Coiled Tubing

Module 4

     

Coiled Tubing Operations in Drilling and Workover

Trainer: Assoc. Prof. Andrei Dumitrescu, Ph.D.

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Coiled Tubing Operations in Drilling & Workover

Table of Contents 1.

Introduction to Coiled Tubing Technology.......................................................................... 3 1.1 What is Coiled Tubing ?................................................................................................... 3 1.1.1 Coil tubing benefits..................................................................................................... 3 1.2 Coiled Tubing History and Industry Status .................................................................... 4 1.2.1 Coiled tubing origins and early equipment ........................................................... 4 1.2.2 Evolution of coiled tubing equipment .................................................................... 5 1.2.3 Coiled tubing industry present status ..................................................................... 5 1.3 Brief Overview of Coiled Tubing Field Applications.................................................... 6 1.3.1 Circulation and pumping applications................................................................... 7 1.3.2 Workover mechanical applications ........................................................................ 8 1.3.3 Drilling applications..................................................................................................... 8 1.3.4 Production applications ............................................................................................ 8 1.3.5 Pipeline applications .................................................................................................. 9

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Coiled Tubing Equipment .....................................................................................................10 2.1 Principal Components of Coiled Tubing Equipment................................................10 2.2 Coil Tubing Unit ...............................................................................................................11 2.3 Injector Head and Guide Arch ....................................................................................12 2.3.1 Weight sensors and depth measurement ............................................................14 2.4 Tubing Reel and Other CT Unit Equipments...............................................................15 2.5 Well Control Equipment ................................................................................................16 2.5.1 Blowout Preventer (BOP) .........................................................................................17 2.5.2 Stripper and wellhead connections ......................................................................20 2.6 Coiled Tubing Subsurface Equipment ........................................................................21

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Coiled Tubing Materials, Dimensions and Life Tracking ..................................................22 3.1 Materials for Coiled Tubing ...........................................................................................22 3.1.1 Alternatives to carbon steel coiled tubing...........................................................22 3.2 Coiled Tubing Dimensions. CT Manufacturing and Repair .....................................24 3.2.1 Coiled tubing manufacturing .................................................................................24 3.2.2 Coiled tubing repair and splicing ..........................................................................25 3.3 Tracking Coil Tubing Fatigue and Service Life...........................................................25

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Coiled Tubing Mechanical Limits. Buckling .......................................................................28 4.1 Coiled Tubing Mechanical Performance ..................................................................28 4.1.1 Effects of cyclic loading ..........................................................................................29 4.1.2 Permanent elongation of coiled tubing ...............................................................30 4.1.3 Mechanism for coiled tubing length change......................................................32 4.2 Coiled Tubing Design.....................................................................................................33 4.3 Buckling of Coiled Tubing Strings .................................................................................34 4.3.1 Sinusoidal buckling of coiled tubing strings..........................................................34 4.3.2 Helical buckling of coiled tubing strings ...............................................................35 4.3.3 Effects of wellbore curvature and of friction .......................................................37 4.3.4 Post-buckling lock-up ...............................................................................................38 1

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4.4 5.

Coiled Tubing Operations in Drilling & Workover Coiled Tubing Limits. Burst and Collapse...................................................................39

Current Applications of Coiled Tubing Technology in Drilling and Workover .............40 Coiled Tubing Drilling Applications..............................................................................40 5.1 5.1.1 Directional and non-directional wells ...................................................................42 5.1.2 Wellbore hydraulics and wellbore fluids ...............................................................42 5.1.3 Overbalanced and underbalanced coiled tubing drilling...............................43 5.2 Coiled Tubing Workover Applications ........................................................................43 5.2.1 Removing sand or fill from a wellbore...................................................................44 5.2.2 Fracturing / acidizing a formation .........................................................................45 5.2.3 Unloading a well with nitrogen...............................................................................45 5.3 Limitations of Coiled Tubing Technology ...................................................................45

References......................................................................................................................................48 Web sites..................................................................................................................................48

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Coiled Tubing Operations in Drilling & Workover

1. Introduction to Coiled Tubing Technology The scope of this module is to provide a detailed overview of coiled tubing technology (including equipment, materials and dimensions, mechanical performance) and its applications in workover, completion and drilling operations. The first chapter defines coiled tubing and briefly presents its history, present industry status and an overview of all its applications. 1.1

What is Coiled Tubing ?

Coiled Tubing is simple conceptually: a continuous steel tubing wound on a spool for repeated deployment into and out of oil wells. It can be defined as any continuously-milled tubular product manufactured in lengths that require spooling onto a large take-up reel, during the primary manufacturing process. The tube is nominally straightened prior to being inserted into the wellbore and is recoiled for spooling back onto the reel. Tubing diameter normally ranges from 0.75 in. to 4 in. (19.5 to 101.6 mm), and single reel tubing lengths in excess of 30,000 ft. (about 9150 m) have been commercially manufactured. Coiled tubing, if used correctly, can perform almost any operation concerning oil and gas wells construction and servicing – intervention works, open hole drilling and milling operations – or it can be used as production tubing in depleted gas wells. A coiled tubing operation is normally performed through the drilling derrick on the platform, which is used to support the surface equipment, although on platforms with no drilling facilities a self supporting tower can be used instead. For coiled tubing operations on sub-sea wells a semi-submersible vessel has to be utilized to support all the surface equipment and personnel. Onshore, they can be run using smaller service rigs, and for light operations a mobile self-contained coiled tubing rig can be used. 1.1.1 Coiled tubing benefits: While the initial development of coiled tubing was spurred by the desire to work on live wellbores, speed and economy have emerged as key advantages for application of coiled tubing. In addition, the relatively small footprint and short rig-up time make CT even more attractive for drilling and workover applications. Some of the key benefits associated with the use of coiled tubing technology are the followings: ¾ Safe and efficient live well intervention; ¾ Capability for rapid mobilization, rig-up, and well site preparation; ¾ Ability to circulate while RIH/POOH*; ¾ Reduced trip time, resulting in less production downtime; * RIH stands for run in hole, which refers to running “something” (CT, drilling assembly, wireline logging tools, casing, etc.) into the wellbore. POOH stands for pulling out open hole, which refers to pulling out whatever assembly is in the hole leaving the well open (i.e. no casing). In cased hole operations the term used is POH – pulling out (of) hole.

