JET Manual 13: Coiled Tubing Pressure Control Equipment [PDF]

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JET Manual 13 Coiled Tubing Pressure Control Equipment Version 1.0

JET Manuel 13 Coiled Tubing Pressure Control Equipment InTouch Content ID# Version: Release Date: Owner:

4221744 1.0 February 23, 2007 Well Services Training & Development, IPC

Schlumberger private

Document Control Revision History Rev

Effective Date

Description

Prepared by

Copyright © 2007 Schlumberger, Unpublished work. All rights reserved. This work contains the confidential and proprietary trade secrets of Schlumberger and may not be copied or stored in an information retrieval system, transferred, used, distributed, translated or retransmitted in any form or by any means, electronic or mechanical, in whole or in part, without the express written permission of the copyright owner.

Trademarks & service marks “Schlumberger,” the Schlumberger logotype, and other words or symbols used to identify the products and services described herein are either trademarks, trade names, or service marks of Schlumberger and its licensors, or are the property of their respective owners. These marks may not be copied, imitated or used, in whole or in part, without the express prior written permission of Schlumberger. In addition, covers, page headers, custom graphics, icons, and other design elements may be service marks, trademarks, and/or trade dress of Schlumberger, and may not be copied, imitated, or used, in whole or in part, without the express prior written permission of Schlumberger. An asterisk (*) is used throughout this document to designate a mark of Schlumberger. Other company, product, and service names are the properties of their respective owners.



Table of Contents 1.0  Introduction 1.1

Learning objectives

2.1

Operating categories

7 7 9 10 11 11 11 12 12 13 14 14 14 15 16 16 17 18 19 20 20 22 22 27 27 28 29 29 29 30 30 31 31

2.0  CT Pressure Control Equipment 3.0  Stripper

3.1 Description 3.2 Specifications 3.3 Stripper types 3.3.1 Conventional stripper  3.3.2 Side door stripper 3.3.3 Sidewinder stripper 3.3.4 Radial stripper 3.3.5 Over/under stripper 3.3.6 Antibuckling guide 3.4 Stripper components 3.4.1 Brass bushings 3.4.2 Stripper element  3.4.3 Energizer  3.4.4 Nonextrusion rings  3.5 Stripper hydraulic system 3.5.1 Stripper drive system 3.5.2 Stripper quick pack or retract 3.6 Redressing side door stripper 

4.0  BOP

4.1 Description 4.2 Specifications 4.3 BOP types  4.3.1 Quad BOP 4.3.2 Combi BOP 4.3.3 Shear-seal BOP 4.3.4 Annular BOP (ABOP) 4.3.5 CIRP BOP  4.4 BOP components JET 13 – Coiled Tubing Pressure Control Equipment  | 

iii

4.4.1 BOP body 4.4.2 BOP rams 4.4.3 Ram bonnet and actuator 4.4.4 Equalizing valves 4.4.5 Side port 4.4.6 Pressure port and debooster 4.5 BOP hydraulic system 4.5.1 BOP hydraulics 4.5.2 BOP drive system 4.6 Redressing the BOP  4.6.1 Quad BOP  4.6.2 Combi BOP

5.0  Auxiliary Pressure Control Equipment 5.1 Quick latch union 5.1.1 Operation 5.2 Side door deployment tool 5.3 Load-bearing quick connect  5.3.1 Operation 5.4 Quick test safety sub (QTSS) 5.4.1 Specification 5.4.2 Operation of QTSS

6.0  Risers and Lubricators 6.1

Specification 

7.0  Crossovers and Connections

7.1 Crossovers 7.2 Flanged connections 7.2.1 Flange types and ring gaskets 7.2.3 Postjob maintenance 7.3 Pin-and-collar unions 7.3.1 Types of pin-and-collar union 7.3.2 Making up pin-and-collar unions 7.3.3 Postjob maintenance 7.4 Threaded connections  7.4.1 Types of threaded connection 7.4.2 Making up threaded connections 7.4.3 Postjob maintenance

8.0  Pressure Testing 8.1

Low-pressure test

iv  |  Table of Contents

31 32 35 36 37 37 38 38 39 41 41 44 47 47 48 48 48 49 49 50 50 53 53 55 55 56 56 58 59 59 60 60 61 61 61 61 63 63

8.2 PT-1 and PT-2 pressure tests 8.2.1 Pressure test 1 (PT-1) 8.2.2 Pressure test 2 (PT-2)

63 63 64 65 67 69

9.0  Glossary 10.0  References 11.0  Check Your Understanding

JET 13 – Coiled Tubing Pressure Control Equipment  | 



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vi  |  Table of Contents

1.0  Introduction Schlumberger Well Services (WS) carries out many types of coiled tubing (CT) operations in live oil and gas wells. One of the most important safety considerations in CT operations is the ability to carry out the work safely and with complete control over the live well pressure. Well Services uses a variety of pressure control equipment on the surface to control the live well pressure. This job execution training (JET) manual introduces you to the different types of strippers, blowout preventers (BOPs), and auxiliary pressure control equipment used by Schlumberger in carrying out CT operations. The manual describes the functions and components of the main pieces of equipment.

Note: Maintenance and assembly procedures are not covered in this manual. These procedures are covered by the equipment manufacturer manuals. Refer to the Coiled Tubing Surface Equipment Maintenance Program, InTouch Content ID# 4196880, for more information.

1.1 Learning objectives Upon completion of this training, you should be able to do all of the following: • List the items of CT pressure control equipment. • Explain the functions of each item of pressure control equipment.

• List the main types of BOP and stripper and explain the differences between the types. • Define and list the main components of BOPs and strippers. • Describe the hydraulic circuit of the BOPs and stripper. • Explain the function of auxiliary pressure control equipment. • Identify different types of quick unions, flanges and gaskets.

Warning: All pressurized equipment has the potential to cause damage to property, and/or injury or death to personnel. The greater the pressure in the system is, the greater the danger is. To minimize dangerous situations, follow all the Well Services-approved safety procedures. Proper supervision is required during hands-on training. Request assistance from your supervisor if you are unfamiliar or uncomfortable with the operation. When working on any equipment, follow the procedures in Well Services (WS) Safety Standard 4: Facilities and Workshops, InTouch Content ID# 3313678. When conducting any pressure testing, follow the procedures in Safety Standard 5: Location Safety, InTouch Content ID# 3313681.

JET 13 - Coiled Tubing Pressure Control Equipment  |  

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  |  Introduction

2.0  CT Pressure Control Equipment The configuration of pressure control equipment on any CT location will be similar whether the operation is on land or offshore. To perform a CT operation, the following pressure control equipment is required: • stripper: to provide an annular seal around the CT string • BOP: to provide contingency and emergency functions • wellhead adapters: to connect the pressure control equipment to the wellhead.

Further auxiliary pressure control equipment may be required, for example: • additional BOPs and strippers, depending on potential wellhead pressure

BOP (Secondary barrier)

Stripper (Primary barrier)

Shear-seal BOP (Tertiary barrier)

Wellhead

Figure 2-1. CT Pressure Control Stack

• lubricator/riser: to give space for tool deployment • hydraulic quick latch: to allow quick and safe stabbing of injector onto stack • flow tee or flow cross and associated valves: to allow well flowback.

The pressure control equipment rigged up on a CT operation is often referred to as the pressure control stack. The configuration of a pressure control stack requires advance planning for every job. Depending on the type of treatment being performed and the well characteristics, different pressure control equipment may be required. Figure 2-1 provides a general view of a typical location rig-up and the locations of these functions.

JET 13 - Coiled Tubing Pressure Control Equipment  |    

2.1 Operating categories In the WS Safety Standard 22 (InTouch Content ID# 3313710), CT operations are categorized by the maximum potential wellhead pressure (MPWHP) of the well. The MPWHP is the highest wellhead pressure (WHP) possible given the reservoir pressure. The following defines the categories based on their MPWHP. • Category 1:

0 to 3,500 psi WHP

• Category 2:

3,500 to 7,000 psi WHP

• Category 3:

7,000 to 13,500 psi WHP.

Note: It is important to remember that even if a well has no WHP (a dead well), it may still have a potential WHP that makes it a Category 2 or 3. The standard describes the minimum equipment configuration for each category. • Category 1 wells. These are the lowest pressure wells. The minimum pressure control equipment required is ○ one stripper (see Section 3.0), 5,000 psi working pressure ○ one BOP (see Section 4.0), 5,000 psi working pressure. • Category 2 wells. The minimum pressure control equipment required is ○ one stripper, 10,000-psi working pressure ○ one BOP, 10,000-psi working pressure

10  |  CT Pressure Control Equipment

• Category 3 wells. These are the highest pressure wells. The minimum pressure control equipment required is ○ two strippers, 15,000-psi working pressure each ○ two BOPs, 15,000-psi working pressure each.

These are the minimum requirements, and additional equipment may be required depending on other factors, such as the flowback configuration. For more detailed information on the equipment requirements for each operating category, read WS Safety Standard 22.

3.0  Stripper This section explains the function and operating principle of the CT stripper. It identifies and explains the main components of a stripper and lists the different models of stripper.

3.1 Description The stripper is the primary well control barrier on CT operations. It is sometimes referred to as the stuffing box. The stripper provides the annular seal, which is the seal between the CT string and the wellbore. It contains the WHP by compressing an elastomer seal, or stripper element, around the CT string. This seal allows full pressure control while the CT string is moving into or out of the well. It is the stripper’s function that allows CT operations to be carried out in live oil and gas wells. The stripper is normally pinned directly to the bottom of the CT injector head (see Fig. 3-1). For CT operations in high-pressure wells, a second stripper (often called a tandem stripper) is required. The tandem stripper is made up below the upper stripper with a flanged connection or quick union. The stripper is run on a hydraulic system, which is controlled from inside the control cabin of the CT unit (CTU). The number and type of strippers required on a CT operation are defined in WS Safety Standard 22, CT Operations.

