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JET Manual 16 Introduction to Coiled Tubing Version 1.0

JET Manual 16 Introduction to Coiled Tubing InTouch Content ID#: Version: Release Date: Owner:

4221749 1.0 February 22, 2007 Well Services Training and Development, IPC

Schlumberger private

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Effective Date

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Copyright © 2007 Schlumberger, Unpublished work.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. A complete list of Schlumberger marks may be viewed at the Schlumberger Oilfield Services Marks page: http://www.hub.slb.com/index.cfm?id=id32083 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

1 1 3 3 4 6 6 6 6 6 7 7 7 7 7 7 8 9 9 10 10 11 13 14 16 17 19 22 25 26 27 29 29

Learning objectives

2.0  What Is Coiled Tubing?

2.1 Introduction 2.2 Why was coiled tubing developed? 2.3 Why use CT? 2.3.1 Live well intervention 2.3.2 Continuous circulation 2.3.3 Rapid mobilization and rig-up  2.3.4 Environmental impact 2.3.5 Tripping time 2.3.6 Pipe handling 2.3.7 Crew levels 2.3.8 Cost 2.4 History of CT manufacturing 2.5 Wall thickness configuration 2.6 CT applications overview

3.0  CT Fluid Conveyance

3.1 Nitrogen kickoff 3.2 Fill removal (cleanout) 3.2.1 Cleanout fluids—selection criteria 3.2.2 Cleanout fluids 3.2.3 BHA selection 3.2.4 Cleanout best practices 3.3 Cement placement 3.3.1 Best practices for cementing through CT 3.3.2 Squeeze cementing 3.3.3 Cement plugs 3.4 Stimulation  3.4.1 Matrix acidizing 3.4.2 Hydraulic fracturing

4.0  CT Tool Conveyance 4.1

Coiled tubing fishing JET 16 - Introduction to Coiled Tubing  | 

iii

4.1.1 Fishing tools: spears and overshots 4.1.2 Auxiliary fishing tools 4.1.3 CT milling 4.2 Downhole valve/sliding sleeve manipulation 4.3 Blaster services 4.3.1 Characteristics 4.3.2 Applications 4.4 Zonal isolation  4.4.1 Cup-type packers 4.4.2 Mechanical 4.4.3 Hydraulic set 4.4.4 Inflatable 4.4.5 Bridge plug 4.5 CT Logging 4.5.1 Logging on CT 4.5.2 Logging cables 4.5.3 Installing a cable 4.5.4 Surface equipment 4.5.5 Downhole equipment 4.6 CT perforating 4.6.1 Perforation techniques 4.7 CT Drilling 4.7.1 Conventional and CTD comparison 4.7.2 CTD advantages 4.7.3 CTD disadvantages  4.7.4 CTD applications 4.7.5 Surface equipment 4.7.6 Downhole equipment

5.0  CT Completions 5.1 5.2 5.3 5.4 5.5 5.6

CT velocity string CT tailpipe extension CT tubing patch Electric submersible pumps Spoolable gas lift valves Through-tubing gravelpack

6.0  Glossary 7.0  Check Your Understanding

iv  |  Table of Contents

29 30 33 35 36 37 37 39 39 39 40 40 41 41 42 43 44 46 47 48 50 52 52 53 54 54 55 57 61 62 63 63 64 64 65 69 71

1.0  Introduction Schlumberger Well Services carries out many different types of coiled tubing (CT) operations in many different environments. This job execution training (JET) manual briefly describes the history of CT and introduces you to the different types of CT applications carried out by Schlumberger CT services. The manual also explains the advantages of using CT over other intervention methods. CT equipment is covered in detail in other JET manuals: • JET 12, Coiled Tubing Handling & Spooling, InTouch Content ID# 4221738 • JET 13, Coiled Tubing Pressure Control Equipment, InTouch Content ID# 4221744 • JET 31, Introduction to the Coiled Tubing Unit, InTouch Content ID# 4221769 • JET 32, Downhole Tools, InTouch Content ID# 4221770.

1.1 Learning objectives Upon completion of this training, you should be able to • explain why CT was developed • identify the three major types of CT intervention • understand the main CT application principles • identify the advantages of CT applications.

JET 16 - Introduction to Coiled Tubing  |  

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  |  Introduction

2.0  What Is Coiled Tubing? 2.1 Introduction Coiled tubing (CT) is a generic name often used for coiled tubing services (CTS). Schlumberger has over 200 CT units worldwide, making it the largest provider of CT services in the world. Figure 2-1 shows a coiled tubing unit. Operationally, a CT intervention involves pushing a coiled tubing string into an oil or gas well to perform work without disturbing the existing well completion. The ability to pump through the CT string allows many different types of operations be carried out. At the end of a CT operation, the CT string is pulled out of the well and spooled back onto the CT reel.

CT technology is based on the use of the CT string, which is a continuous flexible steel tube that is spooled on a reel for transport and storage. The reel is a part of the coiled tubing unit (CTU). You will learn more about CTUs in JET manual 31. At surface, the end of the CT string is connected to a high-pressure swivel joint on the reel hub so that fluids can be pumped through the string continuously if necessary. The CT string is run into and retrieved from the wellbore by the injector head. The injector head is controlled hydraulically from the CT cabin by the CTU operator. The hydraulic system gives the operator a high degree of control over the position and movement of the CT string.

Guide arch (Gooseneck) CT string Injector head

Control cabin Reel

Power pack

Stripper BOP

Well head

Figure 2-1. CTU Terms

JET 16 - Introduction to Coiled Tubing  |  

A stripper assembly is mounted below the injector head. This assembly provides a dynamic seal around the tubing string, which means that the CT string can be run and retrieved on live wells. The blowout preventer (BOP) assembly is mounted between the stripper and the wellhead. This provides secondary and contingency pressure control functions. The CTU is operated from the control cabin, which is designed as a single point control and monitoring station for the primary functions of the CTU and auxiliary equipment.

2.2 Why was coiled tubing developed? Coiled tubing (CT) was developed to perform remedial work on live wellbores. Figure 2-2 shows a Bowen tools unit rigged up on a Wellhead. To perform remedial work, three key elements were required: • A continuous conduit that can be inserted into the well and allow fluid conveyance • A means of running and retrieving the string from the well under pressure • A device capable of providing a dynamic seal during any operation.

The first fully functioning coiled tubing unit (CTU) was developed in California (1962) by Bowen Tools Company to wash out sand in the wells in the Gulf Coast. Figure 2-3 shows the evolution of CT.

  |  What Is Coiled Tubing?

Figure 2-2. Bowen Tools Unit

Strip length

Typical CT string

String OD

50 ft

3 1/2 in

250 ft

3/4 in

Material strength

PLUTO

50,000 psi

6,000 ft x 3/4 in Material type

1 in 60,000 psi 1 1/4 in

1,000 ft 15,000 ft x 1 1/4 in

Low alloy carbon steel

1,700 ft (Japanese) 3,500 ft Continuous milling process developed

1 1/2 in 70,000 psi 1 3/4 in, 2, 2 3/8 in 2 7/8 in

80,000 psi 90,000 psi

3 1/2 in, 4 1/2 in

100,000 psi

20,000 ft x 1 1/2 in 110,000 psi

Titanium Composite material

120,000 psi 28,000 ft x 2 3/8 in (Largest string 2003)

Chrome alloy

Figure 2-3. CT Evolution

JET 16 - Introduction to Coiled Tubing  |  

2.3 Why use CT? The direct competitors for CT services are snubbing units and small workover rigs. Each technique has its own advantages depending on the particular work or operating conditions.

which is one of the primary reasons why CT is used for live well intervention.

2.3.3 Rapid mobilization and rig-up

The following sections explain the advantages of CT operations over snubbing units and workover rigs.

Since all the components of a CT rig are modular and mobile (i.e., skid- or truck‑mounted), they can be moved from location to location easily.

2.3.1 Live well intervention

A CT unit can be rigged up more quickly than most conventional rigs (Fig. 2-4).

A workover intervention is a major maintenance or remedial treatment of an oil or gas well. In many cases, a workover requires removing and replacing the production tubing string after the well has been killed and a workover rig placed on location. CT operations, however, can be run through the existing production tubing or casing, while it is still producing oil or gas. The pressure control equipment used on every CT operation allows the workover to be done safely on a live well. The ability to perform an intervention without having to kill the well and remove the production tubing saves the client time and money and avoids potential damage to the formation. Figure 2-4. CT Express

2.3.2 Continuous circulation The CT reel is equipped with a swivel and piping, which allows fluid to be pumped through the tubing while the reel is rotating. CT enables continuous circulation while running in hole (RIH) and pulling out of hole (POOH) because the tubing is continuous. With a conventional workover rig or snubbing unit, circulation must be stopped to break out each stand of pipe. The ability to continuously circulate or convey a well treatment provides better well control,

  |  What Is Coiled Tubing?

2.3.4 Environmental impact The CT unit footprint is usually much smaller than a workover rig. This results in less environmental damage from unit setup. In addition, since the CT unit and its circulating system are self-contained, any spilled fluids are also contained, thereby protecting the environment.

2.3.5 Tripping time

2.4 History of CT manufacturing

Because a CT string is continuous, it can be run into a well and pulled out quickly. Conventional tubing consists of individual tubing joints with connectors on each end. These connectors must be screwed together when running in hole and broken (unscrewed) when pulling out of a well.

Low carbon steel alloys are used to manufacture CT strings. These alloys come in various material yield strengths. The yield strength is usually given in pound per square inch (psi) and indicates the load-bearing capacity of the material.

Making and breaking a tubing string is not only time consuming, but can result in accidents on drilling and workover rigs. The time saved and increased safety in continuously running CT is one of the biggest advantages of CT.

2.3.6 Pipe handling Pipe handling refers to picking up, laying down, and maintaining pipes. Handling one reel of pipe usually requires less manpower and resources than handling many lengths of pipes.

2.3.7 Crew levels CT operations require less personnel than conventional drilling rigs. The newest CT units such as the CTX and CT SEAS* coiled tubing safer, efficient automated solutions reduce the number of personnel required even further by improving efficiency.

2.3.8 Cost CT is generally less expensive than using a conventional drilling rig to perform well services because of reduced time and personnel. However, in each case, the client makes an economic evaluation between all the intervention options (e.g. wireline, slickline, snubbing, or workover rig).

The most commonly used material yield strengths currently used are • 70,000 psi • 80,000 psi • 90,000 psi • 100,000 psi.

Early continuous tubing was limited to relatively small diameters and short string lengths (76 m [250 ft]), because of manufacturing limitations. The short strings were combined using butt welds to make longer strings. The many butt welds resulted in numerous string failures. Today, improved welding techniques allow CT strings to be milled continuously without the need for butt welds.

2.5 Wall thickness configuration A nontapered CT strings has only one wall thickness. To manufacture a nontapered string, several sections of CT with the same wall thickness are welded together. The string has the same outside diameter, inside diameter, and wall thickness over its entire length. For tapered CT strings, several sections of CT with different wall thicknesses are welded together (Fig. 2-5). The result is a CT string with varying inside diameters and wall thickness. The outside diameter is constant over the entire length of the string. Tapered strings are very common and are typically necessary to enable safe access into

JET 16 - Introduction to Coiled Tubing  |  

wellbores deeper than approximately 3,500 m [11,483 ft]. The heavier wall thickness at surface supports the weight of the CT string in the well plus any tensile force at the downhole end (for example, during fishing operations).

Figure 2-5. Tapered CT String

2.6 CT applications overview CT applications can be broken into three major categories: • fluid conveyance • tools conveyance • CT completions.

The next three sections of this JET manual will cover each one individually.

  |  What Is Coiled Tubing?

3.0  CT Fluid Conveyance CT is used to convey fluids into the well to either circulate the fluids (Fig. 3-1) or inject the fluids into the reservoir (Fig. 3-2).

The main CT fluid conveyance operations are • nitrogen kickoff • fill removal (cleanout) • cement placement • stimulation: matrix acidizing • stimulation: hydraulic fracturing and CoilFRAC* stimulation through coiled tubing.

These applications are described in the following pages.

3.1 Nitrogen kickoff Figure 3-1. Nitrogen Circulated to Lift the Well

After performing drilling and workover operations on a well, the well is usually dead, which means it does not flow. This is because the column of fluid left inside the wellbore exerts a hydrostatic pressure that is greater than the formation pressure. This pressure prevents the flow of the reservoir fluid. Nitrogen (N2) circulation through CT is the most common method of starting production. This is often called a kickoff or lift (Fig. 3-3). It is one of the most common applications of CT.

Figure 3-2. Stimulation Treatment

The technique is relatively simple. The CT string is run into the well and nitrogen gas is circulated through the string into the fluid column in the well. This gas reduces the hydrostatic pressure of the column. When this pressure is reduced below the pressure of the reservoir, the well begins to flow. In some cases, the well can be kicked off by circulating a light fluid, such as diesel, instead of nitrogen gas.

JET 16 - Introduction to Coiled Tubing  |  

Common sources of fill are • sand or fine material from the reservoir • proppant (material used in hydraulic fracturing operations) • debris from a workover.

To remove fill, a cleanout fluid is pumped through the CT string with the end at the point of the fill buildup. The fluid is circulated back up the annulus between the CT string and the completion tubing to carry the fill back to surface. At the surface, the returns may be handled by surface well testing equipment or go directly into the production line. Figure 3-3. Nitrogen Lift

3.2 Fill removal (cleanout) The most common application of CT is removing fill materials, such as sand or debris, from the wellbore (Fig. 3-4). Fill material can seriously reduce or even stop the production of a well by blocking the flow of oil or gas. It can also block slickline or wireline tools from passing for well operations or prevent downhole sleeves and valves from opening or closing.