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¾ Lower environmental impact and risk; ¾ Reduced crew/personnel requirements; ¾ Cost may be significantly reduced. The potential advantages associated with coiled tubing are typically driven by the fact that a workover rig (and associated cost) is not required, the rapid CT trip speed in and out of the well, and that CT operations are designed to be performed with pressure on the well. Eliminating the requirement to kill the well can be a significant factor in the decision to utilize coiled tubing for a particular field operation, as it reduces the risk of formation damage. Coiled tubing is often used to carry out operations similar to wireline. The main benefits over wireline are the ability to pump chemicals through the coil and the ability to push it into the hole rather than relying on gravity. However, for offshore operations, the footprint for a coiled tubing operation is generally larger than a wireline spread (wireline operations can be carried out from a smaller and cheaper intervention vessel), which can limit the number of installations where coiled tubing can be performed and make the operation more costly. Coiled tubing can also be fitted with internal electrical conductors or hydraulic conduits, while modern CT strings provide sufficient rigidity and strength to be used in deviated or horizontal wellbores. This enables successful execution of downhole operations that would be impossible to perform with conventional wireline approaches, or would be cost prohibitive if performed by jointed-pipe. 1.2

Coiled Tubing History and Industry Status

The development of coiled tubing as a well service tool as know today dates back to the early 1960's, and it has become a key component of many well service and workover applications. While well service/workover applications still account for more than 75% of coiled tubing use, technical advancements have increased the utilization of coiled tubing in both drilling and completion applications. The ability to perform remedial work on a live well was the key driving force associated with the development of coiled tubing. To accomplish this feature, three technical challenges had to be overcome: ¾ a continuous conduit capable of being inserted into the wellbore (CT string); ¾ a means of running and retrieving the coiled tubing string into or out of the wellbore while under pressure (injector head); ¾ a device capable of providing a dynamic seal around the tubing string (stripper or pack-off device). In the followings, the history of these developments is summarised, concluding with a brief overview of the present status of the CT industry. 1.2.1. Coiled tubing origins and early equipment: Prior to the Allied invasion in 1944, British engineers developed and produced very long, continuous pipelines for transporting fuel from England to the European Continent to supply the Allied armies. The project was named operation "PLUTO" (Pipe Lines Under The Ocean), and involved the fabrication and laying of several pipelines across the English Channel. The successful fabrication and spooling of continuous 4

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flexible pipeline provided the foundation for additional technical developments that eventually led to the tubing strings used today by the coiled tubing industry. In 1962, the California Oil Company and Bowen Tools developed the first fully functional coiled tubing unit, for the purpose of washing out sand bridges in wells. The first injector heads operated on the principle of two vertical, contra-rotating chains, a design still used in the majority of coiled tubing units today. The stripper was a simple, annular-type sealing device that could be hydraulically activated to seal around the tubing at relatively low wellhead pressures. The tubing string used for the initial trials was fabricated by butt-welding 50 ft. (15.24 m) sections of 13/8 in. (34.925 mm) OD pipe into a 15,000 ft. (4572 m) string and spooling it onto a reel with a 9 ft. (2.75 m) diameter core. 1.2.2. Evolution of coiled tubing equipment: Throughout the late 1960's and into the 1970's, both Bowen Tools and Brown Oil Tools continued to improve their designs to accommodate coiled tubing up to 1 in. (25.4 mm) OD. By the mid-1970's, more than 200 of the original-design CT units were in service. By the late 1970's, several new equipment manufacturing companies (Uni-Flex Inc., Otis Engineering, and Hydra Rig Inc.) also started influencing improved injector head design. Coiled tubing strings were also undergoing significant improvements during this period. Through the late 1960's, CT services were dominated by tubing sizes of 1 in. (25.4 mm) and less, and relatively short string lengths. Tubing diameter and length were limited by the tubing mechanical properties and currently available manufacturing processes. Early coiled tubing operations suffered many failures due to the inconsistent quality of the tubing and the numerous butt welds required to produce a suitable string length. However, by the late 1960's, tubing strings were being manufactured in much longer lengths with fewer butt welds per string. During this time, steel properties also improved. These changes and the associated improvement in CT string reliability contributed significantly to the continued growth of the coiled tubing industry. Today it is common for coiled tubing strings to be constructed from continuously milled tubing that can be manufactured with no butt welds. In addition, CT diameters have continued to grow to keep pace with the strength requirements associated with new market applications. During the 1980’s, coiled tubing materials and strings improved significantly, and the maximum practical CT size increased to 1.75 in. (44.45 mm) and then further to 3.50 in. (88.9 mm) in the 1990’s. It is clear the coiled tubing industry has continued to make technical advancements that have opened new market applications for the technology. This progress has served to make coiled tubing an even more appealing solution for its early market applications. 1.2.3. Coiled tubing industry present status: The coiled tubing industry continues to be one of the fastest growing segments of the oilfield services sector, with a rapid rate of about 20% per year in the last 15 years of the 20th century. Coiled tubing growth has been driven by attractive economics, continual advances in technology and pipe manufacturing process, and utilization of 5

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coiled tubing to perform an ever-growing list of field operations (see Table 1.1). Coiled tubing today is a global, multi billion dollar industry in the mainstream of energy extraction technology with estimated revenue of about USD 1 billion per year (before the onset of the global economical crisis last year). In January 2009, 1,704 CT units were estimated to be available on a worldwide basis (counted by Les Tomlin, Trican Well Service Ltd.). The total number of working coiled tubing units is up sharply from the roughly 850 units reported in February 2001. Canada and the U.S. are estimated to contribute with about half of these units (419 and 456 respectively) while in Europe there are only about 152 active units (including Africa, but excluding Russia and neighbouring countries where 196 units operate). CT first established its niche in the marketplace as a cost-effective well cleanout tool. In recent years, these conventional wellbore cleanouts and acid stimulation jobs accounted for more than three quarters of total coiled tubing revenue. However, CT use has continued to expand as it is adopted for use in additional field operations. Recently, coiled tubing fracturing and drilling applications have emerged as two of the fastest growth areas. Revenue from these two CT applications has grown from almost zero 15 years ago, to approximately 15% in more recent times. The CT market is dominated by three large service companies, who control approximately 60% of the coiled tubing total marketplace. The market is also serviced by numerous smaller CT service providers. On a regional basis, there are typically more than 30 providers of coiled tubing in the International marketplace. Canada is serviced by more than 35 CT providers, and the U.S. by more than 25 companies. The development emphasis in the CT industry today is to “expand the envelope”, i.e. to perform CT services on deeper, longer reach, more tortuous wells with higher pressures, more corrosive and erosive fluids using larger pipe sizes, longer lubricators, moving platforms, etc. Also the geographic envelop is being expanded. 1.3

Brief Overview of Coiled Tubing Field Applications

Early applications were designed around the fluid circulating/placement capabilities of the coiled tubing string, while most recent applications can rely on several unique features of the CT string and equipment. The use of coiled tubing has continued to grow beyond the typical well cleanout and acid stimulation application. This growth can be attributed to a multitude of factors, including advances in CT technology and materials as well as the increased emphasis on wellbores containing a horizontal and/or highly-deviated section. The coiled tubing application list to date (shown in Table 1.1 below), as provided by ICoTA (International Coiled Tubing Association), illustrates additional operations where the use of coiled tubing is growing and could be of benefit in future field works. Current CT applications are briefly described below, while workover and drilling applications are discussed in chapter 5. Most applications make use of one or more of the following features: ¾ Live well operations – pressure control equipment coiled tubing can be safely applied under live well conditions.