Figure 3-1. Stripper Pinned to Bottom of Injector Head

3.2 Specifications Strippers are available in different sizes and are classified by the internal diameter of the stripper body. The stripper must be dressed to accept different sizes of CT string. A list of the most common sizes of stripper and the sizes of CT that can be used with each can be found in Table 3-1. Table 3-1. Common Sizes of Stripper and CT

Stripper nominal size Size of CT union seals

3.06 in ≤ 2 in

4.06 in ≤ 2 7/8 in

JET 13 - Coiled Tubing Pressure Control Equipment  |    11

Strippers are hydraulically actuated using an air-over-hydraulic pump, controlled from the CTU cabin. Two manual backup systems are provided in the cabin in case of a loss of hydraulic pressure.

Retainer and clip pins Slip cap and upper bushing Nonextrusion ring

The hydraulic system of the stripper is described in more detail in Section 3.5.

Packing inserts Energizer

Different categories of strippers are used in different operating conditions:

Lower bushing

• conventional • side door

Interchangeable

3.3 Stripper types

Conventional assembly

• sidewinder • radial Interlocking stripper inserts

• over/under.

3.3.1 Conventional stripper The conventional or top-loader stripper design (see Fig. 3-2) is based on the original stripper design, where the bushings and stripper insert are loaded from the top of the stripper body. This design makes changing stripper inserts quite difficult when the stripper is pinned to the injector. The length of the bushing section is relatively short compared with later designs.

12  |  Stripper

Figure 3-2. Conventional Stripper

Note: The stripper elements, nonextrusion rings, and the upper bushing are all split in half. This arrangement ensures that the elements can be replaced during a job, with the CT in the well.

The stripper is nonpressure balanced, meaning that the WHP affects its function. The WHP pushes upward on the packing and helps the stripper to seal. This factor reduces the hydraulic pressure required to pack the stripper.

12

3.3.2 Side door stripper Side door strippers (Fig. 3-3) are preferred over conventional strippers because of design features that give improved safety and ease of use. They are the most common model of CT stripper used by Schlumberger.

rings by hydraulically retracting the pack-off piston and exposing an open window on the side of the stripper. This feature is particularly advantageous when changing the stripper element with tubing in the well. This model of stripper has a longer section of brass bushings than the conventional stripper. This section gives improved centralization of the CT string to reduce stripper insert wear. Side door strippers are available in pressurebalanced designs, which isolates the hydraulic chamber from the WHP. This pressure balancing means that the WHP has no effect on the piston pressure on the stripper insert. This lack of effect on the piston pressure eliminates any effects caused by fluctuations in well pressure. Side door strippers are also available in nonpressure-balanced designs.

Figure 3-3. Side Door Stripper

The side door stripper was introduced to enable easier and safer replacement of stripper inserts while the equipment is rigged up. As the name suggests, this model of stripper has a side door that allows direct access to the internal components of the stripper. This door means that the stripper can be serviced easily during a job, even with the CT string in the well. The side door design permits replacement of the element, energizer, and nonextrusion JET 13 - Coiled Tubing Pressure Control Equipment  |    13

3.3.3 Sidewinder stripper Sidewinder strippers (Fig. 3-4) are generally used as tandem (lower) strippers in highpressure applications, although they can also be run as primary strippers.

Figure 3-4. Sidewinder Stripper

The unique feature of the sidewinder stripper is the ability to fully retract the stripper elements and wear bushings from the bore of the stripper. This ability allows the CT bottomhole assembly (BHA) (which generally has an OD greater than the CT string OD) to be inserted through the stripper packer without breaking any connections below the stripper. In most cases, this feature can represent a large time advantage.

Note: The radial stripper (Fig. 3-5) has been replaced by the sidewinder stripper.

Figure 3-5. Radial Stripper

3.3.5 Over/under stripper An over/under stripper (Fig. 3-6) serves as two individual strippers in one stripper body. It can be used as a replacement for a two-stripper configuration, fulfilling the requirements for a primary and a tandem stripper packer in higher WHP applications. It gives a reduction in stack height of 1.2 m [4 ft] over the two-stripper configuration.

The sidewinder stripper has a much shorter stack height than an equivalent side door stripper, which can be an advantage in certain applications where stack height is critical.

3.3.4 Radial stripper The stripper elements are energized from the side (radial), which enables a relatively large insert to be used. It does not have fully retractable inserts to allow full bore access as does the sidewinder.

14  |  Stripper

14

between the bottom of the injector head chains and the top of the stripper (see Fig. 3-7).

Figure 3-7. Buckled CT String

Figure 3-6. Over/Under Stripper

The packers are activated by individual pistons and can therefore be used independently. Both packers are supported by bushings.

To prevent this buckling, an antibuckling guide can be placed over the top of the stripper, between the stripper and the injector head (Fig. 3-8). This guide acts as an extension of the stripper bushing section by centralizing and restraining the CT string, thereby preventing buckling.

A pressure chamber between the packers can be used to inject lubricants onto the CT as it goes in the well or inhibitors on the CT as it is pulled out of the well.

3.3.6 Antibuckling guide The antibuckling guide is not a stripper, but it is used as an extension to the stripper in certain circumstances. When running CT into wells with high WHP, the injector head is snubbing or pushing the pipe into the well against the upward force generated by the WHP.

Figure 3-8. Antibuckling Guide

At high pressures, the compressive force on the CT string can lead to the string buckling

JET 13 - Coiled Tubing Pressure Control Equipment  |    15

3.4 Stripper components This section explains the main components of the stripper.

3.4.1 Brass bushings The stripper contains brass bushings above and below the elastomer stripper element (see Fig. 3-9). The function of the brass bushing is • to avoid contact friction between CT string and the stripper body • to minimize the extrusion (deformation) of the stripper element.

The brass also acts as a guide for the CT string during stabbing-in of the string into the stripper. Brass is chosen as the material for the bushings for the following reasons: • to minimize the abrasion on the CT string • to minimize the chance of generating sparks.

Standard brass bushings have an internal diameter of CT string OD + 0.025 in. For example, the internal diameter of the brass bushings for a 1.75-in CT string is 1.750 in + 0.025 in = 1.775 in.

Figure 3-9. Brass Bushings from Side Door Stripper

Note: It is important that you regularly check the brass bushings for wear on the internal bore, because worn bushings cause the stripper elements to wear out very quickly.

Worn brass bushings should be replaced immediately. You can find the maximum permitted brass bushing ID in the Coiled Tubing Operators Manual (InTouch Content ID# 3013707). If the ID exceeds this limit, you must replace the brass bushings.

16  |  Stripper

16

3.4.2 Stripper element The stripper element is a two-piece, interlocking elastomer element (Fig. 3-10), which fits around the CT string inside the stripper body. This element is compressed by a piston to provide a seal around the CT string against wellhead pressure. The piston is driven by hydraulic pressure controlled from the control cabin.

The most common materials used are listed below, but a wider range of specialized stripper elastomers for particular conditions can be obtained from the suppliers. • Urethane is the longest wearing material, but can only be used at low to moderate temperatures. It has a temperature range of -40 to 93 degC [-40 to 200 degF]; it deteriorates above 93 degC [200 degF]. • Nitrile is the most common oilfield rubber compound. It has good oil and water resistance, and can be used at high wellbore temperatures. Nitrile cannot be used in the presence of H2S (hydrogen sulphide) gas. It has a temperature range of 37 to 177 degC [100 to 350 degF].

Figure 3-10. Two-Piece Interlocking Element from Stripper

Higher hydraulic pressures, resulting in greater compression of the elastomer element, are required for higher wellbore pressures.

Note: The stripper inserts are the sacrificial components in the stripper system as they become worn out regularly. They should be replaced after every CT run, but often need to be changed out during a run if they have become worn.

• Viton™ has excellent resistance to most oil and gas well chemicals and has a higher temperature range than urethane and nitrile. Resistance to abrasion wear is not as good as urethane or nitrile. It has a temperature range of 5 to 204 deg C [40 to 400 deg F]. • Ethylene propylene diene rubber (EPDM) has excellent resistance to steam and geothermal hot water fluids. It will not tolerate oil, so it cannot be used in oil wells. It has a temperature range of 7 to 260 degC [20 to 500 degF].

For further information on the range of stripper inserts available, the suppliers can be contacted: • Texas Oil Tools: www.tot.com

3.4.2.1 Stripper element material

• Benoil: www.benoil.com

Stripper elements are available in a range of different materials, with different levels of • wear resistance • temperature resistance • chemical resistance.

JET 13 - Coiled Tubing Pressure Control Equipment  |    17

3.4.2.2 Stripper insert life The main factors affecting the stripper insert life are the following: • hydraulic pressure: The stripper inserts wear out quickly when used in wells with high WHP. When the WHP is high, the stripper insert needs to be compressed with a high level of hydraulic pressure to maintain the seal. This high pressure increases the friction between the CT string and the stripper insert, which wears out the insert more quickly.

To avoid wearing out the insert unnecessarily, it is important not to apply unnecessary excess stripper pressure on standard (low or medium pressure) applications. • lubrication: Lubrication also plays an important role in the lifespan of a stripper element. For example, stripper inserts will wear much more quickly in a dry gas well than in an oil well where the pipe will be “lubricated” by the wellbore fluid when being stripped out of the hole.

Most stripper models have an injection port to allow injection of a lubrication fluid or inhibitors as required. It is a good idea to check the compatibility of any lubrication fluid you are planning to use with the stripper insert manufacturer. For example, diesel will soften some types of inserts, causing excess wear.

from side to side. This action will wear the stripper inserts more quickly.

Note: After stabbing in the CT string at the beginning of an operation, always retract the stripper and check the condition of the stripper inserts because the end of the string often damages the stripper inserts. A good practice is to use old stripper inserts while stabbing the CT string. Replace with new inserts after stabbing.