Fill can be removed mechanically and/or chemically. In most cases, fill is removed by circulating a fluid through the CT while slowly penetrating the fill with a nozzle. Sometimes, a chemical such as acid, solvent, or another liquid is pumped to help chemically break down the fill before it is circulated out of the wellbore. When the fill is tightly packed or consolidated, a downhole motor or impact hammer may be required to mechanically break down the fill. Fluid is circulated to remove sand from the wellbore. Because of the complex hydraulics, solids removal is generally more difficult in highly deviated and horizontal wellbores.

3.2.1 Cleanout fluids—selection criteria The choice of cleanout fluid is very important in ensuring the success of a fill cleanout operation. The choice can depends on the following design criteria: Figure 3-4. Sand Removal

10  |  CT Fluid Conveyance

• completion size and CT size: In small ID completions, the cleanout fluid will move upwards very fast and will generally carry solids with it. In large ID completions, the fluid will travel more slowly for a given

pump rate, and the solids may fall out. The CT size determines the maximum pump rate possible. Together, the completion size and the CT size determine the annular velocity. This is extremely important in the design of the cleanout. • reservoir pressure and temperature: The hydrostatic pressure of the cleanout fluid should be less than the reservoir pressure to ensure the fluid returns to surface and is not lost in the reservoir. Also, some fluids will break down at high temperatures. • well deviation: The more deviated the well is, the more difficult it is to remove the solids. More complex computer modeling needs to be used in horizontal and highly deviated wells to calculate what type of fluid will be effective. • fluid compatibility: The fluid must not damage the reservoir or cause a sludge or emulsion when mixed with the reservoir fluid.

Table 3-1 summarizes the effect of various well properties on the difficulty of achieving a successful cleanout.

3.2.2 Cleanout fluids There are four classes of cleanout fluids: • water, brine, or diesel • gelled fluids

• foamed or nitrified fluids • slugs.

3.2.2.1 Water, brine, or diesel fluids Water, brine, and diesel are the most common fluids used in the most simple cleanout candidates, such as vertical or slightly deviated wellbores (less than 30 degrees) which can hold a column of fluid. These fluids work by keeping the particles in suspension in their turbulent flow. The main advantages of water and brine are the low cost and the ease of handling. A compatibility test should be performed to check if the fluid has any compatibility problems with the reservoir rock or the wellbore fluid. When a salt is added to water, the fluid is called brine. Common salts used in mixing brine are potassium chloride (KCl), sodium chloride (NaCl) and calcium chloride (CaCl2). Brine is preferred over water when the reservoir is sensitive to pure water or in high-pressure wells, where the heavier fluid is preferred because of its higher hydrostatic pressure. Diesel is generally used in slightly lower pressure wells because it is approximately 17% lighter than water. It has fewer compatibility problems than water because it is a crude oil‑derived product, but it is not as easy to handle.

Table 3-1. Factors Affecting Complexity of Cleanout

Best Case

Worst Case

Completion size

Small ID, such as 3 1/2-in tubing

Large ID, such as 7-in tubing

CT size

Large OD, 2 in

Small OD, 1 1/4 in

Reservoir pressure

Medium to high pressure, can hold column of water

Low pressure, cannot hold column of fluid

Reservoir temperature

< 93 degC [200 degF]

> 149 degC [300 degF]

Well deviation

Vertical

Highly deviated or horizontal

Fluid compatibility

No compatibility issues

Sludge-forming or reservoir-damaging JET 16 - Introduction to Coiled Tubing  |  11

3.2.2.2 Gelled fluids

3.2.2.3 Nitrified and foamed fluids

Gelled fluids (Fig. 3-5) provide more effective solids carrying than water or diesel because of their viscosity. This viscosity decreases the falling velocity of particles. This decrease can be highly effective in vertical and slightly deviated wells.

When wellbore conditions become more difficult, more complex fluid solutions need to be used for a successful cleanout. 3.2.2.3.1 Nitrified fluid The fluid is called a nitrified fluid (or energized fluid) when a base fluid (water, brine, or diesel) is pumped simultaneously with nitrogen. The proportion of nitrogen in the fluid is generally relatively low. Nitrified fluids are mainly used as low hydrostatic cleanout fluids in low-pressure wells. The gaseous nitrogen expands in the annulus, giving increased annular velocity in large ID completions, to assist in lifting out solids. 3.2.2.3.2 Foamed fluid

Figure 3-5. Viscous Gelled Fluid

There is a wide range of gelling agents with different properties available. It is important to check the temperature range of the gelling agent, as most gels lose their viscosity at high temperatures. The Schlumberger PowerCLEAN* J571 or J572 gels are designed for high temperature applications. Some gels used in CT cleanout operations are • xanthan • guar • HEC • ClearFRAC • PowerCLEAN* engineered fill removal service J571/J572.

The fluid is called a foamed fluid or just foam when a chemical foaming agent is added to the base fluid and a relatively high proportion of nitrogen is pumped simultaneously. An ideal foam has a consistency like shaving foam. Foam has excellent solids-carrying capacity because it suspends the particles in its foam structure. A good foam will hold particles even if you stop circulation. Foamed fluids are used • as a low hydrostatic cleanout fluid in low pressure wells • to improve solid removal in horizontal wells.

Foam cleanouts can be very effective but are complex and need good prejob design to control the quality of the foam and the handling of the returned fluid. It is important that the well does not flow during the cleanout because oil and gas react with the foam to break it. Breaking means the foam loses its structure and reverts to its liquid and

12  |  CT Fluid Conveyance

gas phases. In this condition, it will not carry solids to surface. Avoiding this condition requires a good prejob design and good control over the return choke pressure. When the foam returns to surface, it can be difficult to handle and needs to be broken down. Generally, a chemical such as mutual solvent or diesel is added to break the foam.

3.2.2.4 Slugs Another common fill removal technique involves pumping liquid and nitrogen in alternating stages. These are called slugs and are generally used in wells that do not support a full column of fluid, as well as in horizontal wells. Normally, a slug of water is followed by a slug of gel and a slug of nitrogen. The slug size is generally calculated so that one cycle equals one reel volume. The CT should be reciprocated (moved up and down) while cleaning out. The job program should be designed so that the CT only enters the fill when fluid is exiting the nozzle. The CT should be slowly pulled upwards when nitrogen is exiting the nozzle to chase the fluid and solids up the well. Slugs reduce the overall hydrostatic pressure in the wellbore and can be used to increase the velocity of the loaded fluid in the annulus. When using slugs, the returns are choked (back pressure held at surface) to control gas expansion and thus annular velocities. Slugs have several advantages: • Low hydrostatic pressure can be achieved.

3.2.3 BHA selection The bottom-hole assembly (BHA) for fill cleanout is generally very simple and typically includes • CT connector • double flapper check valve • straight bar (optional) • nozzle.

Some clients request that the BHA also include a hydraulic disconnect and circulation sub. The circulation sub is sometimes opened at the end of the cleanout operation to allow higher pump rates during the bottoms-up circulation. JET 36, CT Downhole Tools, InTouch Content ID# 2208502.

3.2.3.1 Nozzle selection In the past, nozzle selection was not very scientific. Some locations liked to use a simple one-hole design, while others added angled orifices to help jet the fill, and others added some backward-facing jets to assist in removing the solids. A Schlumberger research project was conducted to study fill removal. Various nozzle designs were tested to find the best design for the most efficient fill removal. The result of the research was the PowerCLEAN nozzle. Specially angled holes in the body of the nozzle create a fluid vortex to carry particles to the surface. The jetting energy of the nozzle

• The well may be flowed to assist in returning solids to surface.

• agitates and entrains fill into the cleanout fluid

• Return fluids to the surface are easily handled because there are definite liquid and gas phases.

• prevents particles from falling down past the nozzle

• The job is simple to design and execute.

• effectively moves the sand up the wellbore.

JET 16 - Introduction to Coiled Tubing  |  13

Numerous cleanout tests showed that PowerCLEAN nozzles have superior performance over other nozzle types, allowing complete removal of solids at lower flow rates.

• required pump rates and maximum pressures • maximum rate of penetration (ROP) • amount of solids to surface.

Figure 3-6. PowerCLEAN Nozzle

3.2.4 Cleanout best practices Fill cleanouts are the most common CT operation worldwide, but the planning and execution should not become a routine. Remember that a poor design can lead to incidents such as • stuck CT pipe • unsuccessful cleanout operation • increased use of chemicals • an unhappy client!

Some of the most important considerations for the good design and execution of a successful cleanout operation are discussed below.

3.2.4.1 Job design All cleanout operations should be simulated using Schlumberger CoilCADE* coiled tubing design and evaluation software modules such as Wellbore Simulator and PowerCLEAN (Fig. 2-7). When properly used, these powerful simulators indicate: • type of fluid to use

14  |  CT Fluid Conveyance

Figure 3-7. Schlumberger Cleanout Design Software

By simulating different cleanout scenarios, the best fluid and pumping schedule can be found for a particular well. A good design will save the client time and money, as well as ensuring that the good reputation of Schlumberger CT is maintained with a successful, efficient, and incident-free operation.

3.2.4.2 Job execution As the CT operator, you need to be aware of the following issues related to CT cleanouts. The job program from your location should give you detailed information on the precise values needed for each particular cleanout. 3.2.4.2.1

Step size

Fill removal is generally carried out in steps or bites. These terms mean that fill is removed in short sections and circulated towards the surface before running the CT deeper to remove the next section. For example, if a well contains 300 m [984 ft] of sand fill, it would be dangerous to try to clean this in one bite. In some cases, the hydrostatic weight of the heavy sand-laden fluid would become greater than the reservoir pressure and losses would occur. Otherwise, a short pump failure could pause circulation. Both cases would mean a lot of sand will fall downwards, which can cause a CT pipe to be stuck. Taking small steps to remove the fill ensures that the hydrostatic weight will not change significantly and that there is only a limited amount of sand in the annulus in case a pump fails.

long it takes the foam to return. Based on this information, the remaining steps can be taken more frequently. However, it is common practice to have no more than three steps of fill in the annulus at any one time. When each step comes to surface, the next step can be taken. 3.2.4.2.2

Rate of penetration

The rate of penetration (ROP) is the speed at which the CT string enters the fill. Typically, a low ROP (5 m/min [15 ft/min]) is recommended. A high ROP leads to a concentrated slug of fill traveling up the wellbore, which could lead to plugged lines on surface. A high ROP can also plug the nozzle ports or cause the CT pipe to get stuck. 3.2.4.2.3

Bottoms-up circulation

Circulating bottoms-up means that an entire wellbore volume of fluid is circulated to bring all solids in the annulus to the surface. This process should be done at regular intervals during long cleanouts, and at the end of all cleanouts to clear the annulus of solids. Often, the well is circulated bottoms-up twice at the end of a job to ensure that all solids have returned to surface. A pill of gelled fluid may be pumped as part of this cleanup procedure to assist in transporting the final solids. Use the sand detection monitor (if available) on the surface return line to optimize a cleanout (Fig. 3-8). This monitor detects sand or fill in the line and allows the operator to know when each bite of fill has returned to surface.

Many cleanouts are designed so that the first step is completely circulated to surface before taking the next step. This process confirms that the fill can be removed with the chosen fluid and pump rate, and also determines how

JET 16 - Introduction to Coiled Tubing  |  15

3.3 Cement placement Coiled tubing can be used for two types of cementing operations (Fig. 3-10): • squeeze cementing: sealing off perforations or casing leaks • setting cement plugs inside a wellbore: kick-off plugs or abandonment.

Figure 3-8. Sand Detection Monitor

The sand detection monitor is used as part of the PowerCLEAN system (Fig. 3-9). Figure 3-10. Schlumberger Cement Pump Truck

The main advantages of using CT instead of a workover rig for these cementing applications are as follows. • The operation is done through the tubing; there is no need to pull completion. • The operation can be done without killing the well. Figure 3-9. Screen Display from Sand Detection Monitor

Software used with the sand detection monitor detects sand returns to surface.

Note: For more information on coiled tubing cleanouts, refer to the CT Cleanout Reference Page, InTouch Content ID# 3275189.

16  |  CT Fluid Conveyance

• Pumping cement slurry through a CT string reduces slurry contamination. • Lower treatment volumes are required. • Accurate placement is possible. • It is inexpensive to combine with cleanout, stimulation, or a N2 lift. • The cost is less.

Note: Pay special attention to the design of the cement slurry to be pumped through a CT string. The small inner diameter of the CT string leads to high friction pressures and a high shear rate on the slurry. This effect significantly reduces the time for the cement slurry to set, and can lead to a cemented CT string if the slurry is not carefully designed and tested.

be eliminated by using cement plugs before and after the slurry to separate the fluids and prevent contamination. These plugs generally include a burst disk mechanism, which means they can be sheared with pressure when they reach the BHA, allowing continuous pumping. They also give a positive pressure indication when they seat in the BHA. Ideally, a plug catcher is run as part of the BHA.

3.3.1 Best practices for cementing through CT The following sections discuss best practices for cementing through CT.

3.3.1.1 Selecting CT To minimize friction pressures and allow high pump rates, the CT string should ideally have the maximum ID possible, depending on location availability. A shorter CT string will also result in reduced pump pressures.

3.3.1.2 Minimizing slurry contamination One of the main advantages of pumping cement through CT is the ability to achieve low contamination of the slurry. To achieve this, you need to begin with a clean CT string, which is a string that has had a pig pumped through it to verify it is clear, or ideally a weak acid pickle. When pumping the slurry through the CT string, there will be some contamination of the slurry at interfaces with the fluids immediately before and after the slurry. The contamination can

Figure 3-11. CT Cement Darts with Burst Disk

It is very important to flush and clean the string very well after the cementing job, and pumping an acid pickle is recommended to remove any excess slurry left behind.