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Coiled Tubing Operations in Drilling & Workover ¾ High pressure – coiled tubing string provides a high pressure conduit for fluid circulation into, or out of the wellbore. In addition, hydraulically operated tools may be powered by fluid pumped through the string. ¾ Continuous circulation – fluids may be pumped continuously while the coiled tubing string is run and retrieved. ¾ Rigidity and strength of CT string – they enable tools and devices (and the string itself) to be pushed/pulled through highly deviated and horizontal wellbore sections. ¾ Installed electrical conductors and hydraulic conduits – they may be installed in the CT string and terminated at the CT reel. This enables additional downhole communication/control and power functions to be established between the BHA (bottom hole assembly) and surface facilities. Table 1.1. Coiled Tubing Field Applications Traditional Applications Growth Applications Well Unloading CT Drilling Cleanouts Fracturing Acidizing/Stimulation Subsea Applications Velocity Strings Deeper Wells Fishing Pipelines/Flowlines Tool Conveyance Well Logging (real-time & memory) Setting/Retrieving Plugs Source: International Coiled Tubing Association, www.icota.com.

1.3.1 Circulation and pumping applications: The most popular use for coiled tubing is circulation or well unloading (see § 5.2.3). A hydrostatic head (a column of fluid in the wellbore) may be inhibiting the flow of formation fluids due to its weight (the well is “killed”). The safest (though not the cheapest) solution is to circulate out the fluid, using a gas, frequently nitrogen (operation also called “nitrogen kick”). By running coiled tubing into the bottom of the hole and pumping in the gas, the fluid can be forced out to production. Circulating can also be used to clean out light debris, which may have accumulated in the hole. Coiled tubing umbilicals can convey hydraulic submersible pumps and jet pumps into wells. These pumps allow for inexpensive and non invasive well cleanouts on low pressure gas wells. These umbilicals can also be run into deviated wells and horizontal laterals. Pumping through coiled tubing can also be used for dispersing fluids to a specific location in the well such as for cementing perforations or performing chemical washes of downhole components such as sandscreens. In the former case, coiled tubing is particularly advantageous compared to simply pumping the cement from surface as allowing it to flow through the entire completion could potentially damage important components, such as the downhole safety valve. Coiled tubing umbilical technologies enable the deployment of complex pumps which require multiple fluid strings on coiled tubing. In many cases, the use of coiled tubing to deploy a complex 7

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pump can greatly reduce the cost of deployment by eliminating the number of units on site during the deployment. Coil tubing can also be used to fracture the well, a process where fluid is pressurized to thousands of psi (tens of MPa) on a specific point in a well to literally break the rock apart and allow the flow of product. 1.3.2 Workover mechanical applications: Two of the tasks from this field of applications, logging and perforating, are by default the realm of wireline. Because coiled tubing is rigid, it can be pushed into the well from the surface. This is an advantage over wireline, which depends on the weight of the toolstring to be lowered into the well. For highly deviated and horizontal wells, gravity may be insufficient. Roller stem and tractors can often overcome this disadvantage at greatly reduced cost, particularly on small platforms and subsea wells where coiled tubing would require mobilising an expensive mobile drilling rig. The use of coiled tubing for these tasks is usually confined to occasions where it is already on site for another purpose, for example a logging run following a chemical wash. Some of the most frequent workover applications are discussed in section 5.2. 1.3.3 Drilling applications: A relatively modern drilling technique involves using coiled tubing instead of conventional drill pipe. This has the advantage of requiring less effort to trip in and out of the well (the coil can simply be run in and pulled out while the drill string must be assembled and dismantled joint by joint while tripping in and out). Additionally, the coiled tubing is stripped into and out of hole, providing a hermetic seal around the coil and, if desired, allowing the well to flow during drilling operations. Instead of rotating the drill bit by using a rotary table or top drive at the surface, it is turned by a downhole motor, powered by the motion of drilling fluid pumped from surface. Recently, Reel Revolution Limited has developed the world's first API certified CT Drilling Unit provided with a system able to rotate coiled tubing from surface at up to 20 RPM (rotations per minute) using coiled tubing sizes up to 3.5½ in. (88.9 mm) OD. On its website, this company claims to have a patent application filed and is currently building the first unit with a view to it being operational during the 3rd quarter of 2009. CT drilling applications are discussed in detail in section 5.1, while its limitations, including the system mentioned above, are shown in section 5.3. 1.3.4 Production applications: Coiled tubing is often used as a production string in shallow gas wells that produce some water. The narrow internal diameter results in a much higher velocity than would occur inside conventional tubing or casing. This higher velocity assists in lifting liquids to surface, liquids which might otherwise accumulate in the wellbore and eventually "kill" the well. The coiled tubing may be run inside the casing instead or inside conventional tubing. When coiled tubing is run inside of conventional tubing it is often referred to as a "velocity string" and the space between the outside of the coiled tubing and the inside of the conventional tubing is referred to as "micro annulus". Velocity strings are at present a common practice, especially in depleted gas wells. They are the final resting place for many used small diameter (OD < 2 in. / 50.8 8

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mm) CT strings. The objective of this permanent installation is to decrease the available production surface area within the wellbore such that the produced gas has sufficient energy to carry any produced liquids to surface. However, for these depleted wells, the choice of coiled tubing size and installation hardware may be heavily dependent on the price/availability of used CT strings. Coiled tubing umbilicals can convey hydraulic submersible pumps, electric submersible pumps and jet pumps into wells for both permanent deliquification schemes and service applications. 1.3.5 Pipeline applications: Coiled tubing can also be used as an effective tool for numerous pipeline applications, including: ¾ Transportation of inspection tools; ¾ Removing organic deposits and hydrate plugs; ¾ Removing sand or fill; ¾ Placing a patch or liner to repair minor leaks; ¾ Setting temporary plugs. Land-based coiled tubing operations in pipelines are similar to CT operations in horizontal wellbores with a few notable exceptions regarding the injector head (see § 2.3) which has to: supply all the force required to RIH with the coiled tubing; be oriented horizontally at the entrance to the pipeline (thus it requires a special mounting frame); snub the coiled tubing into the pipeline during the entire RIH operation (thus the weight measuring device must be configured for accurate measurement of snubbing forces). Coiled tubing operations in pipelines from an offshore platform are similar to operations in extended reach wellbores that kickoff at a shallow depth. The primary difference is that the path of the coiled tubing between the injector and the conduit on the sea floor may include several short radius bends which impart a high drag force, and increase the snubbing force requirement on the CT injector. There are also multiple permanent coiled tubing installations for pipeline applications including flowlines and control lines. The use of coiled tubing as a flowline between offshore structures normally results in installation costs much lower than for conventional laybarge installations of welded line pipe and in lower frictional pressure loss than equivalent size jointed pipe. Individual sections of flowline can be connected mechanically (use of slip-type connectors) or by welding, with the latter being more common. Coiled tubing is often used as the hydraulic control line connection between production facilities and subsea equipment. Multiple lines are normally bundled into a single line (umbilical) to reduce installation costs and to make the system more robust.