3.4.3 Energizer Most stripper elements are designed as a part of a two-part system comprising the consumable stripper element itself and an outer energizer. A one-piece energizer like the one shown in Fig. 3-11 can be used in a conventional stripper. Side door strippers require two-piece energizers.

Also, manufacturers have developed some self-lubricating models of stripper insert. These inserts are made of an elastomer compound with good lubrication properties. • brass bushing condition: One of the functions of the brass bushings is to centralize the CT string in the stripper. If the brass bushings are worn on the internal diameter, the CT string can move slightly

18  |  Stripper

18

Figure 3-12. Full-Bore Stripper Not Requiring Energizerr

3.4.4 Nonextrusion rings

Figure 3-11. One-Piece Energizer

Because the CT string does not come in contact with the energizer, the energizer does not wear as much as the inner stripper insert does. For this reason, they do not need to be replaced very often. However, they should be inspected each time the stripper insert is changed, and replaced if any damage or deformation is evident.

Nonextrusion rings are two-segment Teflon™ discs (see Fig. 3-13) that are placed immediately above and below the stripper insert to prevent the extrusion or deformation of the stripper insert. These disks are generally long lasting, but should be checked regularly for any damage or any wear to the ID bore.

Full-bore stripper inserts also exist that do not need any energizer (Fig. 3-12). These models allow quicker changing of inserts when worn.

Figure 3-13. Two-Piece Nonextrusion Ring

JET 13 - Coiled Tubing Pressure Control Equipment  |    19

3.5 Stripper hydraulic system

CTU control console

All strippers, regardless of their type, operate in basically the same way, with some differences that are beyond the scope of this manual. Depending on the stripper design and packing arrangement, hydraulic pressure is applied to the top, bottom, or side bushing via a stripper actuator piston. The piston compresses the energizer, which in turn forces the packing insert against the CT string. Most actuator pistons are dual acting, which means they hydraulically pack and retract the stripper. Packing causes the piston to actuate the energizer and packing inserts. Retracting causes the piston to deactuate the energizer and packing inserts.

Rucker pump

3.5.1 Stripper drive system

Figure 3-14. Backup Controls in CTU Cabin

The stripper hydraulic system is pressurized by a Haskell air-over-oil pump located in the CTU cabin.

3.5.1.1 Emergency procedures

As a backup, if air pressure is lost, the Haskell pump can be manually operated. An additional hand pump mounted on the small pump console, known as a Rucker pump, can also operate the stripper if a stripper pump fails. The primary and secondary systems can apply 5,000-psi hydraulic pressure, although normal operations will require much less pressure than that. The stripper is fitted with two hydraulic hoses that run back to the control cabin, one for packing and one for retracting. The stripper hydraulic system also acts as a backup system for the BOP and the injector head traction hydraulic systems. Figure 3-14 shows the backup controls.

20  |  Stripper

Haskell pump

The following emergencies can be met by these procedures. • loss of air supply: If the air supply is lost, or the air-operated portion of the Haskell pump fails, the pump can be operated manually using the hand lever supplied. Since the stripper pressure adjust control will no longer be active, the pressure will be controlled by manual effort and displayed on the pressure gauge located on the pump console. The system is then operated as normal. • failure of Haskell pump: If the Haskell pump fails to operate, either pneumatically or manually, the manual Rucker pump can be used to supply the systems. The supply pressure is controlled by manual effort.

20

3.5.1.2 Hydraulic pumps (normal operation)

STEP 02

Place the stripper control valve in the PACK position (see Fig. 3-16).

With the Haskell pump selected in the normal operating mode, the hydraulic system pressure is controlled as follows:

STEP 01: Select the stripper system to

be activated: Stripper 1 or 2 (see Fig. 3-15). Generally, System 2 is used with a tandem stripper when it is required. When the stripper selection valve is placed in the Stripper #1 position, the hydraulic pressure in Stripper #2 will remain static within the system, as long as it remains in PACK position. The No. 2 system pressure can be bled or reduced by selecting the neutral position.

Figure 3-16. Move Stripper Control Valve to PACK Position

STEP 03

Increase the stripper pressure. Regulate the Stripper Pressure Adjust Control to apply the required system pressure (Fig. 3‑17). The system pressure will be displayed on the system pressure gauge and on the Stripper #1 pressure gauge. The control should be adjusted so that the Haskel pump stalls when the desired pressure is reached.

STEP 04 Figure 3-15. Stripper Selection Valve in Stripper #1 Position

Decrease the stripper pressure. by placing the stripper control valve in the neutral position.

JET 13 - Coiled Tubing Pressure Control Equipment  |    21

3.6 Redressing side door stripper Redress a side door stripper after a CT operation as follows.

Step 01

Back out the two lock screws and open both doors wide (Fig. 3-18).

Figure 3-17. Regulating Stripper Pressure

3.5.1.3 Hydraulic pumps (emergency operation) Both stripper-system hydraulic pumps can be selected to supply backup hydraulic pressure to the BOP and injector head traction circuits. When the pumps are being used for this purpose, the stripper hydraulic system must be isolated from the pump pressure.

Figure 3-18. Open Door

Step 02 Pressure up the retract port (Fig. 3-19) and fully retract the piston, exposing the stripper insert. Remove the bushing clamp on top of the stripper by removing the cap screws. The piston moves from open to closed (Fig. 3-20).

3.5.2 Stripper quick pack or retract In older units, the stripper is packed and retracted using the Haskell air-over-hydraulic pump only. Recent models of CTUs have an option to tie directly into a 2,500-psi feed from the priority supply. This feed allows the stripper to be packed or retracted quickly, using the quick pack or retract control valve. Figure 3-19. Retracting Piston

22  |  Stripper

22

Figure 3-20. Piston Moving from Open to Closed

Figure 3-22. Removing Upper Brass Bushings

Step 03

Remove the stripper insert and nonextrusion ring(s) (Fig. 3-21).

Figure 3-23. Inspecting Brass Bushings for Wear Figure 3-21. Stripper Insert and Nonextrusion Rings

Step 04

Remove the upper brass bushings and inspect them for wear (Figs. 3-22 and 3-23).

JET 13 - Coiled Tubing Pressure Control Equipment  |    23

Step 05

Remove the lower brass bushings (Fig. 3-24) and inspect them for wear.

Figure 3-26. Installing Upper Brass Bushing, View 2

Figure 3-24. Removing Lower Brass Bushings

Step 06

Reinstall the lower brash bushing.

Step 07

Install upper brass bushing into piston (Figs. 3-25 through 3-27).

Figure 3-27. Installing Upper Brass Bushing, View 3

Figure 3-25. Installing Upper Brass Bushing, View 1

24  |  Stripper

24

Step 08

Step 09

Figure 3-28. Installing New Stripper Insert

Figure 3-30. Installing Bushing Clamp

Install a new stripper insert (Fig. 3-28), followed by the nonextrusion ring (Fig. 3-29).

Install the bushing clamp and install both cap screws to hold it in place (Fig. 3-30).

Figure 3-29. Installing Nonextrusion Ring

JET 13 - Coiled Tubing Pressure Control Equipment  |    25

Step 10

Step 11

Figure 3-31. Piston in Open Position

Figure 3-33. Making Up Lock Screws to Mechanically Lock

Pressure up on the upper packoff port and extend the piston down over the stripper insert (Fig. 3-31 and 3-32).

Close the doors around the piston above the step ring. Make up the lock screws to mechanically lock (Fig. 3-32).

Figure 3-32. Piston in Closed Position

26  |  Stripper

26

4.0  BOP This section explains the function and operating principle of the BOPs used in CT operations. It identifies and explains the main components of a BOP and lists the different models of BOPs.

Blind rams

4.1 Description The BOP is a secondary well control barrier in the pressure control equipment stack-up. Besides isolating wellbore pressure during an emergency situation, it also provides a means of cutting or holding the CT string if required. Movement of the CT string must be stopped when using any of the BOP functions. There are various configurations of BOP; the most common ram functions are • blind function: isolate wellbore pressure by sealing the full bore • shear function: shear (cut) CT string

Shear rams Slip rams Pipe rams

Figure 4-1. Quad BOP

A variety of BOPs are also used as tertiary pressure barriers, generally providing additional shearing and sealing capabilities for added safety during offshore operations. These BOPs include combi BOPs and single ram shear/seal BOPs. Schematics of various types of BOPs are shown in Fig. 4-2.

• slip function: grip CT string and support weight • pipe function: isolate wellbore pressure by sealing around annulus of CT string.

A quad BOP contains these four functions in one (see Fig. 4-1).

JET 13 - Coiled Tubing Pressure Control Equipment  |  27

Table 4-1. BOP Specifications Blind rams

BOP Nominal Size

3.06 in

4.06 in

Shear rams

Size of CT

2 in

2 7/8 in

Common working pressure ratings

10,000 psi 15,000 psi

10,000 psi 15,000 psi

Quad BOP Slip rams Pipe rams

Combi BOP

Blind/ Shear ram

Pipe/ slip ram

Shear/seal BOP

Blind/ shear ram

Figure 4-2. Most Common Types of BOP for CT Operations

In general, the lower BOP should be made up directly on the wellhead (using a wellhead adapter is required). If access is restricted at the wellhead, one short riser length may be needed between the wellhead and BOP.

4.2 Specifications BOPs are available in various sizes and are classified by the internal diameter of the bore. Each size can be dressed to accept a specific size of CT string. The specifications of the most common sizes of BOP can be seen in Table 4- 1.

28  |  BOP

As the tendency towards larger OD pipe has developed over the years, the 3.06-in and 4.06- in sizes have become the most common used by Schlumberger. Some larger sizes (6 5/8 in and 7 1/16 in) are in use in some locations for special applications, but these are not standard models. The most common types of CT BOPs have a working pressure of 10,000 psi. For CT operations on very high-pressure wells (Category III), BOPs with a working pressure of 15,000 psi are required. BOPs are hydraulically actuated and are run on a dedicated 3,000-psi BOP hydraulic circuit and accumulator from the CT cabin. The accumulator provides a reserve of hydraulic energy to enable the BOP to be operated (for a limited number of functions) following an engine shutdown or circuit failure. The backup systems in the CTU cabin consist of an air-driven pump and a manual, hand-operated pump. Schlumberger only operates H2S-resistant models of BOPs.

4.3 BOP types The following describe the various types of BOP used in CT applications.

A quad BOP is equipped with four sets of rams (from top to bottom): • blind rams • shear rams

4.3.1 Quad BOP The Texas Oil Tools (TOT) 10,000-psi working pressure, H2S-resistant quad BOP (Fig. 4‑3) is the BOP most commonly used by Schlumberger CT services. Upper flange/ connection adapter

• slip rams • pipe rams.

This model incorporates two equalizing valves; one each to equalize pressure across the blind rams and pipe rams. These valves are used to equalize the pressure across the ram in a controlled manner before it is opened, to protect the ram seal from damage.

Pressure port

Blind rams Shear rams Slip rams Pipe rams Kill port Lower flange/ connection adapter

Equalizing valve

4.3.2 Combi BOP A combi BOP has all the functions of a quad BOP, but in a shorter configuration (see Fig. 4‑4). It is equipped with two sets of dual‑function rams (from top to bottom): • blind-shear rams: cut CT and seal fullbore in one function • slip-pipe rams: grip CT and seal annulus pressure in one function.

Equalizing valve

Kill port

Equalizing valve

Figure 4-4. Combi BOP

Figure 4-3. Quad BOP

The main advantage of the combi BOP over the quad BOP is that it provides the same four functions in a shorter body. This reduction in

JET 13 - Coiled Tubing Pressure Control Equipment  |  29

length is often important when rigging up with height restrictions. The disadvantage of a combi BOP is that it provides less flexibility in its function. The four functions cannot be operated independently as they can in a quad BOP.

4.3.3 Shear-seal BOP Shear-seal BOPs (Fig. 4-5) are single ram BOPs used as tertiary barriers. The shear-seal BOP is equivalent to the upper ram of a combi BOP, but these single rams are stronger and are offered in larger bore sizes.

Seal element

Retract

Pack off

Figure 4-6. ABOP

ABOPs seal on almost any shape or size of cylinder—drill pipe, tool joints, drill collars, casing, or wireline. Figure 4-5. Shear-Seal BOP

They are typically mounted on the top of the wellhead if the quad or combi BOP cannot be installed directly on the wellhead. Shear-seal BOPs are primarily used in offshore operations.

4.3.4 Annular BOP (ABOP) Annular BOPs (ABOPs) are connected on the top of the wellhead and serve as tertiary barriers (Fig. 4-6). They are similar in design and function to the Hydril™ annular presenter found in drilling rig pressure control stacks.

30  |  BOP

4.3.5 CIRP BOP The CIRP* completion insertion and retrieval under pressure system is a Schlumbergerdeveloped system for deploying (making up) or retrieving long perforating gun strings under wellhead pressure. This system is often used in CT perforating operations. The CIRP system uses a special CIRP deployment stack, commonly known as a CIRP BOP. This stack is not truly a BOP because it does not contain any pressure-sealing rams. It is actually a set of special function rams in a BOP body, which are designed for making up and breaking special CIRP connectors in long gun strings (Fig. 4-7).

More information on the CIRP system can be found in JET Manuals 16 (InTouch Content ID# 4221749) and 32 (InTouch Content ID# 4221770).

4.4 BOP components The following are the main components of the BOP assembly.

4.4.1 BOP body The BOP body is manufactured from one solid block, to avoid the weaknesses associated with joints, connections, and welds. Flanged connections are used on top and bottom, and for the side port.

Gun Rack Guide ram actuator

Rack actuator

No go ram actuator

Lock actuator

Lock CIRP connector Gun

Figure 4-7. CIRP Deployment Stack for Deploying Gun Strings

JET 13 - Coiled Tubing Pressure Control Equipment  |  31

Most CT BOP models have an internal hydraulic system. All hydraulic fluid passages are machined into the BOP body and ram bonnets. This feature reduces the need for external piping, which in turn minimizes the risk of damage to the hydraulic system during handling of the BOP.

Hydraulic connectors Front

Right hand

Left hand Back

4.4.2 BOP rams The components for each BOP ram are assembled onto a stainless steel ram body. The design of the ram body is specific for the ram function for which it will be used. This design allows the same ram body to be used over a range of CT sizes by changing the relevant ram inserts. The ram body is attached to the actuator rod by an off-centered slide arrangement (see Fig. 4-8) that ensures that the ram and actuator are correctly assembled when fixed to the BOP body.

Side port

Figure 4-9. Convention to Distinguish RH from LH Parts

4.4.2.1 Blind rams The BOP blind rams are used to seal the entire wellbore, using front and rear seals (Fig. 4-10). They are used to contain wellhead pressure. The rams only hold pressure from below. Rear seal Front seal reinforcing

Front seal

Blind-ram body

Actuator rod

Retainer bar

Ram Body

Figure 4-8. Ram Body Slides onto Actuator Rod

When redressing a BOP, it is important to understand the standard definition of right hand (RH) and left hand (LH) used to distinguish between parts. For example, the RH and LH shear rams blades are different. The convention for RH and LH is shown in Fig. 4-9. The side port (or kill port) is always located on the back of the BOP. 32  |  BOP

Figure 4-10. Blind Ram with Front and Rear Seals

When the blind rams are closed, the configuration of the seals on the ram body is designed to use the differential pressure from below to create additional force to keep the rams closed (see Fig. 4-11). This feature helps prevent the blind rams from being opened if there is pressure differential across them.

Low pressure above the ram set

Pressure differential acting to maintain closure

4.4.2.2 Shear rams The BOP shear rams (Fig. 4-12) are designed to cleanly cut the CT string and any internal electrical cable if present.

Pressure differential acting to maintain closure

High pressure below the ram set

BOP body

Figure 4-11. Differential Pressure to Keep Blind Ram Closed

Caution: Never attempt to open the blind rams when there is high pressure below the rams and low pressure above. The sealing face on the blind rams would be severely damaged if it were opened with a pressure differential across the rams. An equalizing valve is fitted to the blind rams that allows the pressure to be equalized across the rams before opening them.

Figure 4-12. Set of Shear Rams

Note: Shearing is used only in emergency situations.

The blades minimize pipe deformation during cutting to leave a good profile for later pipe retrieval.

Note: After closing the rams hydraulically, the blind rams can be manually locked using the handwheel at the end of the actuator. They must be manually unlocked before opening hydraulically. To prevent accidental activation, the controls for the blind rams in the CTU cabin have double lockout protection: a cover must be opened and a pin must be removed before the control can be activated. The same blind rams are used in a BOP no matter what size CT string is being used. Because the rams are fullbore, they can only be activated when no CT is across the rams.

The shear rams do not seal the wellbore. If the wellbore pressure needs to be sealed in an emergency situation, the CT string must be pulled up before shutting the blind rams.

Note: Take care when assembling shear rams because the left and right ram bodies are different.

JET 13 - Coiled Tubing Pressure Control Equipment  |  33

Booster cylinder assemblies have been added to the shear rams on 2.50-in and 3.06-in CT BOPs (Texas Oil Tools EC and EH models) to give increased shearing force. The original design of these BOPs was developed in the early 1980s when smaller and thinner-walled CT strings were being used.

4.4.2.4 Pipe rams The BOP pipe rams are shaped to close around and seal the annulus between the CT string and the wellbore (see Fig. 4-14). They are used to contain wellhead pressure when the CT string is in the hole.

The newer EK model of BOP has been designed with large shear actuators and heavyduty shear blades to be able to cut high CT wall thicknesses. Like the blind rams, the controls for the shear rams have double lockout protection to prevent accidental activation.

4.4.2.3 Slip rams Slip rams (Fig. 4-13) are designed to grip the CT string and hold it against downward (weight) and upward (snubbing) forces. Figure 4-14. Pipe Ram Seals Around CT String

Similar to the blind rams’ function, the pipe rams only hold pressure from below. They are also designed so that pressure from below helps keep the rams closed. This design helps prevent the blind rams from being opened while there is pressure differential across them.

Figure 4-13. Slip Ram

The slip rams can create minor surface damage on the CT string. Since marks and damage on the CT string surface can result in a string failure, it is important that the slip rams are used only when needed and that the slip area is designed to cause minimal damage to the string.

34  |  BOP

As with the blind rams, you should never attempt to open the pipe rams if there is a pressure differential across the rams. The pipe rams are fitted with an equalizing valve to allow the pressure to be balanced above and below the ram before opening. An example of when the pipe rams are used is when the stripper element needs to be changed during a CT run. When the CT string movement has been stopped, the pipe rams can be closed to seal around the pipe. The pressure above the pipe rams can be bled off to allow safe access to change the stripper inserts.

Note: The CT string movement must be stopped before closing the pipe rams. These rams can be manually locked after being closed hydraulically. They must be manually unlocked before opening hydraulically.

4.4.3 Ram bonnet and actuator The ram body and actuator form a complete assembly that must be removed to inspect or replace the ram bodies. Each assembly is secured to the BOP body by four studs and capped nuts. The main features of a ram bonnet and actuator assembly are identified in Fig. 4-15.

Well pressure seals and hydraulic system seals are separated by a vent and weep hole (Fig. 4‑16) to prevent accidental pressuring of the hydraulic system by well pressure. The ram position (open/closed) is indicated by the ram indicator rod, which is attached to the actuator piston. Ram function tests are carried out before every CT operation to ensure that the rams are opening and closing in accordance with the controls inside the CTU cabin. One operator will always verify the movement of the ram by watching the ram indicator rods.

Closing tube Indicator pin

Hydraulic cap Cylinder Bonnet Bolt

Manual lock wheel

Bonnet

Figure 4-15. Main Features of Actuator

JET 13 - Coiled Tubing Pressure Control Equipment  |  35

Note: The manual locking mechanism must be fully retracted before hydraulically opening the ram.

Caution:

Figure 4-16. Checking Weep Hole for Leaks

4.4.3.1 Manual operation The handwheel at the end of each actuator can be used • to close the ram in case of a failure of the hydraulic system • to lock the ram if it has been hydraulically closed.

On a Texas Oil Tools quad BOP, it takes approximately 19 or 20 turns of the handwheel to fully close a ram.

Note: It is important to count the number of turns of the handwheel when closing a ram, to ensure that it is fully closed.

The same procedure is used to lock a ram that has been hydraulically closed. A ram should be locked if it is planned to be closed and left unattended for a prolonged period of time. The handwheel cannot be used to open a ram; a ram can only be opened hydraulically.

36  |  BOP

Severe damage will result to the internal components of the actuator if an attempt is made to hydraulically open the actuators while the manual locks are closed. To avoid accidental opening of the ram while manually locked, it is important to lock out the BOP controls in the CTU cabin. This action is particularly important when crews are working in shifts.

4.4.4 Equalizing valves When the blind or pipe rams are used to hold pressure from below, it is important to equalize (balance) the pressure above and below the rams before reopening them. This equalization is done with the aid of an equalizing valve. Opening the equalizing valve exposes a small orifice in the BOP body that opens a pathway between the bore of the BOP above and below the closed rams. This pathway allows the pressure to slowly build up above the closed blind or pipe ram. When the pressures above and below the rams are equal, the valve can be closed again and the rams can be opened safely. Figure 4-17 identifies the features of an equalizing valve assembly.

Blind ram or pipe ram isolating the BOP bore

Valve outlet above the ramset Equalizing valve allen key socket

refers to the ability to pump through this port to kill a well. Weco 1502 union

BX 152 Ring Gasket

Valve inlet below the ram set

Figure 4-17. Equalizing Valve Assembly

The reasons for using an equalizing valve are as follows: • Opening a ram without equalizing the pressures will damage the face of the sealing ram. • The BOP hydraulics are not strong enough to open the rams against the additional closing force exerted by the wellbore pressure.

The equalizing valve is opened and closed with a 1/4-in allen key.

Note: The equalizing valve has a left hand thread, which means it is opened by turning it clockwise and closed by turning it counterclockwise.

4.4.5 Side port The side port (see Fig. 4-18), often called the kill port, is a flanged connection on the front of the BOP body, which can be used to pump fluids into the CT/tubing annulus, or through the cut CT string if the BOP shear rams have been activated in an emergency. The name kill port

Figure 4-18. Side Port Flanged onto BOP Body

On 3.06-in and 4.06-in, 10,000-psi BOP models, the kill port is a 2 1/16-in, 10k flange, which is generally provided with an adaptor to a 2-in 1502 Weco connection for easy rig up of a pumping line. In Category I and II operations, the kill port is generally isolated with two plug valves during operation. The electronic pressure sensor for WHP is generally rigged up between these valves.

4.4.6 Pressure port and debooster A pressure port is located on the BOP body above the blind rams. This port allows WHP to be monitored only when the blind rams are open. The pressure port is connected by a smallbore steel tube to a pressure debooster fitted on the BOP body (see Fig. 4-19). Steel tube is used instead of hose because it is less likely to be mechanically damaged and is more fireresistant. The connections on both ends of the tube are high-pressure, metal-to-metal, seal autoclave fittings.

JET 13 - Coiled Tubing Pressure Control Equipment  |  37

4.5 BOP hydraulic system BOP rams are hydraulically actuated, although the rams may also be actuated and locked manually under certain conditions. Since the BOP is a major component of well control equipment, it can be operated from the dedicated hydraulic supply circuit or one of several backup methods.

4.5.1 BOP hydraulics The BOP actuator pistons are dual acting, which means they hydraulically both open and close the BOP rams (see Fig. 4-20). Figure 4-19. Pressure Debooster Connected to Pressure Port

The function of a pressure debooster is to hydraulically reduce the WHP by a factor of 4:1. This reduction reduces the pressure within the hydraulic gauge hose running to the control cabin, which means that if the WHP is 5,000 psi, the pressure in the hose running to the control cabin will be 5,000/4 = 1,250 psi. The WHP gauge in the cabin is calibrated to display a WHP of 5,000 psi from the 1,250 psi pressure in the hose.

The rams are attached to an actuator rod and the actuator is in turn connected to the piston actuator. When hydraulic pressure is directed to the close port, the pressure is directed through the external closing tube on the two opposite rams. This pressure then acts on the brass piston in the actuator, forcing the piston actuators to move towards each other to close the BOP rams. As they move, they pull the indicator pin inside the actuator arm, giving a visible indication that the rams have closed. When hydraulic pressure is directed to the open port, the pressure acts on the inside of the brass piston in the actuator, forcing it to move outwards into the open position. The piston actuators move away from each other, to open the BOP rams. As they move, they push the indicator pin, giving a visible indication that the rams have opened.

38  |  BOP

Hydraulic passages drilled through bonnet

Adapter

Closing tube

Retainer

Elbow

Set screw & woodruff key

Hex retainer Indicator

Actuator rod

Seal Piston guide Bonnet

Seal

Piston Rod nut

Bearing assembly Sleeve Retainer Stem nut Hydraulic Cylinder Key cap

Piston retainer

Figure 4-20. Ram Actuator

4.5.2 BOP drive system Because the BOP is a major component of well control equipment, it can be operated from several different power supplies.

4.5.2.1 Power pack supply The main power supply is a dedicated 3,000- psi BOP hydraulic circuit in the CTU power pack. This supply must be ON at all times during a CT operation.

Rucker pump Haskell pump

4.5.2.2 Emergency supplies If an engine shuts down, the emergency supplies described below can be used to charge the BOP supply. Haskell air-over-hydraulic and manual systems Turning the BOP hand pump supply valve on allows the operator to use the stripper hydraulic supplies for the BOP (see Fig. 4-21).

Figure 4-21. Using Stripper Hydraulic Supplies for BOP

If air pressure is lost or the pneumatic portion of the Haskell pump fails, the Haskell pump can be operated manually. The Haskell pump is also backed up by a separate Rucker hand-operated pump, which JET 13 - Coiled Tubing Pressure Control Equipment  |  39

may also be used to charge the BOP supply circuit.

Note: While charging the BOP circuit with either of these systems, the stripper hydraulic circuit must be isolated from any pressure fluctuations by closing the stripper system supply valve.

Figure 4-23 shows an accumulator during normal operations. When the hydraulic system pressure is lost, the pressurized bladder expands to fill the space. This action retains pressure in the hydraulic system for a limited number of functions, until the bladder has reached its maximum size. At this stage, its stored energy has been completely used up.

N 2 gas Hydraulic oil

Accumulator The BOP accumulator allows limited operation of all BOP functions following the shutdown of the power pack engine. Standard CTUs are fitted with a 38-L [10- galUS] capacity bladder-type accumulator, which is precharged with nitrogen gas. Figure 4-22 identifies the features of a BOP accumulator. 2-in NPT connection

Accumulator bottle

Bladder Gas valve

During standard operations, the 3,000 psi hydraulic system pressure, compresses the bladder of N 2 gas Hydraulic oil

N 2 gas

When accumulator is used, the pressure decreases inside the accumulator bottle. The bladder expands, pushing the hydraulic fluid out of the bottle.

Figure 4-23. BOP Accumulator Function

Schlumberger specifies that BOP accumulators must be sized large enough to provide enough stored hydraulic energy to perform three functions on all BOP rams: open, close, and open again.

Discharge valve

Protective cap

Figure 4-22. Commonly Used Accumulator Assembly

The bladder of nitrogen gas is compressed during normal operations by the hydraulic system pressure. When hydraulic system pressure is lost, as in the case of a power pack engine shutdown, the bladder can release the hydraulic power it has stored.

40  |  BOP

4.6 Redressing the BOP The pictures in this section were taken during the redress of one quad and one combi BOP.

4.6.1 Quad BOP A 3.06-in quad BOP is shown in Fig. 4-24. Note the boosters on the shear rams on this model.

Figure 4-26. Removing Handwheel

Step 03

Removing the blind ram actuator (Fig. 4-27). Larger sizes of BOP will require two personnel to lift the actuator.

Figure 4-24. 3.06 in Quad BOP

Step 01

Removing the bolts which hold the bonnet and actuator in place (see Fig. 4-25).

Figure 4-27. Remove Blind Ram Actuator

Figure 4-25. Bolts Holding Bonnet and Actuator in Place

Step 02

Removing the handwheel on the shear rams (Fig. 4-26). This handwheel obstructs the removal of the blind ram actuator. JET 13 - Coiled Tubing Pressure Control Equipment  |  41

The blind ram body can be seen protruding from the bonnet in Fig. 4-28.

Step 05

Figure 4-28. Blind Ram Body

Figure 4-30. Retainer Bar and Front Seal Sliding Out of Blind Ram Body

Step 04

The retainer bar and the front seal slide out of the blind ram body (see Fig. 4-30).

Holding the blind ram actuator firmly in a vice for inspection during the redress (Fig. 4-29).

Step 06

Figure 4-29. Holding Blind Ram Actuator in Vice

Figure 4-31. Inspecting Shear Ram Actuator

42  |  BOP

Holding the shear ram actuator firmly in a vice for inspection (see Fig. 4-31).

Step 07

Step 08

Figure 4-32. Sliding Shear Ram Body off Actuator Rod

Figure 4-34. Front and Rear Seals and Retainer Bar

Sliding the shear ram body off the actuator rod (see Fig. 4-32).

The slip ram insert is visible with its retaining pin; see Fig. 4-33.

The front and rear seals and the retainer bar from the pipe ram (see Fig. 4-34).

Step 09

The pipe ram equalizing valve is removed for inspection (see Fig. 4-35).

Figure 4-33. Slip Ram Insert with Retaining Pin

Figure 4-35. Removing Pipe Ram Equalizing Valve

JET 13 - Coiled Tubing Pressure Control Equipment  |  43

Reassemble the BOP by following these steps in reverse.

4.6.2 Combi BOP Larger sizes of BOP such as the 4.06-in combi BOP shown in the following photos are designed with ram change rods. This feature allows the ram to be serviced without lifting the ram actuator itself.

Step 01

(Fig. 4-36).

Step 02

Sliding the ram actuator outwards on the ram change rods, where it remains supported during servicing (Fig. 4-37). You can see here that this ram is not dressed for use; it is in the training school and has no ram fitted on it.

Fitting the ram change rods

Figure 4-37. Ram Actuator Sliding Out on Ram Change Rods

Step 03 Assembling a combination pipeslip ram (Fig. 4-38).

Figure 4-36. Fitting Ram Change Rods

Figure 4-38. Assembling a Combination Pipe-Slip Ram

44  |  BOP

Step 04 Fitting the pipe-slip ram onto the actuator rod; Fig. 4-39.

Figure 4-41 shows a combination blind-shear ram: note the space for the blind seal.

Figure 4-41. Combination Blind-Shear Ram Figure 4-39. Fitting a Combination Pipe-Slip Ram

The pipe-slip ram is in position; see Fig. 4-40.

Reassemble the BOP by following these steps in reverse.

Figure 4-40. Pipe-Slip Ram in Position

JET 13 - Coiled Tubing Pressure Control Equipment  |  45

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46  |  BOP

5.0  Auxiliary Pressure Control Equipment This section explains the general principles of other pressure control equipment that are commonly used by Schlumberger as part of CT operations.

Note: For more detailed information, you should consult the manufacturer’s technical manuals.

5.1 Quick latch union Caution: During rig up on a CT operation, stabbing the injector head and stripper onto the BOP is hazardous. In many cases, an operator is close to the connection, assisting in stabbing the quick union. This proximity creates a risk of a personal injury.

Figure 5-1. Hydraconn Union

Using a Hydraconn union (see Fig. 5-1) from Texas Oil Tools (TOT), sometimes known as a quick stab or quick latch (QL; see Fig. 5-2), can reduce the exposure of personnel to risk. The QL is a two-piece hydraulic latching union, which allows the stripper to be stabbed onto the BOP without operator assistance.

Figure 5-2. QL Union

JET 13 - Coiled Tubing Pressure Control Equipment  |  47

The QL provides a quicker and safer means of connecting a lubricator or injector to the wellhead riser than threaded unions. The QL has matching conical surfaces to provide stabbing and self-alignment of the injector. The upper (male) part of the Hydraconn union is made up to the bottom of the stripper with a flange or Bowen quick union. The lower (female) part of the Hydraconn is generally flanged to the top of the BOP.

5.1.1 Operation The female part has a tapered seal bore, which makes it easy to stab the connection. To make up the QL, the male part of the QL is simply lowered inside the lower female part. The latch inside the female engages on the male profile, locking it in place. After the CT operation, you need to break the QL connection to rig down the CT. The QL also has mechanical locking screws to prevent accidental release of the QL. The QL can be unlocked by first unscrewing the mechanical screws and then applying hydraulic pressure through the hydraulic port with a hand pump. This pressure will release the latch inside the QL and allow the injector and stripper to be released by lifting with a crane.

5.2 Side door deployment tool The side door deployment tool (SDDT) is pressure control equipment used to deploy long toolstrings. It is actually a hydraulically actuated window in the pressure control equipment stack that can be opened to allow the BHA connections to be made, without breaking the lubricator stack (see Fig. 5-3). Using an SDDT allows safe access for making up tools without needing to work under a suspended load.

48  |  Auxiliary Pressure Control Equipment

Figure 5-3. Closing the SDDT Window

See JET 36, CT Downhole Tools, InTouch Content ID# 4221770, for more detailed information on tool deployment using a SDDT.

5.3 Load-bearing quick connect The load-bearing quick connect is designed to safely and quickly stab the injector head to the drill pipe or flow head when working on a drill ship or semisubmersible rig. Texas Oil Tools manufactures the JHS™ model load-bearing quick connect with the following features (see Fig. 5-4): • tapered bore to allow for easy stabbing even in rough seas • strong design of latching system can take entire weight of drillstring. Some models have tension rating of greater than 1.5 million lbm (682 metric tons). • three separate seals in separate bores, each rated to the pressure rating of the quick connect.

section (male connection). The latch on the stinger engages on the profile inside the skirt, locking it in place. The quick connect can be released by applying 600-psi hydraulic pressure from a hand pump. The latching system will only release when the quick connect is not in tension or compression and has no wellhead pressure. A backup manual release system exists if the hydraulic release system fails. See the Texas Oil Tools manual for more information on this.

5.4 Quick test safety sub (QTSS) Caution: Pressure testing the surface pressure control equipment is forbidden with any explosive guns or chemical cutters in the riser, as doing so could lead to the detonation of the guns or the ejection of the very toxic chemicals from a chemical cutter.

Figure 5-4. JHS Quick Connect with Skirt (Top) and Stinger (Bottom)

The sealing system is specially designed to prevent leakage caused by side loading when the drill vessel responds to waves.

The basic principle of the quick test safety sub (QTTS), shown in Fig. 5-5, is that it allows you to pressure test the pressure control equipment without introducing pressure inside the stackup. Note the fitting for the external hand pump at the connection in Fig. 5-5.

The Texas Oil Tools JHS Series hydraulic releasing connector is available in 3.06-in, 4.06-in, and 5.12-in sizes in pressure ranges of 5,000 to 15,000 psi.

5.3.1 Operation The large taper on the skirt makes it easy to stab the connection even in rough conditions. The load-bearing quick connect is latched by simply lowering the skirt over the lower stinger

JET 13 - Coiled Tubing Pressure Control Equipment  |  49

5.4.1 Specification The QTSS can be manufactured with quick unions or flanged connections at the top and bottom, according to the location requirements. The main feature of the QTTS is the special quick test joint at the center. This is a modified quick union with a double O-ring seal. The design of the QTTS allows the integrity of the O-ring seals to be checked with an external hand pump (see Fig. 5-6) without an internal pressure test. This feature means that the connection can be tested very quickly every time it is broken and remade up.

Figure 5-5. QTTS

The QTTS is mainly used in CT operations where perforating guns or chemical cutters will be run, but it can also be used to reduce pressure testing time on multirun CT operations. It is estimated that a QTSS can reduce the time needed to pressure test the stackup by more than 30 min per run. On expensive drilling rigs, saving 30 min can result in saving a lot of money for the client! The main advantages of the QTSS are that it • eliminates the risk of pressure testing with perforation guns or chemical cutters in the riser • saves rig time on pressure test for all multiple run CT jobs and especially multiple run perforation jobs • avoids contaminating the well with pressure-test fluids. 50  |  Auxiliary Pressure Control Equipment

Figure 5-6. Hand Pump Pressure Test Connection

5.4.2 Operation of QTSS The QTTS should be placed in the pressure control equipment stack at the position of the joint normally opened to insert and retrieve the tools or guns from the well. Before introducing a perforating gun or chemical cutter into the riser, the entire pressure control equipment stack should be pressure tested internally. After a successful pressure test, the pressure should be bled off from the pressure control equipment stack. Then, you can break open the

quick test connection on the QTTS just as you would a standard pin-and-collar connection. The gun or chemical cutter can then be deployed inside the riser and the quick test connection can be made up again. At this stage, the pressure control equipment stack has all been pressure tested, but you need to confirm the integrity of the quick test connection that was broken and made up again. With a normal QL union, you would need to test the entire pressure control equipment stack again internally. But the special feature of the QTSS allows the connection to be pressure tested with an external hand pump. This is achieved by testing only the seal of the joint by pumping between the O-rings. You can pressure test this joint by connecting a small hydraulic hand pump with a hydraulic hose to the port on the special quick test joint of the QTSS (see Fig. 5-6). Using the hand pump, increase the pressure to the required test pressure (the same as the test pressure used earlier on pressure control equipment stack; you should have received a printout of all test pressures from the field engineer). If a satisfactory pressure test is achieved on this joint, the whole stackup is pressure tested without having to pressure test with a gun in the riser.

JET 13 - Coiled Tubing Pressure Control Equipment  |  51

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52  |  Auxiliary Pressure Control Equipment

6.0  Risers and Lubricators Risers and lubricators are sections of blank pipe with standard end connections that are used as part of the pressure control equipment stack for one of the following reasons: • provide space for deploying downhole tools

the BOP and the wellhead in certain circumstances, but a lubricator cannot. In high-pressure applications, only a flanged riser can be used between the upper and lower BOPs.

• position BOP and injector head in accessible position (often known as spacing out).

The terms riser and lubricator are often confused. • A lubricator (see Fig. 6-1) has pin-andcollar unions (also known as quick unions) as end connections, such as Bowen, OTIS, or TOT unions. Lubricators are generally used between the BOP and stripper to provide extra length for deploying downhole tools under pressure or to place the injector head at a convenient height.

Figure 6-2. Riser

6.1 Specification Risers and lubricators come in many sizes, but the main sizes used for CT operations are • 3.06 in • 4.06 in • 5.12 in • 6.38 in • 7.06 in.

They come in many lengths, but the standard lengths are 4, 8, and 12 ft. Figure 6-1. Lubricator

• A riser (see Fig. 6-2) generally has flanged end connections. Risers are often used on offshore platforms to place the BOP and injector head at convenient and accessible heights. A riser can be placed between

Risers and lubricators come in various working pressure ratings: 5,000 psi, 10,000 psi, and 15,000 psi are the most common ratings used in CT operations.

JET 13 - Coiled Tubing Pressure Control Equipment  |  53

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54  |  Risers and Lubricators

7.0  Crossovers and Connections This section describes crossovers and the main types of connection Schlumberger uses on pressure control equipment:

Or a crossover may adapt between different types of connection, for example, see Fig. 7-2.

• flanged • quick union (or pin-and-collar) • threaded.

7.1 Crossovers Crossovers or adaptors are used in the pressure control stack to adapt between different connections. They are sometimes denoted as XO in drawings or text. Crossovers can be different sizes of the same type of connection they are connecting, for example, see Fig. 7-1. Figure 7-2. Flange-Quick Connect Crossover

Crossovers are an important piece of pressure control equipment and must be purchased and tested in accordance with the Well Services Safety Standards. Before using a crossover, follow these guidelines. • Ensure that, on each flange, the connection size and pressure rating is clearly marked, as well as whether it is standard or H2S service. • Using the crossover serial number, ensure that it has been tested according to WS Safety Standard 23 within the past 12 months.

Figure 7-1. Flange-Flange Crossover JET 13 - Coiled Tubing Pressure Control Equipment  |  55

• Check connections and seal areas for damage or wear.

7.2 Flanged connections Flanged connections are bolted connections with a metal-to-metal seal provided by a gasket ring. In CT operations, flanged connections are considered the strongest and most reliable connection available. Schlumberger specifies the use of flanged connections in critical situations, such as high-pressure CT operations and in the presence of H2S. When made up properly and pressure tested, they are extremely unlikely to fail and they do not rely on rubber O-ring seals. Flanged connections are built to American Petroleum Institute (API) specifications. API specifies API 6B and API 6BX flanges for wellhead equipment. Figure 7-3 illustrates the main differences between these flange types.

API 6BX flanges have a raised face on one or both flange faces and the flanges are made up face to face to form a closed flange. The force of the bolts reacts primarily on the raised face of the flange. The ring gaskets used in API 6BX flanges are BX type. The API 6BX flange is the type of flange most commonly found on BOPs, as it covers 10,000 psi and 15,000 psi ratings. R ring gaskets are energized only by the makeup bolt force of the connection. RX and BX gaskets provide a pressure-energized seal. RX and BX ring gaskets are not interchangeable. All BX rings have a pressure passage while only selected RX rings are machined with the passage. Figure 7-4 illustrates the different ring gasket profiles. R Ring gaskets- oval or octagonal in cross section

Close face Standoff

Pressure passage RX ring gasket–asymmetric octagonal cross section

BX ring

R or RX ring API 6B Flange

Some RX ring sizes have a pressure passage machined between faces.

Figure 7-4. Ring Gasket Profiles API 6BX Flange

Figure 7-3. API 6B and API 6BX Flange Connections

7.2.1 Flange types and ring gaskets API 6B flanges are not designed for face‑to‑face makeup and are sometimes referred to as open flanges. The force of the bolts reacts on the metal ring gasket. The ring gaskets used in API 6B flanges are R or RX type (see Fig. 7-3). Flanges rated for 3,000 psi or 5,000 psi are generally API 6B flanges.

56  |  Crossovers and Connections

BX ring gasket–octagonal, all sizes are machined with a pressure passage

Note: Gasket rings become slightly deformed during makeup and they should not be reused.

The connections come in a large range of sizes and pressure ratings. Table 7-1 lists a range of common flange sizes and pressure ratings. Table 7-1. Gasket Ring for Common API Flanges

3,000 psi

5,000 psi

10,000 psi

15,000 psi

2-1/16 in

R 24 / RX 24

R 24 / RX 24

BX 152

BX 152

2-9/16 in

R 27 / RX 27

R 27 / RX 27

BX 153

BX 153

BX 154

BX 154 BX 155

3-1/16 in 3-1/8 in

R 31 / RX 31

R 35 / RX 35

4-1/16 in

R 37 / RX 37

R 39 / RX 39

BX 155

5-1/8 in

R 41 / RX 41

R 44 / RX 44

BX 169

7-1/16 in

R 45 / RX 45

R 46 / RX 46

BX 157

BX 156

9 in

R 49 / RX 49

R 50 / RX 50

BX 157

BX 157

11 in

R 53 / RX 53

R 54 / RX 54

BX 158

BX 158

JET 13 - Coiled Tubing Pressure Control Equipment  |  57

7.2.2 Making up flanges When making up a flange, it is important to follow the proper procedure. • initial flange alignment • tightening sequence used to tighten the bolts. Do not tighten the first bolt fully, and move on to the next one. Instead, make up the bolts in a series of steps using a star pattern as shown in Fig. 7-5. This method helps achieve an equal distribution of the load around the flange.

Load-indicating washer. Dimples flatten at correct load.

Hardened backup washer

Figure 7-6. HPHT Bolt System

7.2.3 Postjob maintenance After each use, the ring grooves should be cleaned, inspected, and greased before storage, to prevent corrosion. Ensure that each flange has its size and pressure rating clearly marked on it, as well as whether it is for standard or H2S service.

Figure 7-5. Bolt Tightening Sequence

For high-pressure, high-temperature (HPHT) applications, a special HPHT bolt tension system should be used (see Fig. 7-6). This system uses a special load-indicating washer and a hardened backup washer to ensure that the correct load is placed on each bolt.

58  |  Crossovers and Connections

7.3 Pin-and-collar unions Pin-and-collar connections are the most common connection in the well service industry and are commonly referred to as quick unions or hand unions (see Fig. 7-7).

different models, which often include the type and position of the sealing O-ring, internal dimensions, and machined finish. Thread OD Sealbore diameter Mating shoulders

Pin assembly

Collar Seal arrangement and location

Thread pitch Box assembly

Figure 7-7. Pin-and-Collar Union

The main advantage of these connections is the speed of making them up and breaking them out. A connection can generally be made up by one operator in approximately 2 min. It is for this reason that they are generally used in the position in the pressure control equipment stack where the lubricator will be broken and made up again several times. In most cases, the connections between the stripper and the upper BOP are pin-and-collar connections.

Note:

Collar

Nominal ID

Figure 7-8. Cross-Section of Pin-and-Collar Union

Note: Because some quick unions look very similar, it is very important to ensure that all equipment with quick unions and adapters are clearly identified and labeled, to avoid finding out on the field that your unions and adaptors do not match.

WS Safety Standard 22 specifies that these unions may not be used below the lower BOP.

7.3.1 Types of pin-and-collar union Various models of pin-and-collar union have been developed by different companies. Several design differences exist between the

JET 13 - Coiled Tubing Pressure Control Equipment  |  59

The most common unions used in CT applications are shown in Table 7-1.

operator of jacking frame), so that the pin is not lowered prematurely, trapping your hands.

Table 7-1. Most Common Unions Used in CT Applications

Name

Code

Bowen

CB

OTIS

CO

TOT

CQ

The codes listed in Table 7-1 are combined with a number to specify a particular type and size of quick union. For example, two of the most common pin-andcollar you will see on CT operations are • CB34: 3.06-in, 10,000-psi working pressure Bowen union • CB44: 4.06-in, 10,000-psi working pressure Bowen union

7.3.2 Making up pin-and-collar unions Some unions have a top thread that will hold the collar. In other cases, use bungee cords or similar devices to hold the collar up (see Fig. 7-9).

Note: Be very careful when making up quick unions, as they have caused many hand injuries in the past. When stabbing the male pin into the box, do NOT hold up the collar with your hands. The collars are heavy and if they fall, your fingers may become trapped underneath. Ensure that you have good communication with the person lowering the pin (crane operator or

60  |  Crossovers and Connections

“Bungee”cord and hooks attached to injector head frame

Figure 7-9. Bungee Cord Holding Up Collars

7.3.3 Postjob maintenance After each use, follow these guidelines: • Clean and inspect collar threads. • Clean and inspect seal areas, seals and backup rings. • Ensure collar retaining arrangement is secure. • Use appropriate thread protectors during storage • BOPs with a quick union adaptor below them should be stored on a matching stump.

7.4 Threaded connections In some cases, it will be necessary to rig up CT onto a threaded connection. This is generally the case, if rigging up onto a string of drillpipe, a temporary well testing flowhead, or some low pressure wellheads.

Stub ACME thread

Pin end of connection may be part of a pin and collar adapter or attached to a CT hydraulic connector.

Note: WS Safety Standard 22 places restrictions on the use of threaded connections in CT operations. They may only be used for lowpressure operations where there is no danger of dangerous H2S gas. For exact requirements, refer to WS Safety Standard 22.

Box end of the connection may be machined into the temporary flowhead body.

O-ring seal may be single or double.

Figure 7-10. Stub ACME Thread

7.4.1 Types of threaded connection Some threaded connections have a pressuresealing thread, while others rely on independent seals or O-rings to provide a pressure seal. Threaded connections include drillpipe threads such as EUE and regular threads, and stub ACME (SA) threads with an O-ring seal (see Fig. 7-10), which are commonly found on temporary well test trees. See JET 36, CT Downhole Tools, for more information on threads.

7.4.2 Making up threaded connections All threaded connections have a recommended makeup torque. Torque is a measure of the rotational force applied to make up the thread. While it may be possible to make up smaller threaded connections with pipe wrenches, larger threaded connections require much higher torque. In this case, a chain tong or hydraulic tong is needed to achieve the recommended makeup torque.

7.4.3 Postjob maintenance Perform this maintenance after every job. • Clean and inspect thread, seals and seal areas for damage. • Install thread protectors for storage. • Make sure that the size, model, and pressure rating is clearly marked on the body for future use. • Make sure that the service is clearly marked as standard service or H2S service.

JET 13 - Coiled Tubing Pressure Control Equipment  |  61

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62  |  Crossovers and Connections

8.0  Pressure Testing It is crucial that all CT operations be performed safely and reliably. Pressure testing verifies that the equipment, as rigged up, will withstand the expected treatment pressures and maintain pressure control. Therefore, it is essential that CT personnel correctly pressure test the equipment before any well intervention. During rig up, the CT equipment, hard lines, and anything that will be used to perform the treatment are pressure tested following the guidelines laid out in WS Safety Standard 22. Typically, the standard requires that a low‑pressure test be performed, followed by two pressure test (PT) procedures: PT-1 and PT‑2. All pressure tests must be documented.

8.1 Low-pressure test

8.2.1 Pressure test 1 (PT-1) Before performing the test, CT personnel determine the safe PT-1 pressure using information from the Service Order and MPWHP previously calculated. CT personnel pressure test the equipment to the maximum safe pressure, with the following setup: • BOPs installed on the wellhead • upper blind rams closed • CT not inserted in the BOP stack.

The PT-1 test includes all treating lines, blind rams, BOP body, all crossovers, and the wellhead (see Fig. 8-1).

The first pressure test performed by the CT personnel is the low-pressure test. The CT personnel pressure test the equipment to 300 to 500 psi for a minimum of 5 minutes to verify equipment assembly. This test is done to detect any large leaks before performing PT-1 and PT-2.

8.2 PT-1 and PT-2 pressure tests PT-1 and PT-2 pressure tests are mandatory for all CT operations and each pressure test must be recorded. Each pressure test must be done in two steps. The first step is a pressure test to 300 psi to check for any large leaks. The next step is to increase the pressure to the maximum as described in the pressure test limits provided by the field engineer. Hold the pressure at each step for 10 min.

Figure 8-1. PT-1 testing

The PT-1 test is then performed to the lesser of 1.5 times the MPWHP or to the working pressure of the lowest rated component in the stack, including the wellhead, crossovers, and third-party equipment.

JET 13 - Coiled Tubing Pressure Control Equipment  |  63

8.2.2 Pressure test 2 (PT-2) Before opening the well, CT personnel pressure test the equipment with the following setup: • all equipment rigged up • downhole check valves installed • CT inserted in the BOP stack.

The PT-2 test includes the CT pipe, pipe rams, stripper, and downhole check valves in BHA (see Fig. 8-2).

Figure 8-2. PT-2 testing

The PT-2 test is performed to the lesser of the PT-1 test pressure or the CoilLIMIT* coiled tubing pressure/tension limit model predicted collapse pressure of the CT string, or 80% collapse pressure rating of the CT connector/ DFCV.

64  |  Pressure Testing

9.0  Glossary ABOP

Annular BOP

API

American Petroleum Institute

BOP

Blowout preventer

CIRP

Completion insertion and retrieval under pressure, a gun deployment system

H2 S

Hydrogen sulfide, a dangerous gas present in some oil and gas wells

LPT

Low pressure test

MPWHP

Maximum potentional well head pressure

PT-1

Pressure test 1

PT-2

Pressure test 2

QTSS

Quick test safety sub

Quick union

Pin-and-collar type connection

SDDT

Side door deployment tool

WSSS

Well Services Safety Standard

XO

Crossover

JET 13 - Coiled Tubing Pressure Control Equipment  |  65

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66  |  Glossary

10.0  References Well Services Safety Standard 4: Facilities and Workshops, InTouch Content ID# 3313678 Well Services Safety Standard 5: Pressure Pumping and Location Safety, InTouch Content ID# 3313681

Suppliers: • Texas Oil Tools: www.tot.com • Benoil: www.benoil.com

Well Services Safety Standard 22: Coiled Tubing Safety Standards, InTouch Content ID# 3313710 Well Services Safety Standard 23: Testing and Inspection of Treating Operations, InTouch Content ID# 3313701 JET Manual 12, InTouch Content ID# 4221738 JET Manual 16, InTouch Content ID# 4221749 JET Manual 31, InTouch Content ID# 4221769 JET Manual 36, InTouch Content ID# 4221770 QHSE Standard S007: Management System Audit, InTouch Content ID# 3260262 OFS Pressure Safety Standard S014 Coiled Tubing Operations Manual (InTouch Content ID# 3013707) CT Surface Equipment Maintenance Program InTouch # 4196880 All technical manuals for BOPs and strippers

JET 13 - Coiled Tubing Pressure Control Equipment  |  67

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68  |  References

11.0  Check Your Understanding 1.

How many BOPs and strippers are needed for a Category 1 CT operation?

5.

a. 1 BOP and 1 stripper

a. conventional

b. 2 BOPs and 2 strippers

2.

What type of stripper was developed to make it easier to change out the stripper element during a CT operation?

c. 3 BOPs and 3 strippers

b. radial

Which one of these factors does not affect the life of the stripper insert?

d. side door

a. hydraulic pressure

c. sidewinder

6.

The stripper bushings are made of _____.

b. lubrication

a. rubber

c. bushing condition

b. stainless steel

d. CT string OD

c. brass d. EPDM

3.

The nonextrusion rings in the stripper are made of _______. a. brass

7.

b. nitrile

a. conventional

c. Teflon

4.

In which stripper can the packer elements and wear bushings be fully retracted from the vertical wellbore?

d. urethane

b. radial

To redress a conventional stripper, the inserts are replaced from the ____ of the stripper.

d. side door

a. top

c. sidewinder

8.

The main drive system of the stripper hydraulic circuit is the _______.

b. side

a. Haskell hand pump

c. bottom

b. Rucker pump (manual) c. Haskell air-over-hydraulic pump d. auxiliary hydraulic circuit

JET 13 - Coiled Tubing Downhole Tools  |  69

9.

Before a CT operation, which pressure tests must be performed on the stripper(s)? a. pressure test 1 (PT-1) b. pressure test 2 (PT-2) c. no need to test at wellsite, if tested at base

10. An antibuckling guide is a requirement on all CT operations. a. true b. false 11. BOPs are generally manufactured with Bowen quick union connections top and bottom. a. true b. false 12. What is the working pressure of a standard CT BOP? a. 5,000 psi b. 7,500 psi c. 10,000 psi d. 15,000 psi 13. The BOP hydraulic system has a pressure of _______________.

15. Blind rams can hold pressure from above and below. a. true b. false 16. Wellhead pressure helps to keep the blind rams in the _____________position. a. open b. closed 17. What is the sequence of actions to close and re-open a set of rams, assuming they will be locked when closed? a. 1. Close hydraulically. 2. Lock manually. 3. Open hydraulically. 4. Unlock manually. b. 1. Lock manually. 2. Close hydraulically. 3. Unlock manually. 4. Open hydraulically. c. 1. Close hydraulically.

a. 2,000 psi

2. Lock manually.

b. 2,700 psi

3. Unlock manually.

c. 3,000 psi

4. Open hydraulically.

d. 4,000 psi 14. The BOP hydraulic system can be used as an emergency hydraulic supply for the stripper. a. true b. false

70  |  Check Your Understanding

18. The controls for the _____ rams have double lockout protection in the CTU cabin. a. blind, shear b. pipe, slip c. blind, pipe d. slip, shear 19. Which rams are fitted with booster cylinders in some models? a. blind b. shear c. slip d. pipe 20. Slip rams hold the pipe in which direction? a. upwards only b. downwards only c. upwards and downwards 21. The equalizing valve must be opened before opening the slip rams. a. true b. false 22. How many times should your accumulator system be capable of cycling all rams on your BOP?

24. What is the function of the pressure debooster? a. to allow the pressure above and below the blind rams to be equalized b. to hydraulically reduce the WHP by a factor of 4:1 c. to access the point on the BOP where you can pump in to kill the well 25. Which type of BOP can seal on almost any shape? a. combi BOP b. annular BOP c. CIRP BOP d. quad BOP 26. What components are tested as part of the PT-1? a. all treating lines, blind rams, BOP body, all crossovers, and the wellhead b. CT pipe, pipe rams, stripper and downhole check valves in BHA 27. What components are tested as part of PT-2? a. all treating lines, blind rams, BOP body, all crossovers, and the wellhead b. CT pipe, pipe rams, stripper and downhole check valves in BHA

a. 2 b. 3 c. 4 d. 5 23. A CIRP BOP can be used instead of a combi BOP for CT operations. a. true b. false

28. The accumulator provides a reserve of hydraulic energy to enable the ____ to be operated following an engine shut down or circuit failure. a. BOP b. stripper c. quick connect d. antibuckling guide

JET 13 - Coiled Tubing Downhole Tools  |  71

29. A section of lubricator can be used between the BOP and wellhead to allow deployment of tools under pressure. a. true b. false 30. What is a quick latch union?

34. Gasket rings can be reused until they are deformed. a. true b. false 35. Which of the following is not a type of pinand-collar union?

a. a type of stripper

a. Bowen

b. a two-piece hydraulic latching union

b. EUE

c. a type of riser

c. OTIS

d. a two-piece item that allows pressure testing of the last connection without pressuring up the entire stack.

d. TOT

31. A load-bearing quick connect is commonly used on CT operations performed on _______. a. offshore platform operations b. land operations c. semisubmersible operations d. all of the above 32. What is the main difference between a lubricator and a riser? a. A lubricator has flanged connections; a riser has quick union connections. b. A riser has flanged connections; a lubricator has quick union connections. c. Lubricators and risers are the same thing. 33. A ___ connection is required for highpressure CT applications. a. quick connect b. threaded c. flanged

72  |  Check Your Understanding

36. The ____ type of connections are restricted to use in low-pressure, non-H2S wells. a. flanged b. threaded c. quick union