3.3.1.3 Controlling depth Since cement placement is permanent, it is extremely important to ensure it is placed in the correct position. For example, if cement is squeezed into the wrong set of perforations, millions of dollars of damage can result. Thus, it is very important to ensure that the CT depth is as accurate as possible. Use the universal tubing length meter (UTLM) for cementing jobs (Fig. 3-12). The UTLM is the most accurate depth counter available and should always be used on critical jobs.

JET 16 - Introduction to Coiled Tubing  |  17

If CT cementing plugs are used, include a plug catcher. If the depth control procedures require a TEL or TNL, this will also be included in the BHA.

Note: Ensure that all BHA components have the largest ID bores possible.

3.3.1.5 Placing cement platform

Figure 3-12. UTLM Rigged Up on CT Reel

For further depth control accuracy, achieve a positive depth indication downhole by tagging a known depth in the wellbore and comparing this with the measured depth. Running a tubing end locator (TEL) as part of the BHA enables you to tag the end of the tubing, which should be at a known depth. You can also use a tubing nipple locator (TNL), which enables you to tag a nipple in the completion.

One of the most important considerations in placing cement is the cement platform. Small cement slurry volumes combined with slow pumping rate through CT will cause the cement to fall down the hole, especially in light fluid. The cement is contaminated then and a good set cannot be achieved. Figure 3-13 shows how a cement platform supports the cement slurry. A cement platform placed underneath the cement slurry provides the required support. The platform can be a sand plug, a mechanical through-tubing bridge plug, or simply a high viscosity/high-density fluid (high-density mud or viscous gel).

3.3.1.4 Selecting BHA To avoid the possibility of cement slurry bridging off in restricted bore in the BHA, keep the BHA as simple as possible. Typically, the following simple BHA is used:

Slurry settles on platform Slurry ropes and contaminates

• CT connector

Sand plug

• double-flapper check valve • nozzle (large bore).

18  |  CT Fluid Conveyance

Figure 3-13. Cement Platform

3.3.2 Squeeze cementing The squeeze cementing technique involves squeezing a specially designed cement slurry under pressure into existing perforations or a casing leak to provide a seal. This method is generally used to repair wellbore problems, such as • poor zonal isolation: A poor primary cementing job can leave channels behind the casing, which leads to communication between different zones behind the casing. This can cause unwanted flows of water or gas from poorly isolated zones.

Cement-filled perforation with good node profile

Figure 3-14. Squeeze Node

• casing repair: Leaks due to corrosion, erosion, mechanical damage must be repaired.

Figure 3-14 shows how the slurry fills the perforation, creating a squeeze node.

• water/gas shutoff: Unwanted water or gas production may be occurring—a common problem in old wells.

The slurry remaining inside the wellbore is then contaminated and circulated out before the cement sets.

The squeeze technique involves spotting the cement slurry across the zone using CT and then picking up the end of the CT string above the top of cement (TOC). Squeeze pressure is then applied to force the slurry into the zone being isolated. When the slurry is forced against the permeable formation, the solid particles filter out on the formation face to form a filter cake, while the liquid phase of the cement (the cement filtrate) enters the formation matrix. A properly designed squeeze job causes the cement filter cake to fill the openings between the formation and the casing. The filter cake forms a hydraulic seal.

Note: Slurry design is very critical for a successful squeeze job because exact fluid loss properties need to be obtained.

3.3.2.1 Squeeze cementing job procedure Job scenario: The client wants to squeeze off the middle zone of perforations, which has begun to produce water in the oil well. Here is a typical job procedure.

JET 16 - Introduction to Coiled Tubing  |  19

STEP 01

STEP 03

Run in hole with CT (Fig. 3-15) below the zone with a typical BHA (connector, double flapper check valve, and nozzle).

Spot a viscous pill of gel or heavyweight mud below the zone (Fig. 3‑17). This pill prevents the cement slurry from entering the lower zone of perforations, which is still producing oil.

Figure 3-15. Squeeze Cementing: Step 01

Figure 3-17. Squeeze Cementing: Step 03

STEP 02

Stop the CT and perform an injection test to confirm that injection can be achieved (Fig. 3-16).

STEP 04 Circulate in the cement slurry (Fig. 3-18) while slowly picking up the CT to follow the increasing level of slurry in the casing. The end of the CT string should remain inside the slurry at all times.

Figure 3-16. Squeeze Cementing: Step 02

Figure 3-18. Squeeze Cementing: Step 04

20  |  CT Fluid Conveyance

STEP 05

When all the slurry has been displaced from the CT string, pull the CT string above the TOC (Fig. 3-19). Apply squeeze pressure through the CT string until the designed squeeze-off pressure is achieved. The design may require this pressure to be held for a certain length of time before bleedoff. Contaminated slurry

Figure 3-20. Squeeze Cementing: Step 06

STEP 07 Cement slurry forced into perforations

Circulate the contaminated slurry and the pill out until the tubing and wellbore are clean (Fig. 3-21). Under normal conditions, reversing out cannot be performed because the CT is always used with a check valve at the end.

Figure 3-19. Squeeze Cementing: Step 05

STEP 06

Be sure to remove the excess cement slurry from inside the casing. Slowly run the CT string to the bottom of the zone while circulating a contaminant (xanthan gel or a cementing spacer) to dilute the slurry (Fig. 3‑20). The contaminant prevents the slurry from setting.

Figure 3-21. Squeeze Cementing: Step 07

JET 16 - Introduction to Coiled Tubing  |  21

STEP 08

Wait until the cement has hardened before continuing operations or production. Figure 3-22 shows the perforations successfully squeezed off.

Perforations squeezed off

it is to flow to surface. If the depleted or low‑pressure zone is not isolated, a large loss in production results. • lost circulation. A thief zone is any formation that cannot support the hydrostatic pressure of the fluid in the well. Loss of drilling fluid to a thief zone can be stopped by setting a properly formulated slurry across the thief zone. • abandonment plugs. An abandonment plug is used to seal off sections or an entire wellbore at the end of its useful life. Cement plugs are set at various depths to prevent zonal communication or any migration of gas or fluids that might pollute underground freshwater sources or cause pressure communication between intervals.

When abandoning a well, regulations generally require that a number of cement plugs be set. Figure 3-23 shows a typical schematic of abandonment plugs.

Figure 3-22. Squeeze Cementing: Step 08

3.3.3 Cement plugs Setting a cement plug in a well is a common oilfield operation that uses a small volume of cement slurry. Cement plugs are used for a variety of purposes, including • kick-off plugs. During directional-drilling operations, it may be difficult to achieve the correct angle and direction when drilling through a soft formation. It is common practice to set a kickoff plug across the zone to achieve the desired course and target. Kickoff plugs are often set through CT as part of CT drilling operations. • plugging back a depleted zone. A depleted zone is a zone of reduced pressure. Oil or gas production from other zones is more likely to enter a depleted zone than 22  |  CT Fluid Conveyance

Figure 3-23. Abandonment Plugs

Because most cement plugs are set as part of drilling rig operations, they are predominantly pumped through drillpipe. In general, CT is used to set plugs when they are needed in rigless through-tubing applications and CT drilling operations.

STEP 02

Spot a viscous pill of gel or heavyweight mud below the zone (Fig. 2‑25). This pill will prevent the cement slurry from falling down the hole and becoming contaminated, resulting in a failure.

Setting a cement plug through CT involves circulating the cement slurry into position using CT and then picking up the end of the CT string above the TOC. A slight squeeze pressure may be applied. If the exact location of the TOC needs to be accurate, the CT string may be run in to circulate out any excess slurry above this point. The CT is then pulled out of hole.

3.3.3.1 Cement plug job procedure The following is a typical abandonment plug job procedure.

STEP 01

Run in hole with CT to maximum depth with a typical BHA (connector, double flapper check valve and nozzle) (Fig. 3-24).

Figure 3-25. Plug Cementing: Step 02

STEP 03

Circulate in the cement slurry through the CT string (Fig. 3-26). When 15 m [50 ft] of cement is in the annulus, begin to pick up the CT string to follow the increasing level of slurry in the casing. The end of the CT string should remain inside the slurry at all times. Stop pumping just before the end of the cement exits the nozzle.

Figure 3-24. Plug Cementing: Step 01

JET 16 - Introduction to Coiled Tubing  |  23

STEP 05

Apply squeeze pressure through the CT string if required by the program (Fig. 3‑28).

Cement slurry forced into perforations

Figure 3-26. Plug Cementing: Step 03

STEP 04

Pull the CT string 30 m [100 ft] above the top of cement (Fig. 3-27). Circulate the well bottoms-up to remove any excess slurry from the wellbore.

Figure 3-27. Plug Cementing: Step 04

24  |  CT Fluid Conveyance

Figure 3-28. Plug Cementing: Step 05

STEP 06

Pull the CT out of hole, maintaining squeeze pressure by holding back pressure with a choke on return line (Fig. 3-29).

Note: For more information on cementing through CT, refer to the following InTouch Reference Pages: • Cementing Through CT Reference Page, InTouch Content ID# 3365407 • Water/Gas Cement Squeeze Shut-Off Reference Page, InTouch Content ID# 3335663

3.4 Stimulation Figure 3-29. Plug Cementing: Step 06

STEP 07

Wait until the cement has hardened before continuing operations (Fig. 3‑30).

Hardened cement plug

Figure 3-30. Plug Cementing: Step 07

Well stimulation is a treatment performed to improve the well production by restoring or improving the permeability of the reservoir. Stimulation treatments fall into two types. • Matrix treatments are pumped into the reservoir at a pressure below the formation fracture pressure. This means it is pushed through the open pore spaces in the formations. • The formation fracture pressure is the pressure at which the formation rock will fracture or crack. If the pressure is released, the rock will return to its original position. Hydraulic fracturing treatments are pumped into the formation at a pressure above the formation fracture pressure. This means that the formation will fracture slightly and the fluid or slurry pumped will move along this open fracture.

Stimulation is one of the most common CT applications. The alternative to stimulating through CT is bullheading, which means pumping the stimulation treating fluid through the production tubing from surface. While this method is generally quicker and cheaper than CT, there are distinct advantages to using CT

JET 16 - Introduction to Coiled Tubing  |  25

• protecting client completion: Pumping the stimulation fluid through coiled tubing protects the client’s production tubing from acid corrosion or erosion from slurry. With bullheading, the entire production tubing is exposed to the stimulation fluid. • placement: With bullheading, it is difficult to predict exactly where the fluid will go. Using coiled tubing ensures accurate placement of the stimulation fluid into the zone to be treated, which means lower volumes of chemicals can be used. • contamination: The small volume of the CT string leads to lower contamination levels of the fluid than pumping through the tubing would. • operations completed as an integrated treatment: For example, fill can be removed before a treatment, or an N2 lift can be performed after treatment.

3.4.1 Matrix acidizing Matrix acidizing is a very common CT application. Acid systems are pumped through the CT string and injected into the formation (Fig. 3-31) to dissolve any damage, scale buildup, or other damaging substances in the near wellbore area. This process allows the oil and gas to flow more freely to the wellbore, which contributes to increased well production. In carbonate rock reservoirs, the acid can dissolve part of the formation rock itself, which can increase the well’s permeability above its original level. This increased permeability increases well production. The most common acid pumped in oilfield applications is hydrochloric acid (HCl). Other acids pumped include acetic acid and formic acid. In general, the acid will be blended with several additives before being pumped into the matrix. The additives improve the performance of the acid system and avoid potentially damaging effects. 26  |  CT Fluid Conveyance

Figure 3-31. Acid Injection

One of the additives used in acid systems is a corrosion inhibitor, which minimizes the effect of the acid on the metal of the CT string or completion. It is important to ensure that the correct amount of corrosion inhibitor is used to avoid damage to the CT string. Besides acidizing the matrix or reservoir, acid is often pumped through CT for other applications: • scale removal and tubing cleaning: Scale can build up in screens, perforations, or tubing, which restricts the flow of oil and gas and prevents the use of slickline and wireline for well intervention. Some common scales, such as calcium carbonate, can be dissolved in acid. CT can be used to spot acid at the point of scale buildup to dissolve it. The effect of the acid can be assisted by a strong jetting effect by using a tool such as the Blaster* (see Section 4.3). The mechanical action of a jetting tool assists the chemical effect of the acid for efficient scale removal. • removal of lost circulation material: Lost circulation material (LCM) is commonly pumped into a well during drilling or workover operations, when the drilling or workover fluid is leaking into the formation. The LCM is generally made up of coarse materials that form a cake on the formation

face, reducing the leakoff of the drilling or workover fluid. However, when LCM is pumped across an oil- or gas-producing reservoir, it can restrict well production, so it may have to be chemically removed. Many lost circulation materials, such as calcium carbonate chips, are soluble in acid. The best way to remove the materials is to spot acid through a CT string in front of the zone containing the LCM.

3.4.2 Hydraulic fracturing For some reservoirs, a hydraulic fracturing treatment is the most effective method of stimulation. Fracturing involves pumping a slurry into the reservoir at a pressure above the fracture pressure of the reservoir. The slurry generally consists of a gelled fluid containing sieved sand or manmade ceramic proppant (Fig. 3-32).

original position, but it remains propped open by the layer of sand or proppant. The layer of sand or proppant is highly permeable and allows oil and gas flow to the wellbore much easier than the original reservoir, increasing well production. The high treatment volumes, high pump rates, and the high pressures required for fracturing operations means that powerful pumps and large tanks must be available on location. An average job can be pumped at 5 m3/min [31 bbl/ min] and 68,000 kPa [10,000 psi]. Figure 3-33 shows many pumps on location for a high rate fracturing operation.

Figure 3-32. Ceramic Proppant

Figure 3-33. Fracturing Operation

The spherical shape of ceramic proppant gives very good permeability for oil and gas to flow. It is available in different strengths and sizes to suit different reservoir properties

The vast majority of fracturing operations are carried out by bullheading, because the high pump rates required cannot be achieved through a CT string. However, fracturing through CT, CoilFRAC, was developed by Schlumberger in the 1990s. It has become a popular form of fracturing for certain applications. Figure 3-34 shows a CoilFRAC setup and Fig. 3-35 shows a CoilFRAC tool.

The sand or proppant fills the crack created in the reservoir. When the treatment is finished and the pressure reduces below reservoir fracture pressure, the reservoir rock tries to return to its

JET 16 - Introduction to Coiled Tubing  |  27

The ability to treat zones individually allows the client to efficiently access and stimulate small zones that previously would have been neglected for economic reasons. This treatment increases the hydrocarbon reserves of the well (the total amount of oil or gas which can be produced from the well). Using CT allows the client to fracture multiple zones in one CT run. This is achieved by running a straddle seal assembly BHA on the end of the CT string. Figure 3-34. CoilFRAC Setup High pressure

Upper bypass ports

Fracture sub (out) High pressure

In sub

Lower bypass ports

Dump valve

Figure 3-35. OptiSTIM* CoilFRAC Tool

The main application of CoilFRAC is in multilayered reservoirs. Using CT, the client can treat individual zones in a reservoir in a time‑efficient manner. This cannot be done efficiently using bullheading techniques. For more information about CoilFRAC, refer to the reference page at InTouch Content ID# 3273491.

28  |  CT Fluid Conveyance

When the straddle seal assembly is located across the perforation interval to be fractured, it seals on the casing wall and isolates the perforations. When the treatment is pumped, it only enters and treats this set of perforations. When the first zone has been treated, the straddle seal assembly is moved to the next zone and set across the next set of perforations to be treated. The second treatment can then be pumped. In most cases, CoilFRAC operations are carried out with larger sizes of CT, typically 2 3/8 in or 2 7/8 in. Because of the high pressures involved, a special high-pressure reel swivel with a working pressure of 102,000 kPa [15,000 psi] is required. Where possible, low friction pressure fracturing fluids, such as ClearFRACv, are used to allow higher pump rates. CoilFRAC operations do not require the use of a double flapper check valve in the BHA because excess slurry must be reverse circulated after a treatment. Reverse circulation is the term for pumping down the production tubing and taking returns up the CT string. It is the easiest way to remove excess sand or proppant from the wellbore because of the high fluid velocities inside the CT string. The CT and fracturing teams must closely coordinate in the planning and execution of CoilFRAC operations.

4.0  CT Tool Conveyance Various tools can be attached to the CT string and conveyed downhole to perform different operations. CT is manufactured for rigidity and strength. The CT string is strong enough to push and pull tools and devices through restrictions, obstructions, and highly deviated and horizontal wellbores. The following examples of CT tool conveyance applications are discussed in this chapter • CT fishing and milling • downhole valve, sleeve operation • BLASTER services • zonal isolation • CT logging • CT perforation • CT drilling.

4.1 Coiled tubing fishing When a tool or downhole device is left in the hole, it is called a fish. CT fishing is a method of retrieving equipment from a wellbore with a CT string. Fishing may be a planned operation such as the removal of a temporary bridge plug or pulling a plug from a downhole nipple. Alternatively, fishing can refer to retrieving a toolstring that was accidentally lost downhole. Generally, slickline is used as a first option for fishing because of its speed and the high level of control in fishing operations. However, in certain cases, CT is used because of the following advantages:

• rigidity and strength: CT enables fishing operations in highly deviated and horizontal wells where slickline cannot reach • pulling capacity: CT is often used when slickline or electric line does not have enough pulling capacity • fluid circulation: Fluid can be pumped through the CT to help clean sand or debris that may be covering the top of the fish.

4.1.1 Fishing tools: spears and overshots Many methods and tools are used in CT fishing operations. Each fishing job is unique and may require tools and techniques be modified to suit the application. For complex operations, a specialized fishing company is often contracted to provide special tools and supervise the operation, as experience is an important factor in fishing operations. Details of the fish, wellbore tubulars, well condition, and surface equipment need to be considered.

Note: It is very important to match the fishing tool exactly to the fish downhole. It is important to have a detailed sketch of all toolstrings run on CT so that you have a good fishing diagram if it is accidentally left in the hole. Refer to JET 32, CT Downhole Tools, for more information. Figures 4-1 and 4-2 illustrate the difference between internal and external fishing necks.

JET 16 - Introduction to Coiled Tubing  |  29

the fish and pull the CT string out of hole if he cannot pull out the fish for any reason. Tool OD Internal Profile

Hydraulically releasable overshots and spears can also be used as running tools to run a matching plug or lock into position in a wellbore and release from the tool downhole by pumping.

4.1.2 Auxiliary fishing tools The following sections discuss various auxiliary fishing tools. Figure 4-1. Internal Fishing Neck

4.1.2.1 Jars and accelerators A jar is a tool that delivers a sudden upward or downward impact force to the toolstring below the jar. Jars are run in most fishing toolstrings in case additional force is required to free the fish. The output force of a hydraulic jar is dictated by the pull force applied before the jar firing. The greater the upward pull applied to the jar, the quicker the jar will fire and the greater the resultant impact will be. The output force can be more than 10 times the size of the CT input force. Figure 4-2. External Fishing Neck

An internal fishing neck has a profile on the inner bore, which can be latched by a matching retrieval tool (known as a fishing spear), which enters inside the fishing neck. An external fishing neck has a profile on the outer body, which can be latched by a matching retrieval tool (known as an overshot), which fits over the fishing neck. The majority of spears and overshots run on CT are hydraulically releasable. This means that the latching mechanism can be retracted by pumping through the CT string above a certain pump rate, allowing the tool to release from the fish. This ability has the obvious advantage of allowing the CT operator to disconnect from 30  |  CT Tool Conveyance

The output force of a mechanical jar cannot be varied downhole. The tool output force is set on the tool on surface. This makes it less flexible than a hydraulic jar. An accelerator must always be placed in the toolstring above the jar assembly. Its main function is to store the energy which will be released when the jar fires. It also helps protect the upper toolstring and the CT string from the shock load caused by the jar impact. Jars and accelerators must be matched for maximum efficiency. The jar manufacturer documentation will give details of suitable matching accelerators.

Many jars release (also called trip, fire, hit or lick) in one direction only. However, dual‑direction tools exist that can jar up and down. CT jars operate on either a mechanical or hydraulic principle.

4.1.2.2 Weight bar A weight bar is a straight piece of heavy wall pipe with standard CT threads top and bottom. Whenever possible, a weight bar should be run in the toolstring between the jar and accelerator. The additional weight between the jar and accelerator increases the output force of the jar.

4.1.2.3 Impact hammers An impact hammer creates a repeated high impact force in the up or down direction. It is activated by pumping fluid and simultaneously applying pull or push force, depending on the direction desired for the impact.

circulating junk basket is used. This tool acts as a downhole vacuum cleaner. The configuration of the tool creates a fluid flow path which draws fluid into the empty bottom chamber of the tool. This creates a suction effect that draws any debris immediately below the tool into the chamber. Spring loaded fingers of flutter cages hold the debris inside the tool. After some time jetting, the tool is retrieved to surface and the debris can be emptied from the tool. If a lot of debris is expected, extension barrels can be added to the lower chamber to provide additional debris collection capacity. It is good practice to run a Venturi junk basket (Fig. 4-3) in the hole if there is any indication of debris on top of a fish. Figure 4-3 shows the flow path in a Venturi junk basket sucking debris into the lower chamber.

The impact force can be adjusted by controlling the pull or compression weight on tool. An impact hammer can typically generate impact forces of 30,000 lbf for a 2,000 lbf setdown force with the CT string. Impact frequency can be several times per second. Like the jar, most impact hammers are run with an accelerator to minimize the forces transmitted to the CT string.

4.1.2.4 Venturi junk basket In many cases, we first need to clean the fishing neck, as debris or sand on top of the fishing neck will prevent latching. Small debris such as sand can be circulated from the well by circulation with CT. However, larger particles such as metal debris or large scale chunks cannot be lifted to surface through cleanout methods. Instead a reverse

JET 16 - Introduction to Coiled Tubing  |  31

Figure 4-4. Knuckle Joint

Figure 4-3. Venturi Junk Basket

4.1.2.5 Knuckle joints Knuckle joints can be placed in a CT toolstring to provide flexibility, as they allow approximately 10o of angular movement (Fig. 4-4). They are generally located between the jar and fishing tool.

4.1.2.6 Lead impression block A lead impression block (LIB) is used to give a visual image of a downhole fishing neck or obstruction (Fig. 4-5). The tool is generally run on slickline, as it is much more sensitive to downhole forces than CT. If it is run before a CT fishing run, it can give valuable information.

32  |  CT Tool Conveyance

The LIB consists of a housing filled with the soft metal lead. An impression of the fishing neck or any wellbore obstruction can be created in the soft metal by running the tool into the fish neck at high speed. The results of LIBs are often open to interpretation because downhole completion hardware can create marks on the lead surface. Experience and a good knowledge of the particular wellbore are often required to interpret a LIB result.

4.1.3.1 Milling tools The following describe some milling tools. 4.1.3.1.1 Motor Downhole motors convert the hydraulic power of the pumped fluid into rotation.

Figure 4-5. Lead Impression Block

4.1.3 CT milling Milling with CT is commonly grouped together with fishing, as they are often used together on well intervention programs. Milling is the name given to the removal of an obstruction in the wellbore with a downhole motor and a milling bit. The obstruction is worn away by the rotating action of the abrasive bit. Some of the common applications of milling are • removing hard scale from a wellbore • milling out a nipple in completion to gain access to the lower wellbore • removing a downhole valve that will not open • milling out a composite temporary bridge plug after a fracture job • washing over an external fish neck that cannot be latched with a fishing tool

The motors used in CT interventions generally range in size from 1 11/16 in to 3 3/8 in. Many different configurations of output speed (rpm) and torque are available. The choice of motor will depend on the • size of the completion • size of CT (and maximum pumprate) • application • downhole temperature • fluid to be used.

4.1.3.1.2 Bit The choice of bit for a milling operation depends on what you plan to mill downhole. Choosing an unsuitable mill for a certain application will lead to an unsuccessful milling job. Some common mills are described here. • step mill: Step mills (Fig. 4-6) are widely used in removal of nipple profiles and scale removal (such as barium sulfate), using low torque output motors. The stepped profile of the mill allows it to gradually open up a restriction.

• milling out cement plug.

JET 16 - Introduction to Coiled Tubing  |  33

• bladed junk mill (Fig. 4-8): Extra long mill heads reduce risk of casing damage, are used for milling stationary and nonstationary objects, and have a rugged design for milling loose junk (metal debris inside the wellbore).

Figure 4-6. Step Mill

• bladed mill (Fig. 4-7): This type of mill is generally used on stationary objects in the wellbore such as cement plugs or drillable bridge plugs.

Figure 4-8. Bladed Junk Mill

• rotary shoe (or washover shoe) (Fig. 4‑9): This is a hollow cylindrical milling tool with a cutting structure on the internal bore, the bottom, and the OD. For stuck CT or tubing, it can be used to mill away formation, scale, sand, around the fish. It can also be used to mill away the slips on packers and bridge plugs to release it.

Figure 4-7. Bladed Mill

34  |  CT Tool Conveyance

4.2 Downhole valve/sliding sleeve manipulation Many modern completions have become more complex than the simple completions previously used. Smart completions are becoming more popular, as they allow the client to control the flow of oil and gas from individual zones in the same well. Downhole flow control valves or sliding sleeves can be controlled either from surface or manually shifted to achieve the desired flow from each zone. Figure 4-9. Rotary Shoe

• underreamer: An underreamer is a tool used to clean out below a restriction or in through tubing applications. Figure 4-10 shows how an underreamer can be run through the tubing and expanded in the casing.

In deepwater operations, different types of isolation valves are used to reduce the number of drillpipe trips needed during the well completion phase. While many of these completions are intended to be interventionless, most downhole valves have a mechanically activated backup function in case of malfunction. This function generally consists of shifting sleeves or opening flapper valves or ball valves with proprietary shifting tools. Downhole valves are opened or closed as required by setting down weight or pulling overpull when latched into the tool with the shifting tool. In wellbore deviations up to about 65o inclination, slickline is the preferred backup option because of the quick rig-up and very fast tripping speed.

Figure 4-10. Underreamer

The blades of the underreamer remain inside the tool for access through restrictions and then expand by centrifugal and hydraulic force when pumping begins and the downhole motor begins to turn. For recovery, the blades are retracted again by stopping pumping. An underreamer can be used to pass through the production tubing and to mill scale or a fish in the larger lower completion.

However, in more deviated and horizontal wellbores, either CT or a wireline tractor is used. A tractor is an electronic tool run on wireline that grips the tubing and pulls the toolstring into the deviated sections. Many smart tools have been developed for use with the tractor system, designed for operating flow control and isolation valves. Figure 4-11 shows the shifting tool for the Schlumberger formation isolation valve (FIV), which latches into the shifting mechanism to open or close the valve.

JET 16 - Introduction to Coiled Tubing  |  35

and has excellent results when compared to conventional techniques.

Figure 4-11. Shifting Tool

Sometimes the forces required to shift a downhole valve can be higher than what can be achieved within the limits of the CT string. In this case, run a jar or an impact hammer as part of the CT BHA to increase the force available downhole, also known as weight on bit. These tools can multiply the available force 5 to 10 times. They are described briefly in Section 4.1, CT fishing. The main advantage of using CT over a wireline tractor in this type of operation is the ability to pump through the CT string. Very often, when a downhole valve does not function correctly, the malfunction is due to fill or debris interfering with the valve mechanism. When CT is used, this fill can be removed by circulation or by running a Venturi junk basket BHA.

4.3 Blaster services The Blaster tool (Fig. 4-12) is a rotating high‑pressure jetting tool for conveying fluid and/or abrasives downhole for many different applications. This system reduces fluid usage

36  |  CT Tool Conveyance

Figure 4-12. Blaster Tool

Schlumberger developed the tool following comprehensive research into the physics behind jetting efficiency. The optimum jetting head and nozzles can be selected for each particular situation. The tool can be used for a range of applications including • acid washes • solvent washes • scale removal • screen cleaning • formation cleaning • perforation cleaning.

The system replaces traditional jetting and wash tools that are good at cleaning out loose fill only. Jet Blaster also replaces the more aggressive mill/motor or impact hammer

combinations, which can be damaging to the tubulars and downhole completion hardware.

4.3.1 Characteristics The Blaster tool has the following characteristics. • high-power jetting: The Blaster tool uses two to five nozzles on a continuously rotating nozzle head. The nozzles produce maximum jet efficiency, while the hydraulic brake in the swivel controls the rotation speed.

Nozzles facing downward are used to clean compacted fills, loose fills, or any other soft to medium bridging material. Radial nozzles (facing to the side) clean the tubular walls, perforations or screens. • engineered jetting system: The head and nozzles are selected (via the Jet Advisor* software) for each particular well to optimize the jetting efficiency and maximize power delivered to the nozzles. • drift ring: The drift ring ensures positive, one-pass cleaning, as it prevents penetration of the head until the deposit is removed to the diameter of the ring. The drift ring size selected depends on the application.

Figure 4-13. The Drift Ring

4.3.2 Applications The Blaster tool is very versatile and is suitable for various applications. It is often called a different name for different applications.

4.3.2.1 Bead Blaster/Scale Blaster Scale buildup in the tubing or casing restricts the flow of oil and gas (Fig. 4-14). It also prevents normal wellbore maintenance by preventing slickline and wireline access.

The drift ring will not allow large cuttings or debris to pass it until it has been broken down by the high pressure jets into smaller pieces. This ensures reliable circulation of cuttings and minimizes the chance of getting the BHA stuck. Figure 4-13 shows how the drift ring ensures that the tool stays at the point of the buildup until it has been removed.

Figure 4-14. Scaled-Up Tubing

Some scales such as calcium carbonate are soluble in acid or other solvents and can be removed by soaking. Other soft scale deposits

JET 16 - Introduction to Coiled Tubing  |  37

can be mechanically removed by jetting with a fluid. Hard scales (such as barium sulfate) cannot be removed by jetting with fluid alone; an abrasive must be added to the fluid. Materials such as sand are effective as abrasives, but damage the tubulars. Schlumberger found that Sterling Beads* safe hardscale removal system are very effective in removing scale, yet their spherical shape does not damage the metal tubing.

4.3.2.2 Bridge Blaster The bead Blaster can only be used if a hole exists through the scale for the nozzle head to enter. If the scale completely bridges off the tubing, the tool head can be configured with a modified mud motor and small mill to drill a pilot hole through the scale, while the radial jets widen the hole using Sterling Beads. This configuration is called the Bridge Blaster* brdige and scale remove service. The Bridge Blaster has also been used to remove cement plugs. Table 4-1. Bridge Blaster Specifications

Specifications Tool maximum OD

1.7 in [43.18 mm]

Maximum operating temperature

350 degF [180 degC]

Maximum flow rate

120 galUS/min (0.45 m3/min)

Wellbore fluids

Can be used in H2S environment

Treating fluids

HCl (to 28%), mud acid, aromatic solvents, DTPA, ETDA, nitrified fluids

4.3.2.3 Jet Blaster The Jet Blaster* jetting scale removal service is used for standard jetting applications, such as perforation cleaning, acid or solvent washes, and compacted fill removal.

38  |  CT Tool Conveyance

The rotating head uses two radial jetting nozzles to clean the wall of the tubing. For fill or bridged material removal, downward jetting nozzles can be added to the head. The system can be used to deliver dissolvers and/or acid to remove soluble scale or other obstructions. Jetting the dissolver into the target generates turbulence at the chemical contact surface, increasing the efficiency of the dissolver system. With this process the acid or solvent consumption can be reduced by up to 10 times over the bullheading technique.

4.3.2.4 Screen Blaster The screen Blaster is used for jetting plugged screens. Jetting solvents or acid into a screen with the Blaster tool ensures that the entire screen is treated, even those areas with heavy damage and very low permeability. Bullheaded fluid only enters the most permeable, lowdamage zones and bypasses the damaged low-permeability zones. In addition, jetting fluid into the screen can blast loose material off the outside of the screen, or from the gap between the base pipe and the screen. For soluble material, the increased turbulence caused by the jet raises the performance of the solvent by between 2 and 10 times, reducing the volume of reagent needed and the time needed to clean the well.

Note: For more information on the Blaster tool and applications, refer to the InTouch reference page, InTouch Content ID# 3251584

4.4 Zonal isolation Zonal isolation refers to operations where the primary objective is to isolate a section of the wellbore. It is achieved through packers, which provide mechanical isolation between two zones. The main types of packer systems used are • cup-type packers • mechanical packers (tension/compression set) • hydraulic set packers • inflatable packers

When fluid is pumped through the CT string, it exits the ports between the cups. The differential pressure across the cups forces the fluid to the tubing wall and provides a seal, forcing the fluid into the perforations. The cups relax again, then pumping stops. These packers are only used in shallow wells. The cups wear as they rub along the inside of the tubulars and are damaged by nipple profiles. The cups do not expand, therefore they cannot be set in a casing that is larger than the tubing above it. Cup-type tools are offten used for CoilFRAC applications.

• bridge plugs.

4.4.1 Cup-type packers Cup-type packers, are the simplest type of packers (Fig. 4-15). This packer is often set across a set of perforations to pump a treatment fluid, such as acid. The cup system isolates one section of wellbore and ensures that the fluid treats the selected perforations.

4.4.2 Mechanical Mechanical packers require the toolstring to maintain an adequate load on the packer to keep it set. Depending on the packer, the load can be tension or compression. A tension-set mechanical packer (Fig. 4-16) is set by pulling tension on the CT string. It can be released by relaxing the tension. Similarly, a compression-set packer is set by setting load on the packer and released by pulling upwards. Mechanical packers can be set multiple times in one run. These packers are often used to hang CT velocity strings or tailpipe extensions in a wellbore. The weight of the CT string hanging below the packer keeps it in tension and set

Figure 4-15. Cup-Type Packer JET 16 - Introduction to Coiled Tubing  |  39

Figure 4-17. Double Grip Hydraulic Packer

Figure 4-16. Mechanical Packer in Tension-Set Configuration

4.4.3 Hydraulic set The majority of hydraulic packers being used are double grip (Fig. 4-17), which means that they include two sets of slips to grip in both directions. Typically, setting these packers is achieved by increasing the internal pressure compressing the sealing element and forcing the slips outward. As the packer sets, the shifting mechanism is held in place by a body lock ring, or ratchet, so that when the pressure differential is released, the packer stays set.

40  |  CT Tool Conveyance

To retrieve the packer, vertical pull will shear release screws or pins, allowing the slips and element to retract. Hydraulic set packers are being used extensively in gravel packs, patches, and gas lift installations.

4.4.4 Inflatable Through-tubing inflatable packers, such as CoilFLATE* inflatable packers (Fig. 4-18), are designed to seal in a casing section that is larger than the tubing above it. The packer needs to be small enough to run and retrieve through the tubing, but when set, it expands to two or three times its original diameter. The higher the expansion, the lower the pressure differential it can withstand.

4.4.5 Bridge plug Retrievable bridge plugs (Fig. 4-19) can be fished again and are used to temporary isolate a well for operations such as wellhead repair or upper zone stimulations.

Figure 4-18. Setting Sequence for CoilFLATE Packer

Single-set inflatables are most commonly used as bridge plugs or isolation tools. Multiple-set inflatables can be set several times in one run and are ideal for remedial and stimulation operations or testing. When pressure is applied to an inflatable through the CT string, hydraulic valves trap the setting pressure in the inflatable element, holding the packer in place even when the tubing pressure is reduced. A straight pull allows the pressure to release and the packer element to relax for retrieval. Inflatable packers can be used as retrievable bridge plugs, cement retainers, or treatment packers.

Figure 4-19. Bridge Plug

Permanent bridge plugs are used to plug depleted zones or for abandonment. Cast iron or composite bridge plugs are sometimes used because they are easily drillable. When a well is fractured multiple times using a drilling rig, previous fractured zones are often isolated with drillable bridge plugs before fracturing the next zone. When all zones have been fractured, the bridge plugs can be drilled out with CT.

4.5 CT Logging Logging refers to the downhole surveys carried out with very specialized electronic tools to gather detailed information on the formation and wellbore (Fig. 4-20). The Schlumberger Reservoir Evaluation Wireline (REW) division provides logging services. JET 16 - Introduction to Coiled Tubing  |  41

cable that allows signals to be transmitted in both directions. As the tool is run across the zone of interest, the tool gathers data and sends it back to the surface. This process can be conducted in wells with deviations up to 65 degrees. However, in highly deviated or horizontal wells, the tools cannot be conveyed to the bottom of the well using wireline, as wireline cannot push them. In this case, logging tools can be made up to the downhole end of the CT string and run in hole in a normal CT run. CT has the advantage over wireline in that it can push the tools into horizontal sections because of its strength and rigidity.

Figure 4-20. Typical Wireline Log Data

Logging applications can be divided into two main groups:

4.5.1 Logging on CT When running the logging tools on CT, there are two methods to retrieve the log data; in real-time or memory mode.

• Openhole logging gives valuable reservoir information about the location and amount of oil and gas. This survey is performed in the openhole section before setting a casing or liner. • Cased hole logging is used to confirm or identify the formation and completion characteristics. Cased hole logging evaluation is performed after a well has been completed.

Many specialist logs are available to gather complex data on the reservoir and well. The basic data gathered by logs includes

CT unit equipped with CTL reel

Optional safe tool deployment system

Logging unit

• presence of oil or gas • type of rock (lithology) • reservoir porosity and permeability • production logging (profile of the production across the reservoir).

Generally, logging tools are run into an oil or gas well on wireline. Wireline is a conductive 42  |  CT Tool Conveyance

CTL string CTL support tools Logging tools

Figure 4-21. CTL Principal Equipment Components

4.5.1.1 Real-time CT logging

4.5.1.2 Memory mode CT logging

In real-time, information is transferred uphole through a wireline cable installed inside the coiled tubing. Real-time downhole data allows the logging engineer to make better decisions easier (Fig. 4-22).

In memory mode, information is recorded in the tool and later retrieved at the surface for analysis. Memory mode does not require a wireline cable to be installed inside CT. The advantages are • Standard CT string can be used; there is no need for expensive cable and time‑consuming installation. • Standard ball-activated tools can be used in the BHA.

The disadvantages are

Figure 4-22. Real-Time Downhole Data

The advantages are • Real-time data allows engineers to change parameters and optimize logging operation based on the information received. • A tool failure can be noticed immediately.

The disadvantages are • Ball-activated tools cannot be used when an electrical cable is inside. This means that specially designed disconnects and circulation subs are required for wired CT applications. • Installing a wireline cable into a CT string takes time and expertise. • Cables can be easily damaged during installation or removal. •

• No data can be seen until the tool is retrieved at the end of the logging operation. This means that the operation cannot be optimized during the job based on real-time data. • If the memory tool fails to record good data, a lot of time is wasted because this only becomes apparent after the operation and then the operation may have to be redone.

4.5.2 Logging cables The majority of CT logging operations are done in real time with a cable inside the CT string. There are three main types of electrical cable, classified by the number of conductors inside the cable. The choice of cable depends on the requirements of Wireline tools being run as the BHA. • monocable (Fig. 4-23): one-conductor cable (production logging and perforation) • coaxial cable (Fig. 4-24): two-conductor cables (production logging and perforation) • heptacable (Fig. 4-25): seven-conductor cables (openhole logging).

JET 16 - Introduction to Coiled Tubing  |  43

Outer jacket - EPC orange Inner armor (10) Insulation - EPC Seating wires (2) Outer armor (9)

Conductor

Figure 4-23. Monocable Configuration Outer jacket - EPC orange Serve insulation - tefzel Inner armor (10) Seating wires (2) Outer armor (9) Serve or shield Insulation - EPC Conductor

the conductors from mechanical damage and take the tensile and compressive forces exerted on the cable. Ideally, the cable will be plastic-coated for CT applications. This helps prevent corrosion on the cable inside the CT string. Several types of plastic coating are available and the choice depends on the well temperature.

Note: Before carrying out any logging operations, be sure to measure the insulation and continuity of the cable. These checks will reveal problems, such as a short circuit or damaged insulation. The measurements are typically done by the wireline team and should be carried out with the reel under pressure. If a CT logging string is in storage, check the insulation and continuity regularly; for example, every 6 months.

Figure 4-24. Coaxial Cable Configuration Outer jacket - EPC orange Void packing - EPC Taped core assembly Inner armor (18) Seating wires (2) Conductor insulation - EPC

Outer armor (15) Filler rod (4) Conductor

Figure 4-25. Heptacable Configuration

The conductor cables are surrounded by two layers of armor cable. The armor cables protect 44  |  CT Tool Conveyance

4.5.3 Installing a cable The most common cable installation method involves pumping the cable into the CT string. The most common cable injection systems are the flow tube and capstan injection systems. The flow tube (sometimes called skinny pipe) injection method circulates fluid through the CT string via a long inject pipe (Figs. 4-26 and 4‑27). The drag force on the cable created by the fluid pushes the cable into the CT reel. The flow-tube cable injection system requires a significant amount of space because of the length of flow tube required. It also requires more pump horsepower than the capstan system does.

CT string with cable installed

High-pressure fluid drain with choke to control CT reel pressure

The capstan drum system is the most reliable method of removing a cable from a CT string without damaging it.

Flow-tube with cable inject pipe

High-pressure fluid inlet Small diameter flow-tube for cable seal Fluid leakage drain

Leakage control tube/seal

Figure 4-28. Capstan Drum

Cable drawn from stroage reel

Figure 4-26. Flow Tube Injection System Schematic

Figure 4-29. Capstan Drum Grooves

Figure 4-27. Flow Tube Injection System

4.5.3.1 Cable slack

The capstan installation system uses a capstan drum (Fig. 4-28). The cable is fed into the drum and spooled around the guide path grooves (Fig. 4-29). During the installation, fluid is circulated through the CT string and the cable is fed into the flow path in a controlled manner.

When installing a cable, be sure to let some slack (extra cable) into the CT string to avoid pulling tension on the electrical cable. Problems can occur because the electric cable tends to lie on the low side of the spooled CT string, making the length of the cable slightly shorter than the length of the CT string (Fig. 4-30). In JET 16 - Introduction to Coiled Tubing  |  45

a vertical wellbore, this effect will pull the cable into tension and possibly pull the cable out of the BHA.

connection with the uphole end of the cable inside the CT string. CTPB housing

Insulator carrier

Radius of CT string RCT

Radius of cable RCAB

Figure 4-30. Electrical Cable Position Inside Spooled CT String

At the end of the installation, when the end of the cable reaches the end of the CT string, clamp the cable to prevent it from coming out of the string. Then, continue pumping to push an extra length of cable into the string to provide the cable slack. The general rule is • monocable: 1% of entire length • heptacable: 0.5% of entire length.

For example, if you are installing a heptacable into a 5,000-m [16,405-ft] CT string, the amount of cable slack to be pumped is • 5,000 m x 0.005 = 25 m [82 ft]

Ensure that the cable slack is distributed along the length of the string. During downhole operations, the slack tends to move towards the downhole end of the CT string. Pump the cable towards the uphole end after logging operations to maintain an even distribution in the string. This process is called slack management.

4.5.4 Surface equipment There are two main pieces of CT logging surface equipment. • pressure bulkhead (Fig. 4-31): The pressure bulkhead enables a pressure‑sealed electrical

46  |  CT Tool Conveyance

Cable protector CT logging cable installed

Figure 4-31. Pressure Bulkhead

• reel collector (Fig. 4-32): As the CT reel rotates, so does the electrical cable. The reel collector enables an electrical connection between the cable in the rotating reel core and the surface monitoring and recording equipment. Different types of collectors are used for different types of reel.

Surface computer

Logging unit bulkhead connection or

• mechanical connection to the CT string (Fig. 4-33): The logging head must provide a means of mechanical connection to the CT string. Some tools include an integral CT connector as part of the tool, others are made up to a separate CT connector by a standard CT thread.

CT control cabin CTSI box

CT reel core cable

CT pressure bulkhead

Upper end connected to CT connector

Reel collector CTL string and logging cable

Cable anchor

Check valves Logging head and toolstring Fluid circulation ports Internal electrical connection Pressure bulkhead

Figure 4-32. Reel Collector in CT Logging Surface Equipment

4.5.5 Downhole equipment There are two main items of CT downhole equipment: the logging head and the CT deployment bar.

4.5.5.1 CT logging head The logging head is the upper assembly of the logging BHA run on CT. Several models are in use worldwide, but the following are common functions:

Fluid flow through check valves exiting through ports in the check valve housing

Mono connection (multiple conductor options available) Standard wireline logging tool connection

Figure 4-33. CT Modular Head (CTMH)

• double check valve assembly: Double flapper check valves are required in CT logging as in all standard CT operations. A special model must be used for CT logging since it requires a sealed bypass for the electrical cable. • allow fluid circulation: Fluid circulation ports are needed to allow fluid or nitrogen circulation or N2 lifting as part of the program.

JET 16 - Introduction to Coiled Tubing  |  47

• contingency release: A disconnect releases the logging toolstring in case it becomes stuck and cannot be recovered. Ball activated disconnect tools cannot be used because of the electrical cable inside. Generally, mechanical disconnects are used. These can be released by pulling a known amount of overpull on the stuck tool. • secure logging cable: The electrical cable inside the CT string can move up and down during operations. The logging head needs to secure the logging cable to ensure it does not move, as this will break the electrical connection with the logging toolstring. • electrical connections between cable and toolstring: The number of connections required will depend on the logging toolstring requirements and the type of logging cable installed in the CT string.

Upper thread protector Upper head

Split threaded ring

Mandrel

Conductor carrier

Lower head

4.5.5.2 CT deployment bar A CT deployment bar (CTDB) enables long toolstring deployment and retrieval under well pressure (Fig. 4-34). The bar temporarily holds the logging toolstring in the BOP while the next assembly of the logging string is made up. It is generally the same diameter as the CT string being used, so it can be hung in the pipe and slip rams. The CTDB is configured with standard logging tool connections on top and bottom to ensure reliable mechanical and electrical connections.

48  |  CT Tool Conveyance

Lower thread protector

Figure 4-34. CTDB Cross-Section

4.6 CT perforating Perforation refers to the process of shooting holes in the wellbore cemented casing or liner to enable oil or gas flow from the reservoir into the wellbore (Fig. 4-35). Perforation is generally done with explosives deployed in special perforation guns.

1 foot shots per foot

Casing hole size

Figure 4-35. CT Perforating

Perforation is a highly specialized technique because the performance of the explosives has a very large impact on well production. Depending on the type of well and formation, the client may want to achieve very deep perforations into the reservoir, or short perforations with a wide hole in the casing. Perforations are classified in terms of their phasing (angle), number (shots per foot or spf), casing hole size, and depth of penetration (Fig. 4-36).

60 O Phasing

Depth of perforation

Figure 4-36. Perforation Terms

The pressure conditions under which the perforation is carried out can have a significant impact on well production. • at-balance: The pressure of the fluid column in the wellbore is equal to than the formation pressure. • overbalanced: The pressure of the fluid column in the wellbore is greater than the formation pressure. When the gun is shot, fluid flows from the wellbore into the reservoir. This can harm the reservoir if it is sensitive to the wellbore fluid. It does not help in cleaning up the perforation tunnels.

JET 16 - Introduction to Coiled Tubing  |  49

• underbalanced: The pressure of the fluid column in the wellbore is less than the formation pressure. When the gun is shot, fluid flows from the reservoir into the wellbore. This helps clean up debris in the perforation tunnels and avoids getting potentially damaging wellbore fluid into the reservoir.

Figure 4-37 shows perforation tunnels for overbalanced and underbalanced scenarios. Overbalanced perforation after flowing Part of low-permeability zone still exists

Perforation partially plugged with charge debris

Ideal underbalanced perforation immediately after perforating

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

Figure 4-37. Perforation Tunnels Scenarios

The conditions chosen for a particular well will depend on the type of rock in the reservoir, as no single condition suits all situations.

4.6.1 Perforation techniques Schlumberger Well Services does not directly select the perforation technique for a particular well, as this expertise is held in the Schlumberger Reservoir Evaluation Wireline (REW) and Tubing Conveyed Perforation (TCP) divisions. In the majority of cases, perforation guns are run into a wellbore on wireline. The wireline operator can achieve a high level of depth 50  |  CT Tool Conveyance

control using signals from the gamma ray (GR) or casing collar locator (CCL) tool. When the guns are at the correct depth, the operator sends an electrical signal from surface through the wireline to detonate the guns. However, in highly deviated or horizontal wells, the guns cannot be conveyed to the bottom of the well using wireline, as wireline cannot push them. A second limitation of wireline is its low load capacity, which means it cannot run a long and heavy gun string. The options used when wireline cannot be used are • tubing conveyed perforation (TCP): The guns are run into the well on a string of tubing or drillpipe • CT perforation: The guns are run on the end of a CT string.

4.6.1.1 CT perforation CT perforation is almost always carried out as a through-tubing operation. This means that the production tubing is already set in the well and the wellhead is in place. The guns need to fit through the wellhead and tubing, and this generally limits the OD of the guns. Some typical sizes of guns run on CT are: 2 1/8 in, 2 7/8 in, 3 1/8 in, 3 3/8 in, 4 1/2 in. Depth control is extremely important in perforation because accuracy when setting off the charge means obtaining the desired flow versus missing the pay zone at inaccurate depths. This is one of the main challenges of carrying out perforation on CT. The main advantages of CT perforating are • rigidity: can run in highly deviated and horizontal wellbores • strength: can run much longer gun strings than on wireline

• underbalanced perforation: full well control allows the wellbore pressure be regulated to allow for underbalance • quick cleanup: completion and testing equipment are ready to flow back the well immediately if desired. This can help minimize any damage to the reservoir.

collar locator (CCL). It recognizes the collars on the casing downhole and uses pressure pulse technology to send a signal to surface at each casing collar. Using a baseline log and software at the surface, the exact depth of the guns can be known (Fig. 4-38).

• ability to pump: well pressure can be adjusted lower than formation pressure • pressure deployment: CIRP* completion insertion and removal under pressure system to deploy and reverse deploy guns into a wellbore under pressure • time reduction: operating time reduced compared to TCP.

There are two different methods of activating or firing the perforation guns on CT: hydraulic and electrical. These methods are described below. 4.6.1.1.1 Hydraulically activated perforation A standard CT string is used and the firing mechanism is activated differently depending on the type of firing head used: • pumping a ball through the CT string and pressuring up (CBF-AA firing head) • pressuring up the CT string or annulus (BCF firing head) • pressure pulses (e-Fire* electronic firing head system)

The pressure required to activate the firing head is predetermined on the surface, by changing the number of shear pins in the tool. With this technique, depth correlation is often done mechanically by tagging a known depth in the completion with a TEL or TNL. However, Schlumberger has also developed the DepthLOG* CT depth correlation log, a more advanced depth correlation method that is used in some locations. This electronic tool is based on the wireline casing

Figure 4-38. DepthLOG Log

4.6.1.1.2 Electrically activated perforation Electrically activated perforation is almost the same as perforation on wireline because it requires a CT string with a cable inside it (a CT logging string). In this case, the CT is only used to place the guns in the correct position, and the gun firing is controlled from the wireline unit. The main advantage of this method is the accurate depth correlation.

JET 16 - Introduction to Coiled Tubing  |  51

The CT logging head is the interface between the cable and the electrical firing head on the wireline toolstring.

a small number of locations, where there are enough suitable candidates to make a CTD project feasible.

It is important to note that balls cannot be circulated through the CT string when there is an electrical cable inside. This means that specially designed disconnects and circulation subs are required for wired CT applications. A standard mechanical disconnect used for CT logging cannot be used for CT perforation as the shock of the perforation will often cause an unwanted disconnect. A tool such as the nonwired multicycle disconnect (MCD) is approved for CT perforation. This requires a combination of overpull and CT cycling to release.

CTD is used in the following applications:

The equipment used on surface is the same as those used on CT logging operations.

4.7 CT Drilling CT drilling (CTD) is a special application of CT (Fig. 4-39). It does not compete with conventional rig rotary drilling for the majority of applications, but there are certain types of wells for which CTD makes technical and economical sense.

• underbalanced drilling • short radius wells • multilateral applications • through-tubing reentry

Typically, the larger CT strings (2 in, 2-3/8 in and 2-7/8 in) are used in CTD. These sizes allow the higher pump rates needed to lift the drilling cuttings to surface. They can also achieve good WOB downhole, which is a key factor in drilling efficiently.

4.7.1 Conventional and CTD comparison There are some important differences between CTD techniques and conventional drilling techniques. • string rotation: Conventional drilling is based on rotary drilling, which means the drill string is rotated. A CT string cannot be rotated, therefore CTD must use downhole motors, orienting tools, and other special equipment to replace the ability to rotate the pipe. • circulation: With normal drilling operations with drill pipe, circulation of the well needs to be stopped to make up the connections. Many problems like lost circulation and stuck pipe can occur during this period. In CTD, there are no connections to make up, so continuous circulation is achieved.

Figure 4-39. Schlumberger CTD Unit in Alaska

Because of the specialized nature of CTD, it is carried out by experienced teams in only

52  |  CT Tool Conveyance

• WOB: In conventional drilling, the WOB comes from the weight of the drillstring in the hole. In CTD, the injector head applies additional snubbing forces to the CT string in addition to the weight of the CT string itself.

4.7.2 CTD advantages CTD has several advantages over conventional drilling: • smaller rig footprint • reduced reservoir damage because of underbalanced drilling techniques • continuous circulation • faster tripping operations (continuous pipe, no connections required) • safe drilling with multiphase fluids (foam and nitrified fluids) • efficiently monitoring and controlling downhole pressures • real-time downhole measurements of surveys, logging data, and pressure data using a wireline inside the coiled tubing • superior directional control because of steering at BHA.

4.7.2.1 Underbalanced vs. overbalanced One of the most important advantages of CTD is the ability to carry out all operations (drilling, tripping, and completion) in an underbalanced situation. Underbalanced means that the hydrostatic pressure exerted by the wellbore fluid is less than the reservoir pressure, which allows the reservoir fluid to enter the wellbore during operations. This state means that the well is live at all times. The fact that very little drilling fluid enters the reservoir reduces the damage to the reservoir. The CT pressure control equipment (strippers and BOPs) allows safe operations in live wells.

Conventional drilling is carried out in an overbalanced situation. This means a heavier drilling fluid is used so that the hydrostatic pressure of the drilling fluid is greater than the reservoir pressure. This controls the reservoir pressure and prevents reservoir fluid (oil or gas) from entering the wellbore. The loss of drilling fluid to the reservoir can damage the reservoir and affect future production. Conventional rotary drilling rigs cannot drill underbalanced, but certain rigs have been fitted with specially developed pressure control equipment to allow underbalanced drilling. However, the well must still be killed for tripping and completion operations, which will cause reservoir damage.

4.7.2.2 Real-time information Another major advantage of CTD is the ability to install a wireline inside the CT string. Running electric steering or logging tools as part of the drilling or completion operations can be carried out quickly and efficiently. This ability to perform trips quickly is a major advantage when performing operations on deep wells.

4.7.2.3 Environmental impact CT units are used to drill in environmentally sensitive areas because of the efficiency in using a closedloop system with no connections. The CT drilling package has less exhaust emissions and greatly reduced noise levels. Because small holes are drilled, educed quantities of drilling fluids must be mixed and less drill cuttings must be disposed of.

CTD allows the well to be maintained in an underbalanced state throughout the drilling and completion operations, virtually eliminating any wellbore damage and possibly reducing the need for well stimulation afterwards.

JET 16 - Introduction to Coiled Tubing  |  53

4.7.3 CTD disadvantages There are, however, disadvantages to CT drilling. These include the following: • limited life of the CT itself (i.e., cycle fatigue), especially in larger CT sizes • less industry experience compared with conventional drilling • reduced horizontal-reach potential, because of sliding friction • additional operating cost because of the need for a downhole motor.

Perforated interval may be squeezed off or remain open

4.7.4 CTD applications CTD has several applications.

4.7.4.1 Previously drilled wells Most CTD operations are carried out in previously drilled wells. Typical examples of this are • deepening an existing well to access deeper reserves (Fig. 4-40) • drilling a horizontal sidetrack to increase production from an old well.

CTD is economically attractive in this situation because the existing well and surface production equipment is used for the new well. CTD in previously drilled wells can be performed as a through-tubing reentry or a casing reentry.

Producing formation(s) below production casing/liner shoe

Figure 4-40. Typical Well Deepening Configuration

4.7.4.2 Through-tubing reentry sidetrack Through-tubing reentry sidetrack is when the CT reenters the wellbore through existing production tubing (Fig. 4-41). This method requires the entire BHA to pass through the tubing. This method is used to deepen wells and for directional sidetrack to increase flow area or access new reservoir targets. The wellbore is exited either through the tubing and casing, or through the casing below the production tubing. Through-tubing method eliminates the cost of • pulling the tubing and associated completions equipment • running production tubing after drilling. This method can be performed with either overbalanced or underbalanced techniques.

54  |  CT Tool Conveyance

Minimum disruption to wellhead equipment

Original completion equipment in place

4.7.4.4 New wells CTD can be used to effectively drill small wellbores (up to 12 1/4 in) from surface. It is typically used only in shallow gas pilot wells, where high-pressure shallow gas can cause blowouts on conventional rigs. The advantage of the CT pressure control equipment is greatly increased safety for this operation. In these cases, the CT unit is used to drill the first 450 to 900 m [1,500 to 3,000 ft] and a conventional rig continues from this point.

4.7.5 Surface equipment New side-tracked wellbore

Original wellbore typically abandoned below kick-off point

Figure 4-41. Through-Tubing Reentry Sidetrack

4.7.4.3 Casing reentry sidetrack

The surface equipment required for a CTD operation is similar to standard CT operations, with some additional features related to the drilling fluid handling and pumping.

4.7.5.1 Returns handling equipment An equipment package is required to handle and store the returned drilling fluid on surface (Fig. 4-42).

With casing reentry, the existing production tubing and packer are removed before the operation. The CT reenters the wellbore through the casing. Casing reentry is used to deepen wells or for sidetracking and horizontal drilling. CT is most effective economically when used • to perform short radius drilling • when in environmentally sensitive locations • offshore on platforms where a full drilling rig is cost prohibitive.

Casing reentries are performed with either overbalanced or underbalanced techniques.

Figure 4-42. Typical CTD Surface Equipment Layout

JET 16 - Introduction to Coiled Tubing  |  55

This equipment package performs the following functions: • removes drill cuttings and solids • removes gas from the drilling fluid • provides storage tank volume to hold drilling fluid • samples returned fluid • mixes new drilling fluid • provides choke line and choke manifold • provides pipework and hoses.

For underbalanced operations, some additional equipment is necessary to deal with the oil or gas, which returns with the drilling fluid.

4.7.5.2 Pumping equipment CT drilling requires long periods of continuously pumping drilling fluids and does not normally employ the same high- and low-pressure pumping equipment used in other CT applications.

Figure 4-43. Single Pump Float ,SPF-243

4.7.5.3 Substructure In most CTD operations, a jacking frame or CT support frame is used to support the injector head. Hydraulic rams in the legs raises the frame, enabling safe and easy assembly and break out of the long toolstrings associated with CTD. Figure 4-44 shows a typical substructure. Using the frame means a crane is not required to support the injector during the entire operation.

Plunger pumps, capable of pumping drilling fluid for long, uninterrupted periods are used, similar to those used in conventional drilling operations. To reduce personnel required, mud pumps are positioned with controls in the CT cabin so that the operator can start and stop the pumps as required to operate orienting tools and other downhole equipment. The single pump float, SPF-243 shown in Fig. 4‑43 can be used for CT drilling applications.

Figure 4-44. Typical CTD Substructure

56  |  CT Tool Conveyance

4.7.6 Downhole equipment There are three main types of BHA used in CTD (Fig. 4-45): • nonsteered drilling BHA • directional drilling BHA • window-milling BHA. CT string

CT connector

+/- 3 ft

Check valves Release joint

WOB

Drill collar(s)

Motor +/- 10 ft

Bit

Figure 4-45. CT Bottomhole Assembly

4.7.6.1 Nonsteered drilling applications BHA Nonsteered CTD is typically used for deepening an existing wellbore. A standard CT string without an electrical cable is used. The BHA consists of

in CTD operations. The connector must be able to withstand the rotational forces applied by the downhole motor. • double flapper check valves: Check valves are run to prevent backflow into the CT that could cause BHA plugging. They also provide an internal safety barrier for the CT in case of a well control event. • release mechanism: Generally a hydraulic‑release tool is run for this application. This is activated by pumping a ball through the CT string from surface, and pressuring up the string when it is sitting in the tool. • drill collars: Drill collars (if needed for vertical wells) are heavy-weight pipes. For vertical wellbores, a small number of drill collars (typically 2 or 3) is used to assist in maintaining a straight wellbore. They are most effective when drilling softer formations or where low weight-on-bit is needed. Spiral downhole collars are preferred since they stick less. • downhole motor: The most commonly used downhole motor is a positive-displacement motor (PDM). The PDM is driven by the drilling fluid that passes through the motor. The fluid passes through a rotor/stator section (similar to a spiral) and causes the inner rotor to rotate.

These motors come in different configurations for different speed and torque capabilities, as recommended for a particular formation. Typically, higher-torque motors are preferred for CT drilling. • bit: The drill bit (or simply bit) comes in contact with the formation to be drilled. When rotated by the motor, the abrasive face of the bit grinds away the formation, deepening the wellbore.

• coiled tubing connector: A dimple-type connector is the most common type used

JET 16 - Introduction to Coiled Tubing  |  57

The two most common types of bits are ○ fixed cutter (sometimes called drag bits) ○ roller-cone bits.

Fixed cutter bits have no bearings and no rotating parts. They use a shearing action similar to machining to cut the rock as they are rotated by the motor above. The most common bits are ○ PDC (polycrystalline diamond compact), for soft-to-medium formations ○ TSP (thermally stable polycrystalline), for medium-to-hard formations ○ diamond, for hard formations.

Fixed cutter bits can be rebuilt (or redressed) and used again. Roller-cone bits come in a variety of configurations. They come in one to four cones on larger bits. The most common configuration is the tri-cone bit. The teeth are either milled steel or tungsten carbide inserts with various nozzle configurations to assist in debris removal. Many of the new designs can also be found with diamond-coated cutters to resist wear.

4.7.6.2 Directional drilling BHA Directional drilling is used to steer a wellbore to an exact target location in the reservoir. Two types of bottomhole assemblies are used to perform directional drilling operations: wireless telemetry and wireline telemetry. • wireless telemetry BHA (Fig. 4-46): Wireless telemetry uses either mud pulses or electromagnetic signals to communicate measurements from the BHA to the operator at the surface. Both systems are convenient because the directional drilling assembly attaches to the end of a standard CT string and sensors at the surface 58  |  CT Tool Conveyance

receives the data. Full access through the CT is possible, so many of the drop-ball activated tools used with nonsteered BHAs can be used. 1 1/2-in DH motor with bent housing Hydraulically operated orienting tool

1 3/8-in CT

4 1/8-in PDC bit Nonmagnetic collar with slim 1 MWD tool Hydraulic release circulating sub CT connector

Figure 4-46. Wireless Telemetry Directional Drilling BHA

The difference between wireless telemetry and a nonsteered BHA is the measurementwhile-drilling (MWD) tool. This tool collects data, including well inclination, gamma ray, and casing collar locator and transmits the data to surface using mud pulses or electromagnetic signals. The data informs the drilling engineer of the toolstring location in the reservoir so he can make any needed changes. • wireline telemetry BHA: Wireline telemetry is a direct, wired connection to communicate measurements from the BHA to operators at surface via surface equipment developed for CT logging. This system allows much higher datatransmission rates than wireless telemetry systems.

Special tools are needed to disconnect and perform other functions downhole, because the wireline cable does not allow the use of ball‑activated tools. Electrical or mechanically‑activated (multi-cycle) disconnects are used.

4.7.6.3 Milling windows Window milling refers to cutting casing to begin directional drilling. In most cases, the direction is achieved by using a • whipstock • cement plug • combination of the two.

Typically, mills are used to mill steel (such as windows in casing, junk, scale,), but are poor for drilling most formations. Mills can be used to mill cement plug kickoffs. Figure 4-47 shows a typical whipstock. The whipstock is a hard metal device set in the casing that guides the mill into the side of the casing. The mill produces a cut or window in the casing.

Window mailing assembly run to cut window and 5 to 10-ft formation

Watermelon mill assembly (or similar) used to dress window

Figure 4-48. Windows Mailing and Watermelon Mill

This illustration shows both the side-cutting mill (or speed mill) used to cut the casing and the watermelon mill used to expand and dress the window. After milling the window through the casing of the well, the directional drilling assembly is then used to continue drilling in the formation to the reservoir target.

Figure 4-47. Directional Drilling BHA

Figure 4-48 shows how a whipstock can be used to guide the BHA to the casing wall. The second BHA includes a watermelon mill to dress the window.

JET 16 - Introduction to Coiled Tubing  |  59

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60  |  CT Tool Conveyance

5.0  CT Completions The term completion refers to the production tubing and associated downhole completion hardware in a well. The typical tubing sizes are 2 7/8 in to 5 1/2 in, although smaller and larger tubing exist. CT completions are applications where a CT string or a section of a CT string is left in the wellbore as a permanent part of the completion (Fig. 5-1). In most cases, the CT completion is run with a standard CT unit and equipment. Many CT completion applications are low‑cost methods to prolong the life of old wells where production is declining or the completion is damaged. However, there are also high‑tech applications where there is a technical advantage to use a CT completion in new wells.

Production tubing

Production packer

Casing

CT completion applications have several advantages over completions run with conventional workover rigs. They are • less expensive

Perforations

• generally quicker • less damaging to the formation when working in live wells.

The following CT completion applications are described in this section: • CT velocity string • CT tailpipe extension • CT tubing patch

Figure 5-1. Main Parts of a Standard Completion

Note: Refer to CT Completion Services and RedaCoil InTouch Reference Page, InTouch Content ID# 3311242, for more information.

• Electric submersible pumps (ESP) • Spoolable* safety valves for CT • Through-tubing gravel pack.

JET 16 - Introduction to Coiled Tubing  |  61

5.1 CT velocity string Over the life of many oil and gas wells, production rates decline and the composition of production fluid changes. These changes require a reduction in the size of production tubular to maintain production efficiency. A CT string can be hung permanently inside existing production tubing to reduce the cross‑sectional flow area of the production tubular. This is known as a velocity string (Fig. 5-2) since the reduced flow area yields higher flow velocity for a given production rate. The well can be flowed either through the CT string itself or through the annulus between the CT string and the existing production tubing. Figure 5-3. Water Buildup Removed by Using CT Velocity String

In many cases, the CT string is hung in a special flanged hanger on the wellhead. However, this method can disable surface and downhole valves because the CT string is running through them so that they cannot be closed. Another system uses a packer to hang the CT string below the downhole safety valve so that the valves remain fully functional.

Figure 5-2. CT Velocity String Configuration

CT velocity strings are particularly popular in old gas wells where an increase in water content is causing inefficient flow. The higher flow velocity helps the gas to lift the water to surface more efficiently, which prevents water buildup and inconsistent flow (Fig. 5-3).

The CT string is generally run in hole with a pumpout plug or check valve system to prevent oil or gas entering the CT string. This is expelled with pressure after hanging the CT string. After installation, the well produces up the velocity string, but in some cases, the CT‑tubing annulus is used for production. An old CT string with little remaining fatigue life is frequently used as a CT velocity string. The coiled tubing string may remain in the well for several years and can be retrieved when necessary using CT equipment again.

62  |  CT Completions

CT velocity strings are the simplest and most widely used of all CT completions. Figure 5-3 shows that in mature gas wells, a CT velocity string can help produce water buildup to surface. This water buildup can kill a well if it cannot be produced.

5.2 CT tailpipe extension A CT tailpipe extension (Fig. 5-4) is a shortened version of a velocity string. It is a length of CT string hung at the end of an existing production tubing to extend the tubing closer to the perforations.

This tailpipe system is simple and quick to install.

5.3 CT tubing patch A CT tubing patch (Fig. 5-5) is CT string hung in a completion for one of the following reasons: • cover a hole in the tubing due to mechanical damage or erosion • permanently shut off a sliding sleeve • isolate perforations.

Upper packer

Tubing leak

Length of CT string

Lower packer Tubing Pressure Annulus Pressure

Figure 5-4. CT Tailpipe Extension

The tailpipe can be hung in an existing nipple or by a simple packer. The most common application for CT tailpipe extensions is in old gas wells, where the well is producing water with the gas. The tailpipe extension allows the well to flow more consistently and reduces any slugging effect.

Figure 5-5. Tubing Patch

Packers are set at the top and bottom of the CT tubing patch to hold it in position and provide the seal between the existing completion and the CT string.

JET 16 - Introduction to Coiled Tubing  |  63

5.4 Electric submersible pumps In low-pressure oil fields, artificial lift techniques are used to produce the oil to surface. One type of artificial lift is electric submersible pumps (ESPs). ESPs are electric pumps installed at the bottom of the production tubing to pump oil to the surface in wells that would produce little or no oil if allowed to flow naturally. ESPs are generally installed by a conventional or workover rig on standard completion tubing, but there are advantages to installing them on a CT string hung permanently in the well. The main advantages of ESPs run by a CT unit rather than with a rig include • faster installation • cable can be run inside the CT string (protects the cable) • no cable splicing or cable bands • no need to kill the well and damage the formation • full pressure control at all times • cheaper day rates.

ESPs need to be serviced or changed every few years. When you consider the cost of multiple rig mobilizations, a CT-deployed system becomes even more attractive. The Schlumberger RedaCoil* CT-developed ESP system is a collaboration between the Well Services and Artificial Lift divisions (Fig. 5‑6). The system has a successful history in CT‑deployed ESPs.

64  |  CT Completions

Figure 5-6. RedaCoil Cross Section

5.5 Spoolable gas lift valves Another artificial lift technique commonly used to produce wells that do not flow naturally is called gas lift. The simplest example of the gas lift technique involves continuously pumping gas down the tubing annulus. The gas enters the tubing string through a gas lift valve (GLV) and lightens the hydrostatic pressure of the fluid column. This helps with well flow. These GLVs are usually run by the rig as part of the original completion. However, when production declines, adding GLVs with CT instead of replacing the completion with a rig is an option. Schlumberger has developed Spoolable gas lift valves specifically for CT applications (Fig. 5-7). These valves can be spooled as part of the CT string. Spoolable GLVs have internal connections so they can pass through pressure-control equipment and run into a well like a standard CT string.

Spoolable safety valve (internal control line) Existing safety valve Spoolable gas lift valve

Production packer

5.6 Through-tubing gravelpack Wells drilled in unconsolidated sands often require a screen to prevent sand production in the wellbore. Sand production from the formation can cause many problems during the life of a well: • sand buildup in the wellbore restricting or stopping production • downhole equipment erosion • casing or liner failure • surface production equipment erosion.

Production packer or seal assembly

Figure 5-7. Spoolable GLV

To prepare the Spoolable completion, the CT string is spooled from one reel to another. The string is cut at the position where the Spoolable valve is installed. The GLV is made up between the two ends of the CT string with internal connections.

A gravel pack (GP) is a wire mesh screen installed in the wellbore across from the producing formation. In many cases, gravel is pumped into the area between the screen and the formation. The GP keeps the sand in place while allowing the oil to flow. Figure 5-8 shows a cross-section of a prepacked screen. This type of screen is run into the well with a layer of consolidated resin‑coated gravel already placed between the screen and the outer shroud.

Spoolable completion strings are specifically designed for a well and therefore can take months to manufacture before the operation. Once completed, the Spoolable completion string is very quick to install. The string is hung at the wellhead with a surface hanger. Spoolable strings can be hung at the bottom of the existing completion as a tailpipe extension to place GLVs closer to the perforations.

Figure 5-8. Prepacked GP Screen

A GP completion is generally put in place by the rig after drilling the well. However, in some cases, such as if sanding begins later in the life

JET 16 - Introduction to Coiled Tubing  |  65

of a non-GP well, CT can be used to install a through-tubing GP completion. Through-tubing refers to screens installed through the existing production tubing. A through-tubing GP installation can increase oil and gas production and eliminate sand production (and its related problems) while maintaining the original completion. The most common method used for throughtubing GPs is the washdown method. The washdown technique consists of two phases. 1. First, the gravel is spotted in place (see Fig. 5-9). The CT string is run into the GP depth and the gravel is pumped into the well. The CT string is retrieved to surface. Figure 5-9 shows the gravel spotted in place. The CT string is run into the GP depth and the gravel is pumped into the well. The CT string is retrieved to surface.

2. The second phase is the installation of the GP screen assembly, which is made up to the CT string. The GP screen assembly consists of the following (Fig. 5-10):

▪ A hydraulic-set double-grip packer

is used to hang the assembly and prevents movement in either direction. This packer is fully retrievable using CT or jointed pipe.

▪ Blank pipe is used to cover the area

from the packer to the top of the perforations. There is no production from this area, so there is no need to use extra expensive screens.

▪ The wire mesh screen acts as a filter, allowing the oil flow while holding the sand in place.

▪ The wash pipe allows circulation

through the entire length of screen to the end of assembly. This is retrieved when the CT string is retrieved to surface.

▪ The nozzle provides jetting action

to help fluidize the gravel to put the screens in place.

Figure 5-9. Gravel is Spotted in Place

66  |  CT Completions

CT connector double flapper check valves Disconnect mechanism

Hydraulic-set double-grip packer

Blank pipe

Screen with washpipe inside

Figure 5-10. BHA to Run GP Screen Assembly

When approaching the top of the gravel in the well GP, pumping begins. The pump rate is sufficient to fluidize the gravel, but insufficient to circulate the material into the tubing. While pumping, the CT is slowly lowered into the gravel until the final setting depth for the screen is reached (Fig. 5-11).

Figure 5-11. Washing the Screen into Place

A ball is then pumped through the CT string to set the packer hydraulically and release the sand screen. The CT running string can now be pulled back to surface with the internal wash pipe (Fig. 5‑12).

JET 16 - Introduction to Coiled Tubing  |  67

Note:

Washpipe

Figure 5-12. Retrieving the Upper BHA and Washpipe

The through-tubing GP is now in place and the well begins sand-free production (Fig. 5-13).

Sand-free production

Figure 5-13. Sand-Free Production

68  |  CT Completions

Refer to Sandface Completions - Rigless Completion and Through Tubing Gravel Pack, InTouch Content ID# 3316403 for more information.

6.0  Glossary Artificial lift This term describes completion systems which provide artificial assistance to produce oil or gas from wells which would not produce economically if left to flow naturally. Examples: gas lift, ESP, rod pumps. Bullheading Pumping a fluid from surface through the existing completion without using CT or drillpipe. Completion The tubing and casing strings in a wellbore through which the oil or gas is produced, including associated downhole valves, screens, nipples, and so on. Electric submersible pump (ESP) ESPs are electric pumps installed at the bottom of the production tubing to pump oil to surface in wells which would produce little or no oil if allowed to flow naturally. Gas lift valve Valves placed in a completion to allow continuous, controlled gas injection to assist in bringing fluid to surface. Gravel pack This type of completion consists of a mesh screen surrounded by gravel in the reservoir. This type of completion is used to prevent unconsolidated reservoirs from producing sand into the wellbore. POOH (pull out of hole) Signifies that the CT string should be retrieved to surface or pulled above present position.

Pressure Control Equipment Equipment used to control wellbore pressure. In CT operations, this refers to the stripper, BOPs, lubricators, risers, and wellhead connections. RIH (Run in Hole) RIH signifies that the CT string should be run into the well or to a deeper position than the current position. Slickline A widely-used intervention technique using a steel cable to run and retrieve tools in a wellbore. It is very fast, relatively cheap, and uses a small crew. It can work up to well inclinations of approximately 65o. Snubbing unit An intervention technique which allows jointed pipe to be run into live wells. Generally used for heavy duty workover and recompletion. Completions can be pulled with a snubbing unit. Spoolable The Schlumberger Gas Lift valve range which can be spooled as part of a CT string. This system is used for through-tubing gas lift valve systems. Through-tubing Through-tubing describe operations carried out without pulling the existing completion. These operations are done through the tubing. TOC top of cement Wireline Electronic tools run on electric cable for reservoir and well evaluation.

JET 16 - Introduction to Coiled Tubing  |  02

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70  |  Glossary

7.0  Check Your Understanding 1.

CT was developed to perform remedial work on dead wells.

6.

a. true

2.

Which two of the following fluids are most suitable for cleanouts in wells that cannot hold a column of fluid?

b. false

A. brine

Schlumberger is the world’s largest supplier of CT services.

C. xanthan gel

B. nitrified fluid D. foamed fluid

a. true b. false 3.

7.

What are the three major groups of CT applications?

A. large completion size B. large CT size

A. CT completions

C. reservoir pressure sufficient to support column of fluid

B. CT fishing C. fluid conveyance

D. reservoir temperature > 163 degC [325 degF]

D. tool conveyance 4.

In a nitrogen kickoff, nitrogen gas is pumped through the CT string to _______ the hydrostatic pressure of the column of fluid in the wellbore.

E. vertical well 8.

a. increase

What three problems are caused by fill or debris in the wellbore? A. reduced production of oil or gas B. wireline and slickline access prevented C. scale buildup D. downhole sleeves and valves prevented from functioning

Which characteristic of a gelled fluid gives it better solids-carrying capacity than water? A. viscosity

b. decrease 5.

Which two of the following conditions make a fill cleanout more technically difficult?

B. density 9.

Which two of the following are NOT TRUE of cementing through CT? A. Operation is done through-tubing; no need to pull the completion. B. Operation can be done in a live well. C. Pumping cement slurry through CT increases slurry contamination. D. Higher treatment volumes are required. E. Accurate placement can be achieved.

JET 16 - Introduction to Coiled Tubing Operations  |  71

10. The cement design is the same for pumping through CT or drillpipe. A. true B. false 11. Which two of the following are reasons for setting cement plugs in wells? A. as a base to mill a window in well tubulars B. to seal off a casing leak C. to seal off an entire wellbore at the end of its useful life D. to seal off perforations producing water 12. Which one of the following is NOT TRUE about matrix acidizing through CT? A. Pumping the acid through CT protects the production tubing. B. It ensures accurate placement of the treatment. C. It reduces contamination of the fluid. D. It increases the amount of acid required. 13. Which one of the following is an advantage of pumping a hydraulic fracturing treatment through CT? A. multiple fractures possible in one run B. larger treatments can be pumped C. pumping at higher rates possible

14. In CT logging or perforating, what function does the pressure bulkhead have? A. enables a pressure-sealed electrical connection with the uphole end of the cable B. enables an electrical connection between the cable in the rotating reel core and the surface monitoring and recording equipment C. establishes an electrical connection between the downhole end of the cable and the logging tool 15. In CT logging or perforating, what is the function of the collector? A. enables a pressure-sealed electrical connection with the uphole end of the cable B. enables an electrical connection between the cable in the rotating reel core and the surface monitoring and recording equipment C. establishes an electrical connection between the downhole end of the cable and the logging tool 16. Which one of the following is NOT a type of electrical cable used in wired CT applications? A. monocable B. coaxial C. triplex D. heptacable 17. Which two electrical properties of the electrical cable must be checked before any logging operation? A. insulation B. resistance C. continuity D. voltage

72  |  Check Your Understanding

18. An overshot is used to fish what type of fishing neck? A. internal fishing neck profile B. external fishing neck profile 19. What are the two methods of activating the guns in CT perforation? A. hydraulic B. pneumatic C. electrical A. chemical 20. Which two of the following are the advantages of underbalanced perforation? A. helps to clean up debris in the perforation tunnels B. increases the length of the perforations C. less expensive D. avoids getting potentially damaging wellbore fluid into the reservoir 21. Which three of the following are advantages of pumping acid through the Jet Blaster over bullheading acid? A. Less chemical is needed to get the same effect.

23. Which three of the following are advantages of CT completions over completions run with conventional workover rigs? A. less expensive B. quicker C. well production increased D. live well operations possible 24. Which two of the following completion types is artificial lift? A. velocity string B. electric submersible pumps C. CT patch D. gas lift valves 25. What is the function of a gravel pack completion? A. increase fluid velocity for more consistent production B. increase oil production C. prevent sand production from the formation 26. Name six advantages of using CT over conventional workover rigs.

B. The Blaster tool can accurately place the acid at the point it is required.

1. _____________________________

C. The jetting effect of the Blaster improves the efficiency of the acid.

3. _____________________________

D. Quicker treatment is possible. 22. What is the name given to the Blaster configuration that includes a small mud motor and mill to drill a pilot hole?

2. _____________________________ 4. _____________________________ 5. _____________________________ 6. _____________________________

A. Screen Blaster B. Bead Blaster C. Bridge Blaster D. Jet Blaster JET 16 - Introduction to Coiled Tubing Operations  |  73

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74  |  Check Your Understanding