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2. Coiled Tubing Equipment The present chapter of this module describes the principal components of the coiled tubing equipment (for both surface and subsurface equipment) and briefly explains their use for selected coiled tubing operations. 2.1

Principal Components of Coiled Tubing Equipment

Modern coiled tubing equipment is at present commonly used to perform a variety of applications (see § 1.3) on well sites or locations of widely varying conditions. As a consequence, no standard equipment configuration applies to all conditions and applications. However, figure 2.1 below shows the principal components of coiled tubing equipment used for most operations.

Fig. 2.1. Principal Components of Coiled Tubing Equipment 10

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In addition, a crane is used to rig up and down the injector head and BOP for most coiled tubing operations (see Figure 2.3). The following sections describe the coiled tubing surface equipment (normally hydraulically powered) commonly used for most CT operations as shown in figure 2.1. Figure 2.2 indicates a totally different coiled tubing system, developed and patented in the United States by P.J. Reilly for Phillips Petroleum Company, conceived for simultaneously translating and rotating coiled tubing in a wellbore. It has a horizontal tubing reel, mounted on a rig and was intended for CT drilling operations.

Fig. 2.2. Alternative Coiled Tubing Unit Design (including injector head detail) Source: United States Patent, Phillips Petroleum Company (Feb. 2003).

2.2

Coil Tubing Unit

The Coiled Tubing Unit is comprised of the complete set of equipment necessary to perform standard continuous-length tubing operations in the field. It is a self contained multi-use machine that can perform approximately any operation that a conventional service rig is capable of – with the exception of tripping jointed pipe. The standard CT unit consists of four basic components (illustrated in figure 2.3): ¾ Tubing Reel – for storage and transport of the coiled tubing; ¾ Injector Head – to provide the surface drive force to run and retrieve the CT; ¾ Control Cabin – from which the equipment operator monitors and controls the coiled tubing; ¾ Power Pack – which generates hydraulic and pneumatic power required to operate the coiled tubing unit. The coil tubing units are generally mounted on tandem drive Class 3 trucks, about 40 feet / 12 m long and they are driven by a large air compressor, usually good for 2500 psi (17.2 MPa) at 660 CFM (18.7 m3/min), mounted between the reel and the 11

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cabin. In lower pressure, natural gas wells, with no hydrocarbons, the compressor is actually used to blow air to bottom hole in these live natural gas wells, for the purpose of "cleaning out" mud and fluid from the wellbore and perforations. In higher pressure wells, or oil wells, nitrogen or carbon dioxide is the preferred and much safer method.

Fig. 2.3. Trailer Mounted Coiled Tubing Unit and Crane Coiled tubing workover units come in a wide range of configurations and sizes, depending on the intended application. They can be truck-mounted, as discussed above, trailer-mounted (as in Figure 2.3) or modular, consisting of individual components packaged in their own frame (ideal for severe space limitations). 2.3

Injector Head and Guide Arch

The main component of the coiled tubing surface equipment and the prime mover for a CT unit is the injector head. This component contains the mechanism to push and pull the coil tubing in and out of the hole. During most CT operations, an injector head has a curved guide beam on top (the guide arch, also called gooseneck) which supports and guides the coiled tubing in/out of the injector body. This structure has a number of rollers along its length to support the coiled tubing. The largest injector head, Hydra Rig 5200, can handle coiled tubing up to 7 in. (177.8 mm) OD and pull up to 200,000 lbs (about 90 tonnes). Many injectors can move with a speed of up to 200 ft./min (about 60 m/min). 12

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The injector provides the following functions: ¾ Apply dynamic axial force to the coiled tubing to control movement into or out of a well; ¾ Supply enough traction to avoid slipping on the coiled tubing; ¾ Apply static force to hold the coiled tubing when stopped; ¾ Platform for weight and depth measurement sensors. The guide arch, in its turn, provides the following functions: ¾ Support the coiled tubing above the injector head; ¾ Provide a controlled radius of bending for the coiled tubing into/from the top of the chains of the injector head. This function is extremely important to the fatigue life which increases as the radius of curvature of the arch increases; ¾ Withstand the reel back tension; ¾ Accommodate the fleet angle between the injector and the tubing reel due to spooling on/off the reel. Typical guide arch radii are 48 in. to 100 in. (1220 to 2540 mm). Current guide arch design generally can withstand the maximum reel back tension, while large radius arches used in the past were vulnerable to such tension, sometimes collapsing. Figure 2.4 shows the sketch of a typical CT injector head (in this figure: 1 represents the coiled tubing, 2 – injector head jacket, 3 – pressure cylinder, 4 – tension cylinder, 5 – load cell, 6 – CT guide, 7 – driven chain wheel, 8 – chain, 9 – tension rollers, 10 – driving chain wheel). Two continuous and opposing chains (pos. 8) are the primary feature of this type of injector. Short gripper blocks contoured to match the OD of the coiled tubing or shaped like a “V” cover each chain. Hydraulic cylinders (pos. 3 and 4) force the chains, hence the gripper blocks, together around the coiled tubing (pos. 1). Variable-speed hydraulic motors drive the gripper chains. As the chains move linearly in the direction of the coiled tubing axis, friction between the gripper blocks and the coiled tubing causes it to move at the same rate as the chains. The process resembles climbing a rope hand-over-hand. Friction is the only force supporting the coiled tubing in the injector head. The injector drive assembly pivots on the base frame and rests on two load cells, one on each side of the pivot. When using cylindrical contour grippers, a different gripper block is required for each coiled tubing size. However, the blocks spread the gripping force evenly over the entire surface of the coiled tubing. This minimizes the risk of scarring or mashing the CT. If V-shaped gripper blocks are used, they make contact with the coiled tubing at four locations around its circumference. The advantage of this block design over the first one is that one size block can grip a range of CT diameters providing more flexibility for the user. However, the contact pressure between the block and the CT has to be higher for a given gripping force. Heartland Rig International developed an injector head without chains, called “Big Wheel”. The main element is a large grooved wheel. The coiled tubing lies in the groove and small rollers on the fixed frame surrounding the wheel force the CT into the groove. The pressure applied to the coiled tubing by the guide rollers provides the gripping force as the CT moves around the circumference of the wheel.

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Coiled Tubing Operations in Drilling & Workover 2.3.1 Weight sensors and depth measurement:

The injector head is fitted with load cells acting as weight sensors, needed to measure the coiled tubing axial force. They can be either hydraulic (an elastomer bladder filled with hydraulic fluid or a piston within a cylinder) or electronic (strain gage sensor). A small-diameter hydraulic line connects the load cell to a pressure gage in the CT unit control cabin where the force on the load cell is displayed. Another method of measuring the CT axial forces uses instrumented load pins (strain gage type) to attach the injector head to support the frame. To the same purpose, a weight indicator calibration system (WICS) as shown in Figure 2.5 can also be used. It consists of a bi-directional electronic load cell attached to both the CT threaded connector and the bottom connection of the stripper. A small electronic box connected to the load cell with a shielded signal cable contains a digital display for reading the axial force applied to the load cell by the injector.

Fig. 2.5. WICS Components

Fig. 2.4. Injector Head

Some coiled tubing injectors incorporate a depth counter for measuring the length of coiled tubing travelling through them. A small wheel contacts the coiled tubing immediately below the chains or in another location on the unit. The counter connected to the wheel mechanically converts the revolutions of the wheel into a linear measurement. A similar depth measuring system can be mounted on the tubing reel

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while an auxiliary such system can mount over the coiled tubing between the guide arch and the level wind. 2.4

Tubing Reel and Other CT Unit Equipments

The coiled tubing reel is a storage device for the CT string. Its drive mechanism has only enough power to wrap/unwrap the coiled tubing on/off the drum. Most land CT units have a reel mounted to a truck chassis or trailer. Some units use a “cartridge” reel system of interchangeable reels. Most reels use a chain drive connecting the hydraulic motor mounted on the support frame to a large sprocket on the side of the drum. The reel drive motor also functions as a dynamic brake during slackoff to maintain tension on the coiled tubing between the drum and the guide arch. The reel brake locks the reel in position when the CT is static, but is not used for dynamic braking. The coiled tubing operator obtains the desired reel tension by controlling the hydraulic pressure to the motor. Figure 2.6 includes the drawing of a fully-loaded tubing reel. The level-wind serves to guide the wraps of coiled tubing onto the drum during pickup and to ensure smooth unwrapping during slackoff. Normally, the double diamond lead screw on the level-wind automatically paces the drum rotation. On the side of the reel, there are mounted the high-pressure swivel (connecting the CT to external piping), the electrical slip-ring assembly (connecting the electric line in the CT to external wiring) and the ball launcher manifold.

Fig. 2.6. Tubing Reel. The following equipments are also part of a coiled tubing unit: ¾ The hydraulic power unit supplies both relatively high-volume, low-pressure hydraulic fluid to dynamic equipment (injector, reel) and low-volume, high-

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Coiled Tubing Operations in Drilling & Workover pressure hydraulic fluid to static devices (stripper, BOP). An example of power unit is shown in the drawing from Figure 2.7.

Fig. 2.7. : Hydraulic Power Unit: 1 – hose connection; 2 – hydraulic motor; 3 – oil tank; 4 – Diesel engine. ¾ The control cabin contains the operator’s console with the analogue gauges, digital displays, electrical and hydraulic control necessary to operate the coiled tubing unit. ¾ The computer based data acquisition system (DAS) is now widely used to electronically record all information pertinent to operating a CT unit. Typical measurements include pump (circulating) pressure, wellhead pressure (WHP), Ct depth, CT axial speed, CT weight (load cells), stripper hydraulic pressure and hydraulic power supply pressure. 2.5

Well Control Equipment

Proper well control equipment is another key component of coiled tubing operations, given that a majority of these operations are performed in the presence of surface wellhead pressure. The typical CT well control equipment consists of a BOP (blowout preventer), topped with a stripper (high pressure CT units have two strippers and additional BOP components). All components must be rated for the maximum wellhead pressure (WHP) and temperature possible for the given field operation. In addition, each component must be compatible with any corrosive fluids that might be produced from the well or introduced as part of the coiled tubing operation. Figure 2.8 below shows a complete stackup of well control equipment with TOT 3.06 in (77.724 mm) for coiled tubing operations at WHP up to 15,000 psi (about 103 MPa). 16

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Fig. 2.8. Example Well Control Stack for CT Operations 2.5.1 Blowout Preventer (BOP): The Blowout Preventer (BOP) is situated beneath the stripper, and can also be used to contain wellbore pressure. Its main function is to prevent well fluids from 17

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escaping into the atmosphere. A coiled tubing BOP is designed specifically for CT operations. It consists of several pairs of rams, with each ram designed to perform a specific function. The number and type of ram pairs in a BOP are determined by the BOP configuration: single, double, or quad. Older quad-BOP systems, which still are the standard coiled tubing BOP, have a different ram for each of these functions and they are commonly used in most operations. The four BOP rams, from top to bottom and their associated functions are: ¾ Blind ram – seals the wellbore when the coiled tubing is out of the BOP; ¾ Shear ram – used to cut the coiled tubing pipe; ¾ Slip ram – supports the coiled tubing weight hanging below it (some are bidirectional and prevent the CT from moving upward); ¾ Pipe ram – seals around the hanging coiled tubing. Newer (combi) dual-BOPs combine some of these functions together and therefore they need only two distinct rams (a shear-blind ram and a pipe-slip ram). Figure 2.9 show typical BOP configurations.

Fig. 2.9. Typical Coiled Tubing BOP Configurations Blind Ram Assembly: Blind rams are sealing rams. They isolate wellbore fluids and contain pressure when there is no coiled tubing in the BOP. Unlike pipe rams, they will not seal on any wireline, cable or tubing. Blind rams (just like slip and pipe rams0 18

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consist of identical ram bodies positioned opposite each other in a ram bore. Each ram assembly contains a ram body, front seal, rear seal and a retainer bar. The front seal closes on an open hole and the rear seal contains the well pressure from behind the ram body. Hydraulic pressure acts on a piston connected to a piston rod. The force moves the rams to the center of the trough bore. As the force is increased, the rubber deforms and forms a seal. Shear Ram Assembly: Shear rams have cutter blades to cut through coiled tubing, wireline and cable. Shera rams have right and left hand ram bodies. The ram assembly consists of ram bodies, shear blades and socket head cap screws which hold the blades. The blade are made of a material that is hardened after machining while the core of the blades remains relatively soft, giving the ductility required to prevent cracking while shearing the coiled tubing. Slip Ram Assembly: Slip rams grip the coiled tubing to prevent it from being pushed out of the well or from falling down the well. Each ram assembly contains a ram body, slip insert and a retainer pin. The slip insert slides into the ram and is hels in place with the retainer pin which does not take any loading. The slips should hold the yield load of the coiled tubing. The slip inserts have a special tooth design to minimize the stresses on the coiled tubing. Pipe Ram Assembly: Pipe rams (also called tubing rams) are sealing rams. They seal around the coiled tubing to isolate wellbore fluids and contain pressure. Each ram assembly contains a ram body, front seal, rear seal and a retainer bar. The front seal closes around the coiled tubing and the rear seal contains the well pressure from behind the ram body. Pipe rams function similarly to blind rams. Standard coiled tubing BOPs also contain two equalizing ports, one on each side of the sealing rams. It also has a side outlet between the slip and shear rams. This outlet can be used as a safety kill line. BOPs are available in a range of sizes, shown in Table 2.1 below together with the corresponding coiled tubing range and normally follow the API flange sizes. Table 2.1. BOP and Coiled Tubing Field Sizes BOP Size Coiled Tubing Range inches mm inches mm 2.56 and 3.06 65.0 and 77.7 0.75 through 2.0 19.05 through 50.8 4.06 103.12 1.0 through 2.875 25.4 through 73.1 5.12 ; 6.375 ; 7.06 130.0 ; 161.9 ; 179.3 1.25 through 3.5 31.75 through 88.9 BOP pressure ratings correspond with API 6A and 16A. Currently blowout preventers have been built for 5,000 psi (34,5 MPa), 10,000 psi (68.95 MPa) and 15,000 psi (103.4 MPa) working pressure. The BOP sits on top of the riser, which provides the pressurised tunnel down to the top of the Christmas tree. Between the Christmas tree and the riser is the final pressure barrier, the shear-seal single BOP (see Figure 2.8), which can cut and seal the pipe.

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Coiled Tubing Operations in Drilling & Workover 2.5.2 Stripper and wellhead connections:

The stripper (sometimes referred to as a packoff or stuffing box) provides the primary operational seal between pressurized wellbore fluids and the surface environment, thus isolating the well's pressure. It is physically located below the injector head and above the BOP. The stripper contains a rubber pack off elements providing a dynamic seal around the coiled tubing during tripping and a static seal around the CT when there is no movement. The early model inline stripper did not provide access to the sealing elements with the CT in place. The latest style of stripper devices are designed with a side door, that permits easy access and replacement of the sealing elements, with the coiled tubing in place. The sealing elements consist of thick-walled elastomer (having several layers) cylinders split length-wise. Elastomers used used for stripper elements must have low coefficient of friction and good chemical and abrasion resisitance. Usually, the WHP energizes the stripper seal by forcing a piston against one end of the elastomer cylinder. Figure 2.10 illustrates a stripper design that applies a radial force directly to the stripper element. In this radial stripper, hydraulic fluid forces opposing pistons together with the stripper elements between them. This squeezes the elastomer between the pistons and coiled tubing to create a pressure seal.

Fig. 2.10. CT Radial Stripper (Texas Oil Tools)

Fig. 2.11. Hydraconn (Texas Oil Tools)

Wellhead connections are used to rig up pressure control equipment. The rigging process can be quicker and safer if using as a pressure control tool a hydraulic quick latch which is normally the last connection made during the coiled tubing rig up. It is used to stab the injector onto the BOP stack and is a non-pressure containing device as it is mounted above the stripper packer. Hydraconns (see Figure 2.11) are designed to facilitate a secure connection between the BOP and stripper packer while providing an elevated level of personnel safety by minimising the need for operator assistance during rig-up of the pressure control stack. The hydraconn incorporates a tapered seal bore that facilitates stabbing the connection and has a safety latch to prevent an unintentional release while operating under well pressure. 20

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The hydraulic release connector (HRC), provided with two mating sections, is designed to facilitate the quick and safe connection of the BOP and/or lift frame to the wellhead or drill pipe. 2.6

Coiled Tubing Subsurface Equipment

The tool string at the bottom of the coiled tubing is often called the bottom hole assembly (BHA). It can range from something as simple as a jetting nozzle, for jobs involving pumping chemicals or cement through the CT, to a larger string of logging tools, depending on the operations. One of the most important subsurface equipments is the motor head assembly (MHA), comprising four equipment elements (a CT connection at the top, a check valve, a CT disconnect at the bottom, a circulation sub, and a burst disc which is optional) incorporated in the same tool to minimize its length. The MHA provides a mean of disconnected from the downhole tools while still maintaining the pressure integrity of the coiled tubing sting. This tool should always be run just below the end of the CT to minimize the risk of becoming stuck. The other main categories of such equipment are the followings: ¾ CT connectors allowing the attachment of the coiled tubing to the BHA. Such connectors can be: grub screw / dimple, external or internal slip type, roll-on, double ended etc. ¾ Check valves is a standard CT string component preventing the back flow of well fluids into the coiled tubing in the event of failure or damage to the string or surface equipment. There are several types of check valves. ¾ Coiled tubing disconnects (release tools) of several types. ¾ Coiled tubing circulation and control valves. ¾ Coiled tubing jars and accelerators. ¾ Coiled tubing straight bars and joints. ¾ Coiled tubing centralizers. ¾ CT toolheads and deployment bar systems. ¾ CT running – pulling and shifting tools. ¾ Coiled tubing end locator. ¾ Coiled tubing nipple locator. ¾ Wireless CT collar locator. ¾ Indexing tools. ¾ CT wash tools and wash nozzles. ¾ Coiled tubing fishing tools. ¾ Impact drills. ¾ Through-tubing packers and bridge plugs.

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3. Coiled Tubing Materials, Dimensions and Life Tracking The present chapter of this module presents the materials used for coiled tubing (with a special emphasis to the alternative to carbon steel such as CRA), contains a brief overview of the manufacturing process and typical dimensions and addresses the problem of tracking CT fatigue and service life. 3.1

Materials for Coiled Tubing

The most common material used at present for coiled tubing is low-alloy carbon steel thermo-mechanically controlled rolled ASTM A606 Type 4 modified and ASTM A607 modified. The mills can adjust the yield strength of these steels over the range of 55-90 Kpsi (380-620 N/mm2) with proper heat treatment. However, they attempt to keep the surface micro-hardness of the finished CT below 22 HRC to decrease its susceptibility to sulphide stress cracking (SSC). The advent of coiled tubing drilling in 1991 spurred numerous advances in the technology for manufacturing coiled tubing, including larger sizes, increased yield strength range and exotic materials. Today, common coiled tubing steels have yield strengths ranging from 55 Kpsi (380 N/mm2) to 120 Kpsi (about 830 N/mm2). At the end of 2003, two companies supplied all the steel coiled tubing used by the petroleum industry. Quality Tubing, Inc. (QTI) and Precision Tube Technology (PTT) each have manufacturing facilities in Houston, TX. Table 3.1 below summarises the mechanical characteristics of the most used QTI low-alloy carbon steels together with the CRA material discussed in the following section QT-16Cr (having different values, with respect to the other steels for both the density - 7.862 g/cm3 and modulus of elasticity - 28·106 psi / 0.193·106 MPa). Table 3.1. Mechanical Characteristics of QT Steels Minimum Yield Minimum Tensile Minimum Maximum Type of Strength Strength Elongation Hardness steel psi MPa psi MPa % Rockwell C QT-700 70,000 483 80,000 552 26 22 QT-800 80,000 552 90,000 621 26 22 QT-900 90,000 621 98,000 676 * 22 QT-1000 100,000 689 110,000 758 * 28 QT-16Cr 90,000 621 110,000 758 NA NA * Calculation formula as a function of cross section area and tensile strength Source: National Oilwell Varco, www.nov.com.

3.1.1. Alternatives to carbon steel coiled tubing: Conventional carbon steel coiled tubing is more than adequate to meet the needs of most field operations. However, some corrosive downhole environments 22

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dictate the use of improved coiled tubing materials. Therefore, CT manufacturing companies are working on corrosion resistant alloy (CRA) coiled tubing materials. Control lines are the largest market for small diameter CRA tubing. QT-16Cr is a relatively new CRA that was specifically developed by Quality Tubing, Inc. for long term direct exposure to wet CO2 environments (where it has a very small corrosion rate compared to other materials). QT-16Cr was commercially introduced in early 2003, and more than 30 tubing strings were in service a year later. Much of the early application was for permanent installations as a velocity string in environments containing wet CO2 and saline conditions. It has been installed to depths greater than 18,000 ft. (about 5500 m). The commercial appeal of QT-16Cr goes beyond its favorable corrosion resistance characteristics. The material has also exhibited much improved abrasion resistance (approximately 1/4th the material loss versus a well known 45 HRC low alloy steel) as well as demonstrating superior low cycle fatigue life when compared to its equivalent in carbon steel. This data indicates the grade may be an excellent candidate for future coiled tubing work string applications. HS-80-CRA is another CRA material being developed for use in downhole completion application in H2S and CO2 environments. This product is a lean duplex material that is laser welded. Early testing indicates it has very good corrosion characteristics in H2S and/or CO2 environments. Another alternative to steel for manufacturing coiled tubing is a composite made of fibers embedded in a resin matrix. The fibers, usually glass and carbon, are wound around an extruded thermoplastic tube (pressure barrier) and saturated with a resin, such as epoxy, in a continuous process. Heat or UV radiation is used to cure the resin as the tube moves along the assembly line. Composite coiled tubing can be manufactured with a wide range of performance characteristics by changing the mix of fibers, the orientation of their windings, and the resin matrix properties. The first commercial application for composite CT was three velocity strings deployed in The Netherlands in mid-1998. The largest market for composite coiled tubing is for flowline and pipeline installations. The advantages of composite CT compared to carbon steel include: ¾ high resistance to fatigue damage, at least 10 times greater than steel; ¾ impervious to corrosion; ¾ significantly lighter than steel CT with comparable internal diameter, resulting in fewer logistical problems; ¾ electrical conductors or optical fibers can be included in the wall. However, composite coiled tubing has several disadvantages compared to carbon steel CT, including: ¾ 3 to 5 five times the cost (at the end of 2000); ¾ maximum operating temperature of 120 oC; ¾ significantly lower stiffness, resulting in much lower critical buckling force. The CT mills have also produced small quantities of coiled tubing made of titanium or stainless steel for highly corrosive environments, but the high cost of these materials has severely limited their use. Titanium was thoroughly explored for use in this application, but it is difficult to weld and costs approximately 10 times as much as 23

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carbon steel. As a result, only a handful of titanium strings have been manufactured (at the close of 2000, only three strings of titanium CT have been produced, all for permanent installations). 3.2

Coiled Tubing Dimensions. CT Manufacturing and Repair

Coiled tubing products are commercially available with outside diameters (OD) from 1.0 in. (25.4 mm) to 4.5 in. (114.3 mm), although larger diameters up to 6.625 in. (168.3 mm) have been produced in short lengths for testing. The standard OD values are (in inches/mm): 1.0/25.4, 1.25/31.75, 1.5/38.1, 1.75/44.45, 2.0/50.8, 2.375/60.33, 2.875/73.03, 3.5/88.9, 4.5/114.3. The nominal CT wall thickness ranges between 0.075 in. (1.91 mm) and 0.250 in. (6.35 mm) depending on the OD value. For instance, 2.0 in. (50.8 mm) OD coiled tubing has the following nominal wall thickness values (in inches): 0.109, 0.125, 0.134, 0.156, 0.175, 0.188. 3.2.1. Coiled tubing manufacturing: The manufacture of coiled tubing involves multiple steps, and the following contains a brief overview of the key components involved in the manufacturing process. Virtually all coiled tubing in use today begins with large coils of low-alloy carbonsteel sheet as raw material. The coils can be up to 55 in. (1.397 m) wide and weigh over 24 tons. The length of sheet in each coil depends upon the sheet thickness and ranges from 3,500 ft. (about 1,050 m) for 0.087 in. (2.21 mm) gauge to 1,000 ft. (about 300 m) for 0.250 in. (6.35 mm) gauge. The first step in tube making is to slice flat strips from the roll of sheet steel, and this step is usually performed by a company specializing in this operation. The strip's thickness establishes the CT wall thickness and the strip's width determines the OD of the finished coiled tubing. The steel strips are then shipped to a coiled tubing mill for the next step in the manufacturing process. The mill utilizes bias welds to splice the flat strips together to form a single continuous strip of the desired CT string length. The mechanical properties of the bias strip welds almost match the parent strip in the as-welded condition, and the profile of the weld evenly distributes stresses over a greater length of the coiled tubing (prior to 1987, butt welds were used instead of bias welds thus generated CT fatigue failure in the welds as a butt weld has inferior mechanical properties to the parent tube particularly in the heat affected zone – HAZ). Joining strips of different thickness or using strips with a continually changing thickness yields a tapered string as “True Tapper TM” produced by QTI. The CT mill then utilizes a series of rollers to gradually form the flat strip into a round tube. The final set of rollers forces the two edges of the strip together inside a high frequency induction welding machine that fuses the edges with a continuous longitudinal seam. This welding process does not use any filler material, but leaves behind a small bead of steel (weld flash) on both sides of the strip. The mill removes the external bead with a scarfing tool to provide a smooth OD. The weld seam is then normalized using highly localized induction heating. Next, the weld seam is allowed to cool prior to water cooling. Full tube eddy current or weld seam ultrasonic inspection may also be performed, depending upon the mill setup. The tubing 24

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then passes through sizing rollers that reduce the tube OD slightly to maintain the specified manufacturing diameter tolerances. A full body stress relief treatment is then performed to impart the desired mechanical properties to the steel. Subsequent to the coiled tubing being wound on a shipping reel, the mill flushes any loose material from the finished CT string. 3.2.2. Coiled tubing repair and splicing: Finally, some considerations about repair of damaged CT are included. The only acceptable method of repairing mechanical or corrosion damage to a coiled tubing string is to physically remove the bad section of tubing and rejoin the ends with a temporary or permanent splice. A temporary splice consists of a mechanical connection that is formed with a tube-tube connector. This type of connection is typically not used for prolonged operations during a coiled tubing job, but rather as an emergency repair to allow the CT string to be pulled out of the hole. However, connector technology continues to evolve and there are certain situations where connectors are used, such as to connect the tool string to the end of the coiled tubing. There are three general types of connectors, including the grapple, setscrew/dimple, and roll-on connector. Connector selection is based on the particular operation to be performed, as each type incorporates unique features that make it bestsuited for a given application. Only butt welds are possible for field welding repair of coiled tubing strings, with TIG (Tungsten Inert Gas) welding being the preferred method for permanent repair of CT work strings. The low heat input and the slowdeposition rate of this technique make it ideal for use with coiled tubing. The CT industry has three generally accepted TIG welding techniques: ¾ Manually, with hand-held tools; ¾ Semi-automatically, with manual preparation with an automatic orbital welder; ¾ Fully-automatically, with a robotic orbital welder. All three methods can produce high quality welds. However, even the best repair weld has no more than 50% of the fatigue life of the virgin tubing. 3.3

Tracking Coil Tubing Fatigue and Service Life

Many parameters affect the coiled tubing service life duration, including reel and guide arch geometry, pumping pressure, CT diameter, wall thickness and material. To be certain that the coiled tubing does not reach the end of its life during a certain job, it is crucial that the CT life is calculated before designing any coiled tubing job. In order to determine the suitability of an existing coiled tubing string for a proposed operation, the user must determine if: ¾ The stresses in the wall of the tubing caused by pressure and axial forces will exceed the yield stress of the material (see § 4.4), and ¾ The accumulated fatigue in any segment of the string will exceed a predetermined safe limit during the course of the operation. 25

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As a consequence, a tracking system is required to monitor the CT fatigue and service life. In addition, coiled tubing geometry which has a direct, significant effect on both issues above must be monitored by means of CT inspection tools. In addition to the practical reason for determining whether CT can safely pass through the surface equipment and be gripped properly by the injector, real-time measurements of tubing geometry are crucial for avoiding disastrous failures. Multiple tools capable of measuring external CT geometry have been used in the CT industry. These tools measure the tubing OD on several radials at a given cross section to determine the ovality and diameter of the CT. More recently, several "fullbody" CT inspection tools, with the ability to detect tubing wall flaws as well as providing tubing wall thickness and geometry measurements, have been utilized. Real-time inspection systems are being used during offshore operations to assure total integrity of the coiled tubing. There are three basic types of coiled tubing inspections technologies currently available in the industry: ¾ Electromagnetic proximity sensor uses proximity sensors to measure the diameter and ovality of the coiled tubing. Two diametrically opposed such sensors each measure the distance from the probe to the CT surface. The distance between the probes being known, the CT diameter can be calculated. Multiple sets of probes measure multiple diameters around the tubing which are used to calculate the ovality. This technology cannot be used for non-magnetic materials such as CRA. ¾ Electromagnetic flux leakage uses magnets to induce a magnetic field into the pipe wall. Hall effect sensors around the pipe sense leakage of the magnetic flux from the wall. This flux leakage gives an indication of cracks and pits both inside and outside the pipe. It can also give an indication of how much steel is in a given portion of the pipe, from which an average wall thickness can be calculated. ¾ Ultrasonic technology is able to accurately measure wall thickness and to give indications of cracks, inclusions and pits and is commonly used in pipe manufacturing facilities. CTES has developed a field device based on this technology, measuring a localized wall thickness at 12 locations around the circumference of the tubing. Coiled tubing service providers utilize sophisticated CT fatigue modelling software and field data acquisition systems to track the operating load history of the coiled tubing string as it is utilized in the field. This operating history allows the coiled tubing string life to be monitored, and the string replaced prior to failure. The fatigue modelling software programs are able to depict the amount of coiled tubing life that has been spent during two downhole operations based on the load history data. Figure 3.1 contains a sample screen capture from such a program. Tracking coiled tubing service life is important especially for the drilling applications for which the amount of fatigue is greatly increased with respect to other applications due to the continuous drilling fluid pressure and large CT diameters used. Therefore, a research effort has been made to develop a coiled tubing life prediction

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model which determines when the coiled tubing will fail due to fatigue caused by the pressure and bending cycles. Figure 3.2 shows the relative CT life for various CT sizes as a result of a life prediction model which determines the life cycle the coiled tubing could make before fatigue failure occurs. One curve shows the CT life with 65% of the maximum allowable working pressure (Pmaw) inside it. The other curves refer to a pressure based on a constant flow rate at 8,000 ft. (about 2440 m) maximum depth.

Fig. 3.1. CT Fatigue Modeling Software Sample Screen Source: International Coiled Tubing Association, www.icota.com.

Fig. 3.2. CT Fatigue Life Limits (research results from [10]) 27

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4. Coiled Tubing Mechanical Limits. Buckling Coiled tubing exhibits surprising mechanical responses to routine operating conditions. Under pressures and axial loading considered harmless to conventional tubing, coiled tubing’s dimensions and mechanical properties change throughout its service life. Such mechanical performance of coiled tubing, fundamentally different from all other tubular products used in the petroleum industry, are a result of the fact that coiled tubing is plastically deformed with normal use. Ct begins its working life plastically deformed on a reel and is then repeatedly subjected to additional plastic deformation. This chapter firstly addresses coiled tubing mechanical performance focusing on the effects of cyclic loading and plastic deformations experienced by the CT. Then, important aspects regarding CT string design, buckling and collapse are treated. 4.1

Coiled Tubing Mechanical Performance

Users of jointed tubular products (drill pipe, casing and production tubing) carefully control or select a combination of product dimensions, properties and operating conditions to avoid yielding the material. However, this is not possible for coiled tubing operations. Plastic deformation in a metallic object is a permanent change in its geometry (strain) caused by loads exceeding the material’s strength (a deformation that remains after the load causing it is removed). For standard CT operations, the tube is plastically deformed as the tube is straightened coming off the reel at point 1 as shown below in Figure 4.1. It is then bent at point 2 as it moves onto the guide arch, and is straightened again at point 3 as it travels to the injector and enters the wellbore. The CT string is then plastically deformed at the same three points (events 4, 5 and 6 in Figure 4.1) during retrieval from the well.

Fig. 4.1. Location of Bends in Coiled Tubing Caused by Surface Equipment

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The bending strain, εB, caused by bending a segment of coiled tubing with the radius r = OD/2 around a curve with the radius R (guide arch or reel radius) can be calculated with the following equation: εB = r / R = OD/2R (4.1) Assuming R = 50 in. (1.27 m) and a coiled tubing OD of 1.25 in. (31.75 mm), the bending strain reaches 1.25%, while εB = 2% for OD = 2 in. (50.8 mm). For a material with a yield strength of 80 Kpsi (551 N/mm2), having a yield strain of 0.3%, this results in a plastic deformation. This is a proof that typical CT surface equipment plastically deforms steel coiled tubing during normal use. In order to avoid such plastic deformation, the only alternative is to use a different coiled tubing material such as titanium with higher yield strength and lower modulus of elasticity than steel or composite material with a low modulus of elasticity. However, reducing the modulus of elasticity reduