrieve packer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IRIS Pulse-Operated Test System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Benefits of the IRIS system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Flexible command system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IRIS dual-valve tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure Controlled Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PCT valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hold-open module . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PORT Pressure Operated Reference Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Formation Protector Module . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hydrostatic reference tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Single-shot hydrostatic overpressure reverse valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Single-shot hydrostatic overpressure reverse valve (internal/external) . . . . . . . . . . . . . . . Multiple-opening, internally operated reversing valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Multicycle circulating valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Multicycle circulating valve with lock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pump-through flapper safety valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tubing fill/test valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tubing test valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Single-ball safety valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pipe tester valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pump-through safety valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Slip joint . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Slip joint and TCP gun correlation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depth control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Jar tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Safety joint . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dual-Action Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fullbore Annular Sample Chamber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . DST String Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10k IRIS string with DataLatch recorder and TCP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Downhole Testing Services

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Contents

1 1 3 7 7 8 11 13 13 14 16 18 20 22 23 25 25 25 29 31 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 66 69 71 72 74 77 77

iii

10k IRIS string for shoot and pull . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IRIS big-bore string . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10k PCT string with DataLatch recorder and TCP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15k PCT HPHT string with TCP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.5k Extreme HPHT string with single-shot tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.5k Ultra HPHT string . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15k slimhole PCT string with TCP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tapered string . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10k PERFPAC string . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

iv

79 80 82 84 86 87 88 88 90

Introduction

This second book in the Schlumberger Testing Services set describes the wide variety of downhole test tools and techniques used for drillstem testing, production testing and completion operations. It is designed to help the user select the correct equipment based upon the objectives and the operating environment. Development of downhole test tools is now centered at the Schlumberger Reservoir Completions Center (SRC), which is described in the following section.

Schlumberger Reservoir Completions Center The Schlumberger Reservoir Completions (SRC) Center at Rosharon, Texas, USA, provides the petroleum industry with perforating, downhole well testing and completion products that meet the growing demand for better well productivity, operating efficiency and safety (Fig. 1). Located 30 miles south of Houston, SRC integrates engineering and manufacturing activities for essentially all Schlumberger perforating and downhole testing and subsea equipment. The 500-acre site is home to over 300 people, who are dedicated to developing high-quality, cost effective technology. Schlumberger has a long tradition of involving clients in its research and engineering activities. At SRC this commitment to continuous improvement is demonstrated by many rapid-response projects supported by teams of experienced, knowledgeable engineers. On any given day, clients from all over the world are on site, participating in formal and informal exchanges with SRC scientists and engineers. SRC encourages reciprocal visits to the center, in support of joint research.

Figure 1. Schlumberger Reservoir Completions Center at Rosharon, Texas, USA.

Downhole Testing Services

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Introduction

1

The SRC Downhole Testing Systems group is responsible for the development of the pressurecontrolled downhole test strings, subsea safety valves, formation isolation valves and IRIS* Intelligent Remote Implementation System tools. The group provides the most flexible and comprehensive array of fullbore tools in the industry, with valve sizes ranging from 11⁄8- to 7 3⁄8-in. ID. The rigorous environments encountered by downhole tools include high pressure and high temperature (HPHT), hydrogen sulfide (H2S), acid, fracturing fluids and lost circulation materials. Reliable operation in these environments demands careful attention tometallurgy, plating, hard surfacing, seals, and overall design and manufacturing methodologies. Designing tool string components to internationally recognized safety specifications allows testing of sour wells and pumping of corrosive stimulation materials. To qualify new tool designs, a 12-in. ID pressure vessel with a 36.5-ft working length enables the performance of tests to 30,000 psi at 450°F [232°C] through five independent pressure zones. Tools can be tested in water or mud, with or without sand, while a computer data acquisition system provides real-time displays and records the data for complete analysis. Downhole tools are assembled at SRC and function-tested at full working pressure and temperature to ensure reliable performance in the field. SRC conforms to the International Standards Organization (ISO) 9001 and 9004 quality standards and has been certified in the design and manufacture of oil well service products (Fig. 2).

Figure 2. Schlumberger Reservoir Completions center ISO certificate.

2

Flopetrol Johnston–Schlumberger downhole tools history The history of the drillstem test (DST) goes back to 1926, when E. C. and M. O. Johnston developed the first commercial downhole testing tools. The two brothers were working in the oil fields in Arkansas, USA, where local conditions required frequent and expensive formation testing in a cased hole. The first tool developed incorporated a tester valve and a conical packer element (Fig. 3). It was used in openhole, saving the cost of running casing to test. The field tests were successful, and the brothers continued to work on improving the tools. Many new tools and techniques were introduced by Johnston Testers. The 1930s saw the introduction of water cushions to reduce differential pressure, a straight hole packer that did not require a core hole and pressure recorders to distinguish between a bad well and tool problems. During the 1940s reverse circulating subs were invented to get recovered oil out of the pipe before tripping out of the hole. In addition to numerous tool improvements in the 1950s, tubing conveyed-perforating was introduced.

Figure 3. Johnston brochure in 1927.

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Introduction

3

Further developments resulted in the MFE* Multiflow Evaluator system in 1961, the first PCT* Pressure Controlled Tester valve system in 1971, the fullbore PCT system in 1980 and the intelligent IRIS tools in 1992. In 1994 a consortium of 11 clients qualified a full range of tools for hostile HPHT conditions with maximum annulus pressures up to 25,000 psi and temperatures above 400°F [204°C]. Later, a selection of tools with an innovative sealing system was qualified for temperatures up to 500°F [260°C]. The process continues (Fig. 4); the Schlumberger design team liaises with field personnel and clients to develop new downhole tools to further enhance tthe capabilities of test strings—and thus maintains the tradition started in 1926.

PCT-D 5 × 17⁄8 in., 15k, H2S Limitation ■ 17⁄8 in. diameter Improvements ■ High-temperature seal ■ N spotting capability 2 ■ New ball valve mechanism (higher unloading)

PCT-A 43⁄4 × 11⁄2 in., 15k, H2S Nonfullbore Limitations ■ Nonfullbore ■ Mechanically operated reversing valves

1985

1988 1990

1980 1975 1961

1965

MFE mechanical tools

Figure 4. DST tool evolution.

4

1970

PCT-C 5 × 21⁄4 in., 10k, H2S, 300°F Fullbore Improvements ■ Fully pressure operated tools ■ Fullbore tools

PCT-E 5 × 21⁄4 in., 10k, H2S, 375°F Improvements ■ Capability of testing in tension ■ High-temperature ball seal ■ N spotting capability 2 ■ Improved ball valve mechanism (higher unloading pressure)

7×

PCT-F 21⁄4 in., 15k, H2S, 425°F Improvements ■ Mud immune ■ Improved temperature and pressure ratings

31⁄2

2000

IRDV-H in., 9k, H2S, 300°F

Fullbore MFE 5 × 21⁄4 in., 15k, H2S, 300°F

1999

1998

1997 1996 1995 1994 1993

J tools 5 × 21⁄4 in., 17.5k, H2S, 500°F Improvement ■ First DST tool qualified to 500°F

1992 1991

PCT-FF 5 × 21⁄4 in., 17.5k, H2S, 425°F Improvement ■ First tool with 17,500-psi differential pressure rating

IRDV-A 5 × 21⁄4 in., 10k, H2S, 330°F Improvements ■ Low-pressure operation ■ Mechanical simplicity ■ Sequential, independent, programmable valve operation ■ N reference not 2 required ■ Index mechanism not required

Downhole Testing Services

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Introduction

PCT-G 31⁄8 × 11⁄8 in., 15k, H2S, 425°F Improvement ■ Fullbore tools for slimhole testing

5

Seal Technology

The operating environment of downhole tools is often limited by the seal technology. Good seal design is the key element in reliable downhole tools and is a challenge because of the multiple pressure cycles and exposure to many different fluids. The following guidelines help explain equipment limitations and how to make the right seal selection for different environments. A seal is a mechanical device that is used to prevent leakage of liquids, solids or gases between chambers at different pressures. Seals are essential to isolate between annulus and tubing pressures and to create hydraulic forces within tools to make them operate. O-ring seals are made from various elastomer compounds (nitrile, Viton®, etc.) and have various hardness ratings (durometer) for different applications. Various types of seals are used in different places in the tools, depending on suitability. For example, the connections between the tools are normally tool joints with metal seals. Internal seals in tools are made from elastomers and can be divided into two types: static and dynamic. Static seals often use double O-rings for redundancy, whereas most dynamic seals are O-rings with backup rings. Dynamic seals designed to unload pressure use V-packings or special hybrid seals.

Downhole environment The downhole testing environment is tough on elastomers because of the variety of fluids and gases present, along with the added effects of time, pressure cycling and temperature. Many of these factors tend to age or overcure the O-ring if the type of elastomer is not suitable for the downhole environment. The choice of elastomer is dependent on several factors. ■

■

■

■

Extrusion resistance is the ability of the O-ring to withstand being forced through a gap (extrusion gap) between two mating parts. The extrusion resistance is affected by increasing pressure differential, pressure cycling and extrusion gap. The majority of tools today use backup rings to minimize the extrusion gap and prevent extrusion. Time and temperature considerations are important as temperature tends to overcure elastomers over time. Different elastomeric compounds react differently, but overcuring makes the elastomer less elastic, which eventually can lead to failure. The maximum operating temperature as defined in the tool specifications should not be exceeded. Each tool type is qualified to a maximum temperature at maximum pressure for a typical DST operating sequence that lasts 120 hr. Chemical attack and the resulting loss of mechanical properties are factors because almost all oilfield chemicals such as brines, acids and inhibitors affect the mechanical properties of O-rings. Different O-ring compounds are affected differently. Tests are performed to determine which is the most suitable compound. For example, some new mud systems contain chemical combinations required to meet environmental standards, which have proved to be aggressive to some O-ring compounds. To evaluate the compatibility of seals with new chemicals, the Downhole Testing Systems group in Rosharon, Texas, performs full-scale tests at various temperatures and pressures. Explosive decompression occurs when gas permeates an O-ring and the pressure is suddenly reduced. The gas then tries to expand and leave the O-ring, which usually results in blisters and cuts. Resistance to explosive decompression varies with O-ring compounds.

Downhole Testing Services

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Seal Technology

7

Recommended elastomer compounds The Schlumberger Downhole Testing Systems group continuously studies elastomers to improve and develop new seals for downhole tools. Part of this process is to qualify and select elastomer compounds to ensure that only high-quality seals are made available to field locations. A unique seal test machine is used to select and determine the limitations of a compound (Fig. 5). The complete seal system is then qualified in the tool by full-scale testing in the DST test vessel. The SRC seal test machine tests seals up to 500°F and 30,000 psi with various fluids and gases.

Figure 5. SRC seal test machine.

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8

The following recommendations are based on laboratory studies and field experience (Table 1). Nitrile C-67 (90 durometer) can be used when all the following conditions are met: – Downhole temperature is less than 300°F [150°C]. – No H2S is present. – No zinc bromide (ZnBr) or calcium bromide (CaBr) is used.

■

Viton V-25 (95 durometer) should be used when any of the following conditions are met: – Downhole temperature is less than 375°F [190°C]. – H2S is present or suspected. – ZnBr or CaBr is used. – Produced fluids contain high levels of light aromatics such as benzene, toluene or xylene.

■

Viton elastomers can be used in place of nitrile elastomers.

Table 1. Comparison of Elastomer Compounds Compound

Nitrile

Viton

HT-3

Aflas

Extrusion resistance

5

5

5

2

Explosive decompression

5

4

4

3

5

5

5

5

Chemical exposure or environment Seawater CaBr/ZnBr completion fluids

2

5

5

5

Steam

1

1

2

3

Diesel

5

5

5

4

Stimulation acids (HCl and HF)†

2

3

3

4

Crude oil

4

5

5

3

H2S

1

4

4

5

CO2

5

3

3

4

Water-base drilling mud

5

4

4

5

Light aromatic hydrocarbons‡

4

4

4

2

Oil-base drilling mud

5

5

5

4

Amine-based inhibitors†

3

2

2

4

Note: Rating system: 5 is excellent, 1 is not recommended. †Most oilfield acid systems use amine-based inhibitor systems. ‡Aflas compounds should not be used if light aromatics such as benzene, toluene and xylene exceed 10%.

■

Viton HT-3 (95 durometer) should be used when any of the following conditions are met: – Downhole temperature is greater than 375°F but less than 425°F [218°C]. – H2S is present or suspected. – ZnBr or CaBr is used. – Produced fluids contain high levels of light aromatics such as benzene, toluene or xylene.

■

Aflas® (90–95 durometer) should be used only when special conditions are met. Contact SRC Engineering for further guidelines. Special seals have been developed for the new ultra HPHT tools, which are designed for operations in temperatures above 425°F.

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A good seal requires more than the selection of a suitable O-ring compound. The tool design, including selection of material and tolerances, and the design of the O-ring groove and seal squeeze are all important factors in achieving a perfect seal. The engineers at Schlumberger have many years’ experience in designing seals for downhole tools in different applications. This, combined with unique test facilities for new developments, places Schlumberger in the forefront of developing seal technology.

Downhole Testing Services

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Seal Technology

9

Typical Downhole Test String Design

Downhole test strings and their component tools can be used in various types of tests. The design of the string is dictated by the well and rig type, as well as the test sequence and objectives. Drillstem test—Downhole tools are run in the hole for a limited-duration test on drillpipe or on tubing. ■ Production test—A permanent packer or tubing string, usually with another specialized tool, is run for a flow or gas test for a relatively long duration. The use of downhole tools to fulfill specialized functions that are required in a production test extends the range and flexibility of the tests. Table 2 describes the functions of the components that make up a typical DST or tubing-conveyed perforating (TCP) tool string as shown in Fig. 6. ■

Table 2. Typical DST or TCP String Components and Functions Tool

Function

Tubing or drillpipe

Provides flow path to surface

Slip joint

Compensates for expansion or contraction of the string

Drill collar

Provides weight for downhole tools

Circulating valve

Provides an independent method of circulation and secondary reversing; circulates out string contents at end of the test

Radioactive sub

Correlates depth during TCP

Surface readout

Monitors downhole pressure and temperature events

Downhole valve

Controls formation flow; isolates cushion and performs other functions

Reference tool

Minimizes surge or swab effects and traps reference hydrostatic pressure in PCT valve

Recorder

Records pressure and temperature versus time during the test

Jar

Provides upstrain to free stuck tools

Safety joint

Provides backoff facility if string becomes stuck

Packer

Isolates between annulus and formation

Perforated pipe

Provides flow path for formation fluids

Debris sub

Avoids accumulation of debris on top of the firing head

Tubing

Spaces out tools

Firing head

Initiates the firing sequence

Spacer

Separates guns from the firing head (safety device)

Perforating gun

Contains perforating charges

Downhole Testing Services

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Typical Downhole Test String Design

11

Tubing or drillpipe

Slip joints (2 or more) Drill collars Redundant circulating valve Drill collars Primary circulating valve RA marker Drill collars Surface readout

Downhole valve Hydrostatic reference tool

Pressure recorders (2 or more)

Hydraulic jar Safety joint Packer

Slotted tailpipe

Debris sub Tubing

Firing head Safety spacer

Perforating gun

Figure 6. Typical DST or TCP tool string.

12

Packers

Packers are designed to isolate the perforated interval from the mud column. The weight applied on the packer compresses its rubber elements against the casing and creates a seal between the annulus and tubing. The packer has three main sections: the drag block and slip assembly, packer elements and the bypass. The drag block and slip assembly has spring-loaded friction pads that contact the casing wall while running in the hole and an annular fluid bypass underneath the elements. A J-slot in the drag block assembly is used to set and unset the packer. While running in the hole, the packer is in the safety position. As long as the J-pin remains in this position the packer cannot set. To set the packer, the following movements are required: 1. Pick string up; this moves the J-pin to the bottom of the J-slot (see Fig. 9, page 19). 2. Turn the string one quarter of a turn to the right at the tool; this moves the pin to the bottom of the setting side of the J-slot. More turns are required at surface; the guideline is 1 turn per 3000 ft in a straight hole. 3. Apply weight on the packer. The weight requirement is approximately 1 ton per in. of nominal packer size (e.g., minimum 7 ton for a 7-in. packer). The J-pin is on the setting side of the J-slot, and the mandrel moves farther down relative to the drag blocks. At this point some equipment has changed position: 1. The bypass closes. 2. The tool body moves down and pushes the slips out against the casing wall; the slips now support the string weight. 3. Continued application of weight squeezes the elements out against the casing wall and keeps the bypass valve closed throughout the DST. At the end of the test, simply picking up the string pulls the bypass open, equalizing the pressure and pulling the packer loose. A mechanism is available to automatically place the J-pin back into the safety position when the packer is in position. Packers are available in different sizes for different casings. Within any one size, the packer can be redressed for different casing weights. The FlexPac packer has a smaller range for each gauge ring size to optimize the performance at high pressure and temperature. The rubber packer elements are available in different hardness levels (durometer ratings) to match the expected bottomhole temperature. The FlexPac packer offers a special element for HPHT conditions above 375°F [190°C]. A gauge ring and junk basket should be run before a cased hole packer is set.

FlexPac system The FlexPac retrievable testing packer system consists of a packer module and an independent hydraulic hold-down module. The hydraulic hold-down module prevents the packer from being pumped uphole when the tubing pressure is greater than the annulus pressure (e.g., when using tubing pressure-operated TCP firing heads or with stimulation). The modular design allows the hold-down module to be placed anywhere in the string. The rugged design of the FlexPac packer system makes it suitable for the high pressures that occur during extreme overbalanced perforating (EOP) and HPHT operations. A tighter control of the extrusion gap on either side of

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the packer elements qualifies the FlexPac system for up to 12,000-psi differential pressure. An improved setting mechanism ensures easier unjaying of the packer at the end of the job.

FlexPac packer The FlexPac retrievable packer (FLXP) (Fig. 7 and Table 3) is designed for testing and TCP operations and replaces the PosiTest* retrievable compression packer. With weight applied to the packer, the sealing elements isolate annulus fluids from the perforated interval. To prevent the packer and string from being pumped uphole during stimulation or similar operations, a FlexPac hydraulic hold-down tool should be run above the packer. The FlexPac packer has a rugged, simple design and is easily redressed between operations or converted for use with other casing weights.

Features ■ ■ ■ ■ ■ ■ ■ ■ ■ ■

FLXP has dependable three-element packing system with antiextrusion rings. Gauge rings have a tighter extrusion gap to improve sealing. Integral bypass minimizes surge and swab effects in all sizes. Tungsten carbide slip inserts grip even the hardest casings. It requires a simple one-quarter turn to set; straight pull to release. Proven face seal controls the bypass. Dual external J-slots improve pressure rating, tensile strength and unjaying. FLXP has a rugged slip design. Design allows pressure testing of packer mandrel. Optional setting mandrel with pressure port allows a differential pressure firing head.

Table 3. FlexPac Packer Specifications Tool

OD† (in.)

ID (in.)

Working Pressure‡ (psi)

Working Temperature (°F)

Service

Casing Size (in., lbm/ft)

FLXP-G

41⁄2 to 51⁄2

1.13

15,000

375

H2S

41⁄2, 13.5 to 51⁄2, 20

FLXP-F

65⁄8 to 75⁄8

2.25

15,000

375

H2S

65⁄8, 24 to 75⁄8, 20

FLXP-E

95⁄8

2.25

15,000

300

H2S

85⁄8, 49 to 95⁄8, 29.3

†OD

depends on gauge ring sizes. pressure: 12,000 psi across the packer elements (15,000 psi across the wall)

‡Maximum

14

Bonded seal

Gauge ring Element

Slips

Friction pad Automatic J-slot J-pin

J-pin in safety

J-pin in setting side

Figure 7. FlexPac packer.

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FlexPac hold-down tool The FlexPac hydraulic hold-down tool (FLXH) (Fig. 8 and Table 4) complements the FlexPac retrievable packer. It prevents the string from moving uphole as a result of hydraulic forces acting below the packer during stimulation or activating a firing head. The slip design is similar to the proven hold-down section of the Positrieve* retrievable downhole packer. When tubing pressure becomes greater than annulus pressure, a piston moves down, activating the hold-down slips. The tungsten carbide inserts on the hold-down slips effectively retain the upward hydraulic force that results from the maximum differential across the packer. When the annulus pressure becomes greater than tubing pressure, the piston moves up, retracting the hold-down slips. A straight upward pull retracts the slips mechanically. The FlexPac hydraulic hold-down tool has a rugged, simple design and is easily redressed between operations or converted for use with different casing weights.

Features ■

■ ■ ■ ■ ■ ■

Modular design allows running one or more hydraulic hold-down tools in any position in the string. Slips can be retracted mechanically. Gauge rings centralize the slip section for improved grip. Rugged slip design prevents upward movement from maximum hydraulic force. Tungsten carbide slip inserts grip even the hardest casings. Proven slip design is similar to that of the Positrieve packer. Slips can be activated only if the hydraulic hold-down tool is in compression.

Table 4. FlexPac Hydraulic Hold-Down Tool Specifications Tool

OD† (in.)

ID (in.)

Working Pressure‡ (psi)

Working Temperature (°F)

Service

Casing Size (in., lbm/ft)

FLXH-G

41⁄2 to 51⁄2

1.13

15,000

375

H2S

41⁄2, 13.5 to 51⁄2, 20

FLXH-F

65⁄8 to 75⁄8

2.25

15,000

375

H2S

65⁄8, 24 to 75⁄8, 20

FLXH-E

95⁄8

2.25

15,000

375

H2S

85⁄8, 49 to 95⁄8, 29.3

†OD

depends on gauge ring sizes. pressure: 12,000 psi across the packer elements (15,000 psi across the wall)

‡Maximum

16

Gauge ring

Tubing pressure port

Slips

Spline

Gauge ring

Figure 8. FlexPac hold-down tool.

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PosiTest packer The PosiTest cased hole packer (PSPK) (Fig. 9 and Table 5) makes a seal between the annulus and formation and supports the string weight. It may also include an integral bypass. The packer has three main sections: the drag block and slip assembly, packer elements and the bypass. The tool has an outer body and an inner mandrel, with a connecting J-pin. The drag block assembly has spring-loaded friction pads that contact the casing wall while running in the hole and an annular fluid bypass underneath the elements. Setting procedure and weight requirements are the same as those described on page 13.

Features ■

■

■

■ ■ ■ ■

■

Heavy-duty design withstands high differential pressures and high temperatures over long periods. Large bypass area minimizes surge and swab effects and reduces the possibility of junk jamming inside the tool. Three packer elements with spacer rings and specially sized gauge rings for antiextrusion and increased seal effectiveness. Integral bypass has a bonded face seal. Tungsten carbide slip inserts give positive grip even in very hard casings (P-110 and higher). Integral bypass reduces string manipulations. With the automatic safety (available on all packers), the packer can be used to pressure test casing. Packer modifies easily for different weights of casing.

Table 5. PosiTest Packer Specifications Tool

OD† (in.)

ID (in.)

PSPK-D-A

41⁄2 to 51⁄2

1.25

PSPK-D-B

51⁄2 to 65⁄8

PSPK-R

Working Temperature (°F)

Service

Casing Size (in., lbm/ft)

9,600

300

Standard

41⁄2, 13.5 to 51⁄2, 20

1.5

10,000

300

Standard

51⁄2, 23 to 65⁄8, 20

65⁄8 to 75⁄8

2.25

10,000

300

H2S

65⁄8, 24 to 75⁄8, 20

PSPK-G-D

85⁄8 to 95⁄8

2.25

10,000

300

H2S

85⁄8, 49 to 95⁄8, 29.3

PSPK-E-F

103⁄4 to 133⁄8

3.00

10,000

300

Standard

103⁄4, 65 to 133⁄8, 48

†OD

18

depends on gauge ring sizes.

Working Pressure (psi)

Bypass seal

Gauge ring

Elements

Slips

Spring loaded drag blocks J-pin in setting side

J-pin in safety

J-pin

Automatic J-slot

Figure 9. PosiTest packer.

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Long-stroke PosiTest packer The long-stroke PosiTest packer (Fig. 10 and Table 6) is different from the standard PosiTest packer in that it is set by string reciprocation instead of string rotation. When the tool is in position to enter the wellbore, the pipe must be picked up and lowered two complete cycles to set the packer. The packer remains in this position unless it is picked up more than 32 in. The packer can be returned to this slot by picking it up 15 in. and then lowering it. The main applications for this packer are tests in horizontal or highly deviated wells and use as a sump packer in the single-trip TCP gravel-packing system. On these jobs, it is advantageous to avoid rotating the string. The long-stroke PosiTest packer is not recommended for operations on floating drilling rigs because it will set whenever heave exceeds 2.5 ft. Table 6. Long-Stroke PosiTest Packer Specifications Tool

OD† (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Casing Size (in., lbm/ft)

PIPK-M

65⁄8 to 75⁄8

2.25

10,000

300

Standard

65⁄8, 24 to 75⁄8, 20

PIPK-LS

85⁄8 to 95⁄8

3.00

9,000

300

Standard

85⁄8, 49 to 95⁄8, 29.3

†OD

20

depends on gauge ring sizes.

RIH position Setting position 15 in.

32 in.

Figure 10. Long-stroke PosiTest packer.

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Compression-set PosiTest packer The compression-set PosiTest packer (PSPC) (Fig. 11) is a modified PosiTest packer with no slips. It is designed to seal against the casing wall when weight is applied to the packer (no rotation needed). This packer is especially suited for use as the upper packer in straddle tests in casing, with the standard PosiTest or Positrieve packer used as the bottom packer. Specifications for the compression-set PosiTest packer are the same as the PosiTest packer (Table 5).

Bypass

Gauge ring

Spacers

Rubber element Gauge ring

Setting mandrel

Figure 11. Compression-set PosiTest packer.

22

Positrieve packer In addition to performing all the functions of a conventional packer, the Positrieve packer (PIPK) (Fig. 12 and Table 7) has an extra section that prevents it from being pumped uphole. Setting procedure and weight requirements are the same as those described on page 13. The hydraulic hold-down section at the upper end of the tool is designed to automatically activate whenever tubing pressure exceeds annulus pressure. When this occurs, the differential pressure pushes down a sleeve and the upper slips are pushed out against the casing wall. This prevents the tool from being pumped uphole. The same amount of differential pressure hydraulically locks the bypass closed. Whenever the applied tubing pressure is bled off, the differential pressure is reversed (annulus to tubing) and the upper slips are retracted. The bypass is maintained in the closed position by the weight of the drill collars. If the upper slips do not deactivate, an override exists. At the end of the test when the string is picked up, an integral shoulder mechanically retracts the upper slips and allows the packer to be pulled loose after the bypass is opened. In addition to standard applications, the Positrieve packer is used for pressure testing, stimulation, cement squeeze jobs and leak detection. Table 7. Positrieve Packer Specifications Tool

OD† (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Casing Size (in., lbm/ft)

PIPK-F

41⁄2 to 51⁄2

1.81

9,500

300

Standard

41⁄2, 13.5 to 51⁄2, 20

PIPK-B

51⁄2 to 65⁄8

2.00

8,000

300

Standard

51⁄2, 23 to 65⁄8, 20

PIPK-C

65⁄8 to 75⁄8

2.43

10,000

300

Standard

65⁄8, 24 to 75⁄8, 20

PIPK-D

85⁄8 to 95⁄8

3.00

9,000

300

Standard

85⁄8, 49 to 95⁄8,29.3

PIPK-D

103⁄4 to 133⁄8

3.00

11,000

300

Standard

103⁄4, 65 to 133⁄8, 48

†OD

depends on gauge ring sizes.

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Tubing pressure

Setting mandrel

Upper slips (extended)

Upper slip activator Upper slip

Inner sleeve with shoulder

Annulus pressure

Floating piston

Tubing pressure

Bypass seal (closed)

Spacer rings

Rubber elements Gauge ring

Setting mandrel

J-pin in setting side

Automatic J-Slot

Figure 12. Positrieve packer.

24

IRIS Pulse-Operated Test System The IRIS Intelligent Remote Implementation System is a new concept for operating downhole tools. Low-intensity command pulses are sent down the annulus and detected by the intelligent controller in the tool. The pulses, recognized as IRIS commands, are implemented using the hydrostatic pressure available downhole to operate the valves in the tool. The IRIS tool combines two fullbore multicycle valves: a tester valve and a circulating valve. Both valves can be cycled independently or in sequence by separate command pulses. The IRIS system is available as a standard 5-in. OD × 2.25-in. ID tool and as a 7-in. OD × 3.5-in. ID big-bore version. The standard tool provides ample flow capacity for typical DSTs; the big-bore tool is preferred for tests with high flow rates and long durations and for through-tubing operations.

Benefits of the IRIS system The intelligent controller provides a high level of flexibility without adding the complexity of an index mechanism or other complicated mechanical parts. The IRIS mechanical section is simple, and most seals and moving parts are bathed in oil at hydrostatic pressure. Combined with large valve operating forces, this bathing ensures reliable tool operation in environments with debris or heavy mud. The flexible command system includes automatic sequences that optimize wellsite operation. Controlling the downhole well is more efficient with the IRIS tool. For example, if sand production is anticipated, the automatic sequence closes the tester valve and opens the circulating valve 30 s later to prevent sand from settling on top of the ball valve before reversing out. The PERFPAC* sand-control method is another example where IRIS flexibility contributes to a reliable and efficient operation. In the PERFPAC single-trip perforating and gravel-pack service, the IRIS tool plays a major role by spotting the cushion and controlling the well during the perforation and cleanup phases. It also provides a bypass, preventing pressure surges and premature setting of the gravel-pack packer when the perforating packer is pulled and moved below the perforations. Eight 1⁄2-in. circulating ports and its insensitivity to pressure fluctuations in the annulus make it possible to circulate at very high rates and complete operations in less rig time than is required with standard tools. The IRIS tool is also insensitive to pressure fluctuations from the operation of other tools or hydraulic fracturing. The low-pressure commands make it easy to communicate with the tool and eliminate problems associated with high pressure levels in the annulus. The hydraulics of the tool are automatically referenced to the hydrostatic pressure, and it can be operated going in and coming out of the well at any depth.

Flexible command system The IRIS tool responds only to specific commands that its intelligent controller recognizes. It is insensitive to other pressure events during the job such as the operation of other downhole equipment, changes in hydrostatic pressure or pressure surges during pumping operations.

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IRIS Pulse-Operated Test System

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Annulus pump pressure as low as 250 psi is applied to communicate with the tool, not to provide operating forces. A mud pump is used to send the command pulses down the fluid column in the annulus. Four types of commands are available for the valve operations: ■ direct commands ■ sequential commands ■ nitrogen commands ■ preset commands. Direct commands, also known as independent commands, do not require a particular sequence to be implemented. They are stand-alone commands to either open or close the tester or circulating valve (Fig. 13). The intelligent controller does not allow both valves to be open at the same time. If one valve is open, a command to open the other is ignored. Sequential commands are used only for the tester valve, providing it with a pressure-operated mode where the well can be shut in quickly by bleeding off the applied annulus pressure.

Low-intensity coded pulses

P t

Command implementation

Independently operated circulating valve

Tester valve Sensor Microprocessor

Test zone

Figure 13. Test string with the IRIS dual-valve tool.

26

Test zone

Nitrogen commands are for the circulating valve only. These special commands open and close the circulating valve with a compressible medium in the tubing (Fig. 14). The IRIS tool provides a more accurate spotting of nitrogen in the string than conventional tools.

Displace String to Nitrogen

Send Nitrogen-Close Command

Circulating Valve Closes After 90 s

Figure 14. Nitrogen command allows accurate placement of N2 cushion.

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IRIS Pulse-Operated Test System

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The optional preset commands are selected at surface, using a computer, before the job. Examples of preset commands are automatic underbalance closure (Fig. 15) and a sequence that closes the tester valve and opens the circulating valve 30 s later. The PERFPAC command is another example of a preset command. In addition to the command options used to operate a valve through the intelligent controller, there is a mechanical override that positions the valves in predetermined positions.

Circulating valve

Test valve Pressure sensor Electronic section

Circulating Valve Open

Circulating Valve Closed

Cushion in Place

Figure 15. Automatic underbalanced closure. The ball valve or the circulating valve automatically closes at a set pressure while running in hole.

28

IRIS dual-valve tool The IRIS dual-valve tool (IRDV) (Fig. 16 and Table 8) is a compact fullbore testing tool that has a multicycle tester valve and a circulating valve. The IRDV is controlled by microprocessor-based electronics and uses hydrostatic pressure as a mechanical energy source to operate downhole tools. Using standard rig pumps, commands are sent as low-level pressure pulses in the annulus. These pulses are detected by a pressure sensor and are decoded with a downhole microprocessor, which implements the commands through the tool electronics and hydraulics. Clean hydraulic fluid, driven by the well hydrostatic pressure, is used to operate the tool. This mode of operation prevents solids in the mud column or debris from the well effluent from contaminating the working parts. Hydraulic control and the high operating force of each valve are achieved by alternating the tool operating pressure between hydrostatic and atmospheric.

Features ■ ■ ■ ■

■ ■ ■ ■

Simplified hydraulic design is immune to mud solids and sand. Operation requires only low-pressure pulses in the annulus. Large valve operating forces improve tool reliability in the presence of debris. Tool is independent of well temperature and pressure, which helps ensure tool operation even during stimulation. Tool is compatible with all other pressure-operated tools. Automatic valve sequences optimize the flexibility and efficiency of the operation. Large flow area and insensitivity to pressure fluctuations allow high circulation rates. Tool operations can be recorded in memory for postjob verification.

Table 8. IRIS Dual-Valve Tool Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

IRDV-AB

5.00

2.25

10,000

320

H2S/acid

31⁄2 IF

IRDV-HA

7.00

3.50

9,000

300

H2S/acid

41⁄2 PH6

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Circulating valve (closed)

Test valve (open)

Atmospheric chamber

Hydrostatic chamber

Pressure sensor Electronics + + + -

Figure 16. IRIS dual-valve tool.

30

Battery

Pressure Controlled Tools

The wide selection of Schlumberger fullbore PCT Pressure Controlled Tester Tools provides modularity for flexibility in tool string design to fit any downhole condition (Table 9). The PCT string is a simple, reliable system that provides optimum safety-oriented operations. After the packer is set, the blowout preventer (BOP) can be closed, and the PCT system allows the complete test to be run without any string manipulation.

Features ■ ■

■ ■ ■ ■ ■ ■ ■

Downhole shut-in valve minimizes wellbore storage effects. PCT string design allows pressure testing of the string against the tester valve or special tubing test valves. String acts as an additional downhole pressure barrier. PCT string enables changing the cushion or placing of partial cushions. Stimulation fluids can be spotted at the perforations. System design is compatible with surface readout and TCP systems. PCT string makes killing the well easier. String works in through-tubing operations. The string acts as a tester and traps downhole sample.

Tool strings with varying specifications are available for any downhole condition. They all have the same reliable design principles, making it easier to operate and maintain tools, regardless of the size and pressure rating. All tool systems are made to the NACE MR-01-75 standard, which requires H2S resistance at all temperatures. Table 9. PCT Tool Systems Specifications Tool System

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Slimhole PCT tool

31⁄8

11⁄8

15,000

425

Standard PCT tool

5

21⁄4

10,000

375

Hostile HPHT

5

21⁄4

15,000

425

Hostile HPHT

5

21⁄4

17,500

425

Ultra HPHT†

5

21⁄4

17,500

500

Big bore

7

31⁄2

9,000

300

† Available

on request

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Pressure Controlled Tools

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PCT valve The PCT valve (PCTV) (Fig. 17 and Table 10), operated by annulus pressure, is the main downhole valve used to control formation flows and shut-ins. The tool is normally run in conjunction with a PORT* Pressure Operated Reference Tool or hydrostatic reference tool (SHRT), both of which will trap a hydrostatic reference pressure in the PCT tool. This feature avoids high precharge of nitrogen at surface. The hold-open (HOOP) module enhances the versatility of the PCT valve. With this module, the ball valve can be held open when the annulus pressure is bled off. This allows wireline to be run through the ball with the annulus pressure bled off or circulation through the ball valve when the packer is not set. Operating pressures for the PCT valve vary with depth but are usually about 1500-psi applied annulus pressure. Table 10. PCT Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

PCTV-E

5.00

2.25

10,000

375

H2S/acid

31⁄2 IF or PH6

PCTV-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

PCTV-FF

5.00

2.25

17,500

425

H2S/acid

31⁄2 IF or PH6

PCTV-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

32

Ball valve Optional hold-open module Annulus pressure Control mandrel

Spring

Nitrogen chamber

Compensating piston

Hydrostatic reference chamber

To reference tool

Closed to Shut in the Formation

Open to Flow or Treat the Formation

Figure 17. PCT valve.

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Pressure Controlled Tools

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Hold-open module The HOOP module (Fig. 18 and Table 11) is an optional part of the PCT valve that allows holding the ball valve open when the annulus pressure is bled off. After the packer is set, the normal operating sequence for the PCT string is to apply pressure to the annulus to open the ball and bleed off the annulus pressure to close the ball. The HOOP module allows this operating sequence, and on certain cycles it locks the PCT ball in the open position after annulus pressure is bled off. The HOOP module is useful in the following procedures: ■ circulating to condition the mud and clean the hole while tripping in ■ testing in 5-in. liner when the test tools are in larger casing and a long tailpipe is used (fluids below the PCT can be circulated out after a test) ■ spotting nitrogen cushions and fluid down to the perforations ■ bleeding annulus pressure during long flow periods ■ running wireline through the PCT valve with annulus pressure bled off ■ eliminating the need for a bypass if the PCT valve is run in or pulled out of the hole in the holdopen position. The addition of the hold-open module does not affect the normal operating pressure of the PCT valve. The hold-open cycle can be altered before the job to suit the operation sequences. Table 11. PCT Hold-Open Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

PCTH-E

5.00

2.25

10,000

375

H2S/acid

31⁄2 IF or PH6

PCTH-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

PCTV-FF

5.00

2.25

17,500

425

H2S/acid

31⁄2 IF or PH6

PCTH-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

34

Lock mandrel

Clutch ring Window sleeve Ratchet key

Ratchet lug

Index lug Driver sleeve

Ball Valve Closed

Ball Valve Open

Ball Valve in Hold-Open

Figure 18. Hold-open module.

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Pressure Controlled Tools

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PORT Pressure Operated Reference Tool The PORT single-shot tool provides reference pressure to the PCT valve and a bypass when running in the hole (Fig. 19 and Table 12). It automatically traps a reference pressure in the PCT valve, eliminating the need for a high precharge of nitrogen at surface. To operate the tool, pressure is applied to the annulus, which then causes the disc to rupture. The overpressure applied to the annulus to rupture the disc is also applied to the reference chamber of the PCT valve. When the annulus pump pressure is bled off, the relief valve bleeds the reference pressure to 350 to 450 psi above the hydrostatic pressure. This trapped reference pressure ensures a high closing force of the PCT ball valve. When coming out of the hole, downhole reference pressure is bled through the relief valve for safety. Because the PORT is pressure operated, set-down weight is not required. The string can be run in tension, which greatly simplifies the string design when testing with a permanent packer. Drill collars (weight) and slip joints (length compensation) can be eliminated. The seal assembly in a permanent packer provides length compensation. When using the PORT, it is recommended that the HOOP module on the PCT valve be used for additional bypass when pulling out of the hole. A Formation Protector Module (FPM) is usually run with the PORT when there are open perforations (see page 38). Table 12. PORT Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

PORT-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

PORT-FF

5.00

2.25

17,500

425

H2S/acid

31⁄2 IF or PH6

PORT-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

36

PCT reference chamber

Drain valve

Relief valve Reference port

Seal mandrel

Atmospheric chamber

Rupture disc

Bypass port

Before Trapping Reference Pressure

After Trapping Reference Pressure

Figure 19. PORT Pressure Operated Reference Tool.

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Formation Protector Module The FPM (Fig. 20 and Table 13) is usually run with the PORT tool when there are open perforations. This module prevents the annulus overpressure applied to close the PORT tool from communicating with the rathole. In this way, open perforations below the tool are protected while squeeze relief continues to be provided when stinging into and out of the permanent packer. ■

■

When stinging into a permanent packer, the module relieves fluid from the inside diameter to annulus when squeeze pressure is approximately 300 psi. When stinging out of the packer, the module will bypass fluid from annulus to inside diameter when inside diameter pressure is 1800 psi less than annulus pressure. The formation is protected from the 1000-psi annulus pump pressure applied to activate the PORT tool because the 1000 psi cannot overcome the 1800-psi pressure of the relieving spring.

Once the PORT tool is activated and the bypass ports are closed, the FPM is no longer affected by differential pressure. Table 13. FPM Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

FPM-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

FPM-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

38

Atmospheric chamber

Rupture disc Seal mandrel

Dump valve

Relief valve

FPM Open

FPM Closed

Figure 20. Formation protector module.

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Pressure Controlled Tools

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Hydrostatic reference tool The SHRT (Fig. 21 and Table 14) provides reference pressure to the PCTV and a bypass when running in and pulling out of hole. The SHRT automatically traps a reference pressure in the PCTV, avoiding high precharge of nitrogen at surface. When running in and pulling out of hole, the SHRT is kept in the open position by the weight below the tool and a powerful spring. Once at setting depth, the SHRT closes when weight is applied on the packer. At the end of the test, picking up on the string reopens the SHRT and helps equalize the pressure across the packer. If injection is planned, drill collar weight is required to ensure that the tool remains in the closed position when tubing pressure exceeds annulus pressure. Table 14. SHRT Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

SHRT-C

5.00

2.25

10,000

350

H2S/acid

31⁄2 IF or PH6

SHRT-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

40

To PCTV

Annulus pressure communicates to the PCTV through the ports

Spline

Spring

Bypass seals Bypass ports

SHRT with Ports Open

SHRT with Ports Closed

Figure 21. Hydrostatic reference tool.

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Pressure Controlled Tools

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Single-shot hydrostatic overpressure reverse valve The single-shot hydrostatic overpressure reverse valve (SHRV), also known as the single-shot hydrostatic overpressure reverse tool (SHORT), is a reversing valve operated by annulus pressure (Fig. 22 and Table 15). It is a single-shot valve, which means that once operated, it cannot be reactivated. It is opened at the completion of the test to reverse out fluids produced during the test. The SHRV reversing valve actuates in response to an increase in annulus pressure. The rupture disc in the outer housing prevents annulus pressure from acting on the operator mandrel. A predetermined amount of annulus pump pressure ruptures the disc and annulus pressure moves the operator mandrel upward to uncover the reversing ports. A ratchet keeps the tool in closed position until the disc is ruptured. Once annulus pressure pushes the mandrel up, the same ratchet locks the mandrel to keep the tool open. Because the rupture disc vents to an atmospheric chamber, it must withstand hydrostatic pressure plus PCTV operating pressure. The greater the hydrostatic pressure, the stronger the disc must be. There are 83 disc ratings available to cover the range of hydrostatic pressures from 900 to 24,000 psi. Table 15. Single-Shot Hydrostatic Overpressure Reverse Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

SHRV-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

SHRV-FF

5.00

2.25

17,500

425

H2S/acid

31⁄2 IF or PH6

SHRV-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

SHRV-H

7.00

3.50

10,000

300

H2S/acid

41⁄2 PH6

SHRV-J

5.00

2.25

17,500

500

H2S/acid

31⁄2 PH6

42

Collet

Piston mandrel Rupture disc

Reversing ports

Closed

Open

Figure 22. Single-shot hydrostatic overpressure reverse valve.

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Pressure Controlled Tools

43

Single-shot hydrostatic overpressure reverse valve (internal/external) The single-shot hydrostatic overpressure reverse valve (internal/external) (SHRV-T or SORTIE) can be opened by applying annulus pressure or tubing pressure (Fig. 23 and Table 16). An additional rupture disc in the bottom sub communicates from the tubing to the atmospheric chamber behind the upper rupture disc. The internal disc pressure rating should be higher than the highest expected tubing pressure (absolute) at the tool. The SHRV-T tool can be run in the following configurations: ■ Annulus pressure operated: The rupture disc is placed in the outer rupture disc port, and the solid plug is placed in the internal rupture disc port. The arrangement is similar to that of the SHRV. ■ Internal pressure operated: The rupture disc is placed in the inner rupture disc port, and the solid plug is placed in the outer rupture disc port. A solid plug in the inner rupture disc is recommended when the SORTIE is used for TCP operations. ■ Annulus or internal pressure operated: One rupture disc is placed in the outer port, and a second rupture disc is placed in the inner port. Table 16. Single-Shot Hydrostatic Overpressure Reverse Valve (Internal/External) Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

SHRV-T

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

44

Collet

Piston mandrel Rupture disc

Reversing ports

Rupture disc

Closed

Open

Figure 23. Single-shot hydrostatic overpressure reverse valve (internal/external).

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Pressure Controlled Tools

45

Multiple-opening, internally operated reversing valve The multiple-opening, internally operated reversing valve (MIRV) is a tubing-pressure operated, reclosable reversing valve with a multiple cycle system that allows pressure testing of the string while running in the hole (Fig. 24 and Table 17). Once the tool is opened, it can be used to reverse circulate; however, the tool is reclosable, which makes it ideally suited for spotting stimulation fluids or changing out cushions. The MIRV is often used to spot stimulation or injection fluids into the string without bullheading into the formation. In a low-permeability formation from which fluids do not flow to the surface, the bullheading of the cushion (which would occur if stimulation fluids were pumped directly into the string) could seriously damage the formation. The tool is opened by applying pressure on surface (pressuring up against the tester valve) and is closed by pumping through the tool at a certain rate. The tool can be preset to close with a pump rate between 2 and 8 bbl/min. The tool can also be run in the hole open, which allows the string to fill with mud. Once the packer is set, the cushion can be pumped into the string, the MIRV can be closed, and the test can be started. Table 17. Multiple-Opening, Internally Operated Reversing Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

MIRV-C

5.00

2.25

10,000

300

H2S/acid

31⁄2 IF or PH6

46

Index section

Piston mandrel

Spring

Reversing ports

Closed

Cycling

Open

Figure 24. Multiple-opening, internally operated reversing valve.

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Pressure Controlled Tools

47

Multicycle circulating valve The multicycle circulating valve (MCCV) is a reclosable valve operated by tubing pressure and is used for spotting fluids and nitrogen (Fig. 25 and Table 18). It is similar to the MIRV but is not rate sensitive for closing. The MCCV responds to changes of flow direction rather than rate changes. The MCCV has a mandrel with a set of ports that can align with either reversing or circulating ports. The tool can be preset on 6 or 12 cycles, depending on the expected pressure tests on the string. When internal pressure exceeds annulus pressure by 500 psi, the indexing system cycles. After a preset number of cycles, the tool opens and the string contents can be reversed out through six l⁄2-in. diameter ports. When direct circulation starts, the reversing port restrictors limit the flow, causing a pressure difference that moves the mandrel into the new position for spotting nitrogen or stimulation fluids. The MCCV is reclosed by bleeding off the tubing pressure or increasing the annulus pressure, which causes a 500-psi differential pressure. The MCCV is not affected by the operation of the annular pressure operated tools and is not limited in operation by available surface pump horsepower. Table 18. Multicycle Circulating Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

MCCV-E

5.00

2.25

10,000

350

H2S/acid

31⁄2 IF or PH6

48

Index system

Operating mandrel Fluid flow Flow restrictors Fluid flow

Closed for Testing or Treating of Formation

Open to Reverse Out Formation Fluid or to Let String Fill During Run-in

Circulating to Spot Nitrogen Cushion or to Treat Fluid Slug

Figure 25. Multicycle circulating valve.

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Pressure Controlled Tools

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Multicycle circulating valve with lock The multicycle circulating valve with lock (MCVL) (Fig. 26 and Table 19) provides a lock module to lock the mandrel in the open or closed position. When the lock is engaged, the tool is insensitive to pressure surges in the tubing or annulus. Annulus-applied pressure, after rupturing a preset disc, disengages the lock. With the lock disengaged, the MCVL operates exactly like the MCCV. Table 19. Multicycle Circulating Valve with Lock Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

MCVL-E

5.00

2.25

10,000

350

H2S/acid

31⁄2 IF or PH6

MCVL-G

3.13

1.13

15,000

375

H2S/acid

23⁄8 Reg. or PH6

50

Index section

Flow ports Fluid flow

Rupture disc

Lock mandrel

Mandrel Locked

Mandrel Unlocked

Ports Closed

Figure 26. Multicycle circulating valve with lock.

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Pressure Controlled Tools

51

Pump-through flapper safety valve The pump-through flapper safety valve (PFSV) (Fig. 27 and Table 20) is a full-opening downhole safety valve. It is run in the open position and closed permanently when the disc is ruptured. The operator mandrel is biased to internal pressure and is locked in the open position to prevent premature closure. Upon rupturing the disc, hydrostatic pressure is applied to the operator mandrel. The operator mandrel moves up against the atmospheric chamber, uncovering the spring-loaded flapper. Pumping down the tubing lifts the flapper off its seat and permits killing the well. It provides a reliable means of well shut-in and the ability to pump into the formation irrespective of tubing or annulus pressure integrity above the valve. Table 20. Pump-Through Flapper Safety Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

PFSV-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

PFSV-FF

5.00

2.25

17,500

425

H2S/acid

31⁄2 IF or PH6

PFSV-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

PFSV-J

5.00

2.25

17,500

500

H2S/acid

31⁄2 PH6

52

Operator mandrel

Rupture disc

Flapper valve

Open

Closed

Figure 27. Pump-through flapper safety valve.

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Pressure Controlled Tools

53

Tubing fill/test valve The tubing fill/test valve (TFTV) (Fig. 28 and Table 21) serves as a means of filling and pressure testing the tubing while running in the hole. As the tubing is lowered into the hole, the fluid enters through the bypass ports. The fluid creates a differential that lifts the flapper and allows the tubing to fill. The tubing can be tested at any depth by pressuring up on the tubing string against the flapper valve. When the test string is at depth and the tubing tests have been completed, the annulus is pressured to rupture a disc that permanently opens the flapper. Once the flapper is open, the tool has a full ID. Table 21. Tubing Fill/Test Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

TFTV-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

TFTV-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

TFTV-H

7.00

3.50

10,000

300

H2S/acid

41⁄2 PH6

54

Flapper

Atmospheric chamber

Rupture disc Fluid flow

RIH Position

Testing Position

Figure 28. Tubing fill/test valve.

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Pressure Controlled Tools

55

Tubing test valve The tubing test valve (TTV) (Fig. 29 and Table 22) provides a way to pressure test the tubing while running in the hole. As the tubing is lowered into the hole, the fluid enters through the bottom of the string. The fluid creates a differential that lifts the flapper and allows the tubing to fill. The tubing can be tested at any depth by pressuring up on the tubing string against the flapper valve. When the test string is at depth and the tubing tests have been completed, the annulus is pressured to rupture a disc that permanently opens the flapper. Once the flapper is open, the tool has a full ID. Table 22. Tubing Test Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

TTV-J

5.00

2.25

17,500

500

H2S/acid

31⁄2 PH6

56

Flapper valve

Operator mandrel

Rupture disc

Closed

Open

Figure 29. Tubing test valve.

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Pressure Controlled Tools

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Single-ball safety valve The single-ball safety valve (SBSV) is a full-opening downhole safety valve (Fig. 30 and Table 23). It is run in the open position and is closed permanently in response to annulus overpressure. The operator mandrel is balanced to internal pressure and is locked in the open position to prevent premature closure. Upon rupturing the disc, hydrostatic pressure is applied to the operator mandrel, thus closing the valve. The large differential pressure (hydrostatic to atmospheric) and the 31⁄2-in.2 operator area yield more than enough force to cut 7⁄32-in. wireline cable, even in shallow wells. The operator locks in the closed position and prevents the tool from reopening until it is retrieved at the surface. The lock can be reset without disassembling the tool, which allows functional testing before running in the hole. A drain valve at the lower end of the tool can be used to bleed off trapped pressure between the ball valves of the PCTV and the SBSV. Kits are available to convert the SBSV to a pipe tester valve (PTV) or pump-through safety valve (PTSV). These tools are on pages 60 and 62, respectively. Table 23. Single-Ball Safety Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

SBSV-E

5.00

2.25

10,000

375

H2S/acid

31⁄2 IF or PH6

SBSV-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

SBSV-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

58

Seal Ball valve

Ball valve operator

Rupture disc Lock

Drain valve

Ball Valve Open

Ball Valve Closed

Figure 30. Single-ball safety valve.

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Pressure Controlled Tools

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Pipe tester valve The PTV is similar to the SBSV but is normally run closed and opens permanently when the disc ruptures (Fig. 31 and Table 24). This tool is useful for production-type tests to allow running in dry and pressure testing the pipe string. When this valve is used with the SBSV, one flow test and one shut-in test can be performed with a minimum of tools. It is also commonly used in HPHT testing for pressure testing the bottomhole assembly (BHA). Connected immediately above the seal assembly, it enables pressure testing of every connection of the string. Table 24. Pipe Tester Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

PTV-E

5.00

2.25

10,000

375

H2S/acid

31⁄2 IF or PH6

PTV-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

PTV-FF

5.00

2.25

17,500

425

H2S/acid

31⁄2 IF or PH6

PTV-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. PH6

60

Seal Valve closed

Valve open

Ball valve operator

Rupture disc Lock

Drain valve

Ball Valve Closed

Ball Valve Open

Figure 31. Pipe tester valve.

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Pressure Controlled Tools

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Pump-through safety valve The PTSV is a modified SBSV using an unbalanced mandrel and a detent (instead of a lock like in the SBSV) (Fig. 32 and Table 25). The tool closes in response to annulus overpressure by rupturing a disc, but it can be reopened by pumping down the tubing. This valve is run in the upside-down position so the mandrel sees tubing pressure and reopens the valve when trying to pump through. Once the tubing pressure exceeds hydrostatic pressure by 600 to 1000 psi, the valve opens and allows fluid to be bullheaded into the formation or circulated up the annulus. The valve automatically closes when tubing pressure is bled off 500 psi below hydrostatic pressure. The valve is useful for DSTs or production tests in 5-in. liner (tools are in the 7-in. casing string). A PTSV can be run and produced gas can still be displaced below the tools before tripping out. (The PCTV must be in hold-open position.) See also the pump-through flapper safety valve (PFSV) on page 52. Table 25. Pump-Through Safety Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

PTSV-E

5.00

2.25

10,000

375

H2S/acid

31⁄2 IF or PH6

PTSV-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

PTSV-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

62

Detent Rupture disc

Ball operator

Ball valve Ball seal

Drain valve

Valve Open

Valve Closed to Shut-in Well Pannulus > Ptubing

Valve Reopened to Pump Through Pannulus > Ptubing

Figure 32. Pump-through safety valve.

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Slip joint The slip joint (SLPJ) is an expansion/contraction compensating tool (Fig. 33 and Table 26). It accommodates any changes in string length caused by temperature and pressure during the DST. The slip joint has two distinct parts: an outer housing and a moving inner mandrel. Its rugged design incorporates three main sections. At the top is a splined moving mandrel that allows torque to be transmitted through the tool. Below this are two pressure chambers, one open to tubing pressure and the other open to annulus pressure. The tool is hydraulically balanced and insensitive to applied tubing pressures. The dynamic seals in the balance chambers are dependable chevron V-seals. Testing slip joints have a stroke of 5 ft; the total number of slip joints required depends on well conditions and the type of operation. For a standard test at 10,000 ft, three slip joints are normal. For tests where injection or stimulation is planned, the associated cooling can cause a large amount of string contraction, and four or five slip joints may be required to compensate for string movement during the operations. A special clamp, securely joining the mandrel and the housing of the slip joint, is added for safety considerations when handling the tool at surface. Slip joints make it easier to space out the TCP guns when testing from a semisubmersible. Table 26. Slip Joint Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

PTSV-F

5.00

2.25

15,000

375

H2S/acid

31⁄2 IF or PH6

PTSV-G

3.13

1.13

15,000

375

H2S/acid

23⁄8 Reg. or PH6

64

5-ft stroke

V–packing seals

Figure 33. Slip joint.

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Slip joint and TCP gun correlation Slip joints are an important concern for accurately positioning the TCP guns. When running a string with a fluted hanger in the BOP, one finds the first fixed point at surface. The second fixed point is the packer at the bottom of the string. The closure of some tools (e.g., SHRT) and the motion downward of the packer mandrel (thus the top shot of TCP gun) must then be taken into account. The slip joint helps space out the string because of its variable length and reduces the use of pup joints.

Depth control Four techniques are used to verify that the TCP guns are at the correct depth: ■

■

■

■

Run a through-tubing gamma ray (GR) and casing collar log (CCL) to locate a reference point in the string and tie into previous logs. Set the packer with electric wireline at a known depth using the GR-CCL for correlation, and sting the guns and completion string through the packer. Set the packer and guns with wireline at a known depth, and sting the completion string into the packer. Tag a fixed and accurate reference point such as a bridge plug.

Special techniques are used on floating rigs and described subsequently. The first technique, using the through-tubing GR-CCL tool, is the most accurate. It relies on a radioactive (RA) marker sub (Fig. 34) placed in the string at a precisely known distance from the top shot. The string is run in the hole to approximately the correct depth, and a short section of GR-CCL log is run over the zone where the sub is located. The GR log indicates the position of the sub (a sharp radioactive peak anomaly) relative to the formation gamma ray. Because the distance from the sub to the top shot is known, the position of the guns can be calculated and adjusted, if necessary, by spacing out the string at the surface. After the packer is set, the GR log may be rerun to ensure that the guns are at the correct depth.

Radioactive pip tag

Figure 34. RA sub.

66

Because the GR log, which is run in tubing, inside casing, is usually attenuated, a slow logging speed achieves better correlation results between the depth control and openhole GR logs. If the formation gamma ray curve shows little activity, a radioactive pip tag should be placed in or below one casing joint prior to running casing as a marker. The second technique relies on setting a permanent packer at a known and accurate depth with wireline, then stinging the guns and completion string with the seal assembly through the packer. A locator is placed on the tubing at the desired distance from the top shot. The third and fourth techniques concern wireline operations. Special techniques used on floating rigs are derived from GR-CCL correlation. A reference point in the string (radioactive marker sub) is tied to the openhole logs, taking into account the various pieces of equipment in the string after the packer is set and string weight slacked off. The procedure is as follows (Fig. 35): 1. Run in hole with DST or TCP string and subsea hanger, land off in subsea BOP stack, and run GR-CCL correlation log. 2. Locate radioactive marker at a depth corresponding to the desired top shot, minus the length of the assembly from the top shot to the radioactive marker measured in tension (including D + J). 3. Pull out of hole to subsea hanger, and add or remove tubing or drillpipe below hanger as required in step 2. Run back in hole with subsea hanger and add the subsea tree assembly. 4. When landed off, the top shot is at D + J below the desired top shot location. 5. Pull up D + J + P, rotate to right, and start to slack off weight; at this point the top shot is P above its final location. 6. As the weight is further slacked off, the setting stroke P of the packer brings the top shot to the desired location. Confirmation with the GR-CCL log is possible after packer setting. T = total slip joint closure available D = desired slip joint closure (typically 1⁄3 to 2⁄3 T ) J = jar + reference tool (SHRT only) closure P = packer stroke while setting

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Pressure Controlled Tools

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D+J+P

Slip joint fully open

Slip joint half closed

T

RA marker

Jar closed Jar open

P D+J

a

b

c

d

e

Figure 35. TCP depth control on floating rigs. a. Run gamma ray correlation log with subsea hanger landed off. b. Adjust space-out below the fluted hanger. c. Land subsea tree. d. Pick up the distance determined by the GR-CCL correlation log. Allow for jar and packer mandrel travel. e. Set packer and slack off weight to land off the subsea tree. Slip joint is at midstroke and guns are at shooting depth. An additional slip joint can be run to facilitate accurate gun positioning.

68

Jar tool The hydraulic jar is used if a packer or guns become stuck (Fig. 36 and Table 27). The jar can be used to provide an upward shock to help pull the tools loose. The tool comprises two parts: a housing connected to the free tools and a spline mandrel attached to the stuck tools. The housing can move up and down with respect to the mandrel. Between the housing and the spline mandrel is an oil chamber separated into two parts by a flow restrictor and check valve. The jar is initially closed (housing down). If the lower section becomes stuck, an overpull is put on the string to store energy in the drillpipe. This overpull causes the jar to begin metering. Oil slowly moves through the flow restrictor, transferring oil from the top chamber to the lower chamber until the seal ring reaches the undercut on the mandrel. When this occurs the housing moves up quickly and an impact is produced upward on the stuck tools. Once the jar is activated, the string is lowered and the housing moves down. Oil flows through the one-way check valve back into the upper section and the tool is recocked, ready to jar again as many times as are needed. Table 27. Jar Tool Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

JAR-F†

5.00

2.25

15,000

375

H2S/acid

31⁄2 IF or PH6

JAR-G‡

3.13

1.13

15,000

375

H2S/acid

23⁄8 Reg. or PH6

†Maximum ‡Maximum

jarring pull is 70,000 lbf jarring pull is 35,000 lbf.

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Pressure Controlled Tools

69

Check valve

Lee Jeva flow restrictor Seal ring

V-packing seals

Spline

Figure 36. Jar tool.

70

Safety joint The safety joint (SJB) (Fig. 37 and Table 28) allows quick release of the test string if the packer or anything below the packer becomes stuck. Typically positioned on top of the packer and made up to the same torque as the other tools in the string, the SJB is disengaged by left-hand torque. The breakout torque is controlled to 950 ft-lbf by a shear pin. An adjusting ring keeps right-hand torque from acting upon the shear pin. The joint can be engaged by applying weight and rotating slowly to the right. Table 28. Safety Joint Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

SJB-F

5.00

2.25

15,000

425

H2S/acid

31⁄2 IF or PH6

SJB-G

3.13

1.13

15,000

425

H2S/acid

23⁄8 Reg. or PH6

Adjusting ring

Locking screw

Shear pin

Coarse threads

Seal

Figure 37. Safety joint.

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Pressure Controlled Tools

71

Dual-Action Valve The Dual-Action Valve (DAV) is a full-opening downhole test valve (Fig. 38 and Table 29). It is run in the closed position, opened by annulus overpressure (rupture disc) and then reclosed by a second annulus overpressure (rupture disc). The operator mandrels are balanced to ID pressure. A two-way ratchet is used to prevent the operator mandrel from shifting, except in response to annulus overpressure. When the first disc is ruptured, hydrostatic pressure is applied to an operator area, which opens the ball valve. The ball stays in the open position until the second disc is ruptured. Rupturing this disc applies hydrostatic pressure to a greater operator area, which permanently recloses the ball valve. Replacing the DAV ball valve with another ball valve enables running the DAV open, closed and then permanently reopened. Table 29. Dual-Action Valve Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

DAV-E

5.00

2.25

10,000

350

H2S/acid

31⁄2 IF or PH6

72

Ball valve

Operator mandrel

Low-value rupture disc High-value rupture disc

Collet

Figure 38. Dual-Action Valve.

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Pressure Controlled Tools

73

Fullbore Annular Sample Chamber The Fullbore Annular Sample Chamber (FASC) is used to trap a downhole sample during a test without shutting in the well (Fig. 39 and Table 30). The sample, once trapped, is contained in an annular cavity in the tool until brought to the surface. By running several tools in series, any number of samples can be taken simultaneously or at different times during the test. The FASC is made up of two basic sections: the sample chamber and operator section. The sample chamber contains a floating piston that separates the chamber into two compartments. The upper compartment is used to trap the sample. This compartment remains empty until the tool is activated. The lower compartment is filled with a hydraulic fluid that is balanced to ID pressure by a compensating piston. When the tool is activated by increasing annulus pressure to burst a rupture disc, this fluid is displaced into the operator section. As the hydraulic fluid flows into the operator section, through a flow restrictor, the floating piston moves down, drawing a sample in behind it. The sample chamber also contains a resettable collet, which locks the sample mandrel in place once a sample has been taken. Sample capacity of 600, 1000 or 1200 cm3 is set at the surface. Table 30. Fullbore Annular Sample Chamber Specifications Tool

OD (in.)

ID (in.)

Working Pressure (psi)

Working Temperature (°F)

Service

Connection

FASC-E

5.00

2.25

10,000

375

H2S/acid

31⁄2 IF or PH6

74

Drain valve

Floating piston Sample chamber Hydraulic fluid

Sample mandrel

Flow restrictor

Atmospheric chamber

Rupture disc Operator mandrel

Before Sampling

During Sampling

After Sampling

Figure 39. Fullbore annular sample chamber.

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Pressure Controlled Tools

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DST String Solutions

This section contains examples of DST string diagrams frequently used around the world. These examples are meant to give an idea of the different concepts and do not necessarily contain all the details of a string. There are many ways of designing a DST string depending on customer needs and operating procedures.

10k IRIS string with DataLatch recorder and TCP The 10k IRIS string with DataLatch* recorder (Fig. 40) is designed for exploration testing below 10,000 psi with surface readout. Monitoring real-time downhole pressure data can often save time because long shut-in periods can be avoided. The IRDV, which is compatible with the DataLatch surface readout system, is used as the downhole tester valve and primary reversing valve. In addition to the DataLatch system reading pressure directly below the IRIS ball valve, any number of gauge carriers can also be run above or below the packer to ensure sufficient data sampling. A pressure recorder close to the reservoir can be critical for correlating the pressure data sampled higher up in the string. In addition to serving as a downhole shut-in valve, the IRDV is also used for pressure testing the string and as a downhole safety valve. The IRIS circulating or reversing valve is reclosable and primarily used for reversing out to kill the well at the end of the test and also to spot treating fluids and changing out the cushion if necessary. For redundancy the SHRV is run as a secondary reversing valve. The FlexPac retrievable packer system with hydraulic hold-down provides a rugged and reliable seal above the producing zone. It provides a string support and also prevents pumping the string up because of hydraulic forces. Two or more slip joints, as required, are run to compensate for any string movement between the two fixed points at the packer and at surface, resulting from temperature changes during the job. Figure 40 shows a basic TCP system below the packer. A wide variety of Schlumberger firing systems and accessories to meet specific needs is available. All Schlumberger DST and TCP systems are manufactured at the SRC center in Rosharon, Texas, and are fully compatible.

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Drillpipe Slip joint open, SLPJ Slip joint half closed, SLPJ Slip joint closed, SLPJ Drill collars RA marker Single-shot reversing valve, SHRV Drill collars

DataLatch surface readout IRIS dual valve, IRDV

UNIGAGE recorder carrier Hydraulic jar, JAR Safety joint, SBJ FlexPac hold-down, FLXH FlexPac packer, FLXP

Perforated pipe Debris sub

Tubing Firing head Safety spacer HSD gun

Figure 40. 10k IRIS string with DataLatch recorder and TCP.

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10k IRIS string for shoot and pull The 10k IRIS string for shoot and pull (Fig. 41) is a simplified string for short shoot-and-pull jobs. The main purpose of this string is to convey the TCP guns and provide means of underbalance and safety while perforating the well. The flexibility of the IRDV tool with its sequential operations is very suitable for this scenario. Slip joints are not required because of the small temperature changes and little or no string movement. It is, however, recommended that gauges be run to record the initial formation pressure immediately after perforating for future reference.

Drillpipe RA marker Single-shot reversing valve, SHRV

Drillpipe

IRIS dual valve, IRDV

UNIGAGE recorder carrier Hydraulic jar, JAR Safety joint, SBJ FlexPac hold-down, FLXH FlexPac packer, FLXP

Perforated pipe Debris sub

Tubing Firing head Safety spacer HSD gun

Figure 41. 10k IRIS string for shoot and pull.

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IRIS big-bore string The 3.5-in. ID big-bore string (Fig. 42) is specially suited for high-flow-rate, long-duration tests and through-tubing operations in 95⁄8-in. casing. The large internal diameter of this string can accommodate 27⁄8-in. guns for high-performance through-tubing perforating. By setting a largebore plug in a nipple below the packer, the well can be suspended to avoid exposing the formation to damaging kill fluids before the well is put on production. The big-bore IRDV is the tester valve and primary reversing valve. The TFTV provides the means for pressure testing the string, and the SHRV is the secondary redundant reversing valve.

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Tubing

Tubing fill/test valve, TFTV-H Single-shot reversing valve, SHRV-H

Crossover

IRIS dual valve, IRDV-H

UNIGAGE recorder carrier

Seal assembly

Nipple profile

Figure 42. IRIS big-bore string.

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10k PCT string with DataLatch recorder and TCP The 10k PCT string with DataLatch recorder (Fig. 43) is designed for exploration testing below 10,000 psi with surface readout. Monitoring real-time downhole pressure data can often save time because long shut-in periods can be avoided. The PCTV is compatible with the DataLatch surface readout system. In addition to the DataLatch system reading pressure directly below the ball valve, any number of gauge carriers can also be run above or below the packer to ensure sufficient data sampling. A pressure recorder close to the reservoir can be critical correlating the pressure data sampled higher up in the string. In addition to serving as a downhole shut-in valve the PCT valve is also used for pressure testing the string and as a downhole safety valve. The MCVL is reclosable, and reversing out to kill the well at the end of the test, it can be used to spot treating fluids and changing out cushion if necessary. For redundancy, the SHRV is run as a secondary reversing valve. The MCVL is tubing pressure operated and provides a system that is redundant because the SHRV is annulus pressure operated. The FlexPac retrievable packer system with hydraulic hold-down provides a rugged and reliable seal above the producing zone. It provides a string support and also prevents pumping the string up because of hydraulic forces. Two or more slip joints, as required, are run to compensate for any string movement resulting from temperature changes during the job between the two fixed points at the packer and at surface. A basic TCP system is shown below the packer. A wide variety of Schlumberger firing systems and accessories to meet specific needs is available. All Schlumberger DST and TCP systems are manufactured at the SRC center in Rosharon, Texas, and are fully compatible.

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Drillpipe Slip joint open, SLPJ Slip joint half closed, SLPJ Slip joint closed, SLPJ Drill collars Multicycle circulating valve, MCVL Drill collars RA marker Single-shot reversing valve, SHRV Drill collars DataLatch surface readout Downhole tester valve, PCTV

Hydrostatic reference tool, PORT or SHRT UNIGAGE recorder carrier Hydraulic jar, JAR Safety joint, SBJ

FlexPac packer system, FLXH and FLXP

Perforated pipe Debris sub

Tubing Firing head Safety spacer HSD gun

Figure 43. 10k PCT string with DataLatch recorder and TCP.

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15k PCT HPHT string with TCP The 15k PCT HPHT string is designed for hostile downhole conditions up to 425°F and 15,000-psi maximum differential pressure (Fig. 44). Most of the tools in this string exist also in a 17,500-psi maximum differential pressure rating for extreme conditions. The tool string has performed successfully in HPHT conditions around the world both with normal kill fluid and with seawater (underbalanced fluid) in the annulus. For very long operations at maximum pressure and temperature, it is recommended to use single-shot tools to avoid having to rely on dynamic seals. A seal assembly and permanent packer are preferred to eliminate the number of downhole tools and increase the differential pressure rating of the packer. The PCT tester valve is used for multiple downhole shut-ins during the test. A PTV above the seal assembly allows pressure testing of all the connections in the string. The seal assembly and PTV are pressure tested before picking up tools, and the remainder of the BHA can be pressure tested against the PTV when running in the hole. The PTV is fitted with a low-value rupture disc set to open at 1000-psi hydrostatic pressure running in the hole. The PCT tester valve is run in the open position, and all other pressure testing is done against the TFTV at the top of the tool string. The TFTV also provides automatic filling of the string and a bypass when stinging in to the permanent packer. Its position at the top of the string protects the seals in all the tools against pressure cycling. It also protects the pressure recorders from extremely high pressures during pressure testing. The PFSV automatically shuts in the well in case of a sudden increase in annulus pressure resulting from a tubing leak. When placed above the recorder carrier it also acts as a back-up shut-in tool for the final shut-in. Two SHRVs for redundancy, set to operate at the same pressure, are positioned above the PCT tester valve. Below the PCT valve is a third SHRV acting as an emergency bypass for bullheading at the end of the test should the PCT fail to open. A basic TCP system is shown below the packer. A wide variety of Schlumberger firing systems and accessories to meet specific needs is available. All Schlumberger DST and TCP systems are manufactured by the SRC center in Rosharon, Texas, and are fully compatible.

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Tubing Tubing fill/tester valve, TFTV-F Single-shot reversing valve, SHRV-F

Tubing RA marker Single-shot reversing valve, SHRV-F

Tubing

Downhole tester valve, PCTH-F Hydrostatic reference tool, PORT-F Single-shot reversing valve, SHRV-F Pump-through flapper safety valve, PFSV-F UNIGAGE recorder carrier Pipe tester valve, PTV-F Seal locator Permanent packer Seal assembly

Perforated pipe Debris sub

Tubing Firing head Safety spacer HSD gun

Figure 44. 15k PCT HPHT string with TCP.

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17.5k extreme HPHT string with single-shot tools The extreme HPHT string has been developed for downhole conditions up to 425°F and differential pressures of 17,500 psi (Fig. 45). The extreme HPHT string is presently based on singleshot tools, giving high operating pressures and a simple rugged design. A PTV at the lower end of the string is for pressure testing the BHA. The lower PTV is set to open automatically at 1000-psi hydrostatic pressure while running in the hole. Subsequent pressure testing of the string is done against the PTV at the upper end of the string. A PFSV automatically shuts in the well in case of a sudden increase in annulus pressure resulting from a tubing leak. It also provides a downhole shut-in at the end of the test. Two SHRVs for redundancy, set to operate at the same pressure, are positioned above the PFSV. Tubing Pipe tester valve, PTV-FF Single-shot reversing valve, SHRV-FF Single-shot reversing valve, SHRV-FF

Tubing Pump-through flapper safety valve, PFSV-FF UNIGAGE recorder carrier Pipe tester valve, PTV-FF Seal locator Permanent packer Seal assembly

Wireline reentry guide

Figure 45. 17.5k extreme HPHT string with single-shot tools.

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17.5k ultra HPHT string The ultra HPHT string has been developed for downhole conditions above 425°F and differential pressures of 17,500 psi (Fig. 46). These tools have been qualified for 500°F at maximum pressure at the SRC test facilities in Rosharon, Texas. A special seal package has been developed and tested for this string. The ultra HPHT string is presently based on single-shot tools, giving high operating pressures and a simple rugged design. A TTV at the lower end of the string is for pressure testing the BHA. The lower TTV is set to open automatically at 1000-psi hydrostatic pressure while running in the hole. Subsequent pressure testing of the string is done against the TTV at the upper end of the string. A PFSV automatically shuts in the well in case of a sudden increase in annulus pressure resulting from a tubing leak. It also provides a downhole shut-in at the end of the test. Two SHRVs for redundancy, set to operate at the same pressure, are positioned above the PFSV. Tubing Tubing tester valve, TTV-J Single-shot reversing valve, SHRV-J Single-shot reversing valve, SHRV-J

Tubing Pump-through flapper safety valve, PFSV-J UNIGAGE recorder carrier Tubing tester valve, TTV-J Seal locator Permanent packer Seal assembly

Wireline reentry guide

Figure 46. 17.5k ultra HPHT string.

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15k slimhole PCT string with TCP The slimhole PCT string is designed for testing in slim holes down to 41⁄2-in. casing (Fig. 47). The 31⁄8- by 11⁄8-in., 15,000-psi tools have the same features as the standard PCT string. In addition to serving as a downhole shut-in valve, the PCT is also used for pressure testing the string and as a downhole safety valve. The MCVL is reclosable, and in addition to reversing out to kill the well at the end of the test, it can be used to spot treating fluids and change out the cushion if necessary. For redundancy, the SHRV is run as a secondary reversing valve. The MCVL is tubing pressure operated and provides a system that is truly redundant because the SHRV is annulus pressure operated. The FlexPac retrievable packer system with a hydraulic hold-down provides a rugged and reliable seal above the producing zone. It provides a string support and also prevents pumping the string up because of hydraulic forces. Two or more slip joints, as required, are run to compensate for any string movement between the two fixed points at the packer and at surface resulting from temperature changes during the job. A basic TCP system is shown below the packer. A wide variety of Schlumberger firing systems and accessories to meet specific needs is available. All Schlumberger DST and TCP systems are manufactured by the SRC center in Rosharon, Texas, and are fully compatible.

Tapered string If the distance between the top of the slim liner and the reservoir is relatively short, a tapered string may be run. Standard tools (5 in. × 21⁄4 in.) are then positioned in the larger casing size above the slim liner as long as the test can still be conducted safely. In special situations a slimhole safety valve and reversing valve can be run down in the slim liner with the rest of the tools in the larger casing above.

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Drillpipe Slip joint open, SLPJ-G Slip joint half closed, SLPJ-G Slip joint closed, SLPJ-G Drill collars Multicycle circulating valve, MCVL-G Drill collars RA marker Single-shot reversing valve, SHRV-G Drill collars Downhole tester valve, PCTV-G

Hydrostatic reference tool, PORT-G or SHRT-G UNIGAGE recorder carrier Hydraulic jar, JAR-G Safety joint, SBJ-G FlexPac hold-down, FLXH-G FlexPac packer system, FLXP-G

Perforated pipe Debris sub

Tubing Firing head Safety spacer HSD gun

Figure 47. 15k slimhole PCT string with TCP.

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10k PERFPAC string PERFPAC single-trip perforating and gravel-pack service (Fig. 48) saves an average of 24 hr of rig time compared with standard gravel-pack service, which requires multiple trips in the hole. In addition to time saving, another big advantage is that the well does not have to be killed between perforating and gravel packing, thereby avoiding fluid losses and damage to the formation. The IRDV plays a major role of the success of the PERFPAC system. The IRIS tool is used to spot the cushion and control the well during the perforating and cleanup phase. It also provides equalizing and bypass as the perforating packer is pulled and moved down below the perforations, preventing surges and premature setting of the gravel-pack packer. The unique command system of the IRDV and its insensitivity to pressure surges and sand are important features of PERFPAC operations.

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Tubing RA marker

IRIS dual valve, IRDV

UNIGAGE recorder carrier

QUANTUM service tool QUANTUM gravel-pack packer Big-bore flapper valve

Gravel-pack screen/blanks

Perforating/sump packer

Perforated pipe Debris sub Tubing Firing head Explosive automatic gun release sub, SXAR Safety spacer HSD gun

Figure 48. 10k PERFPAC string.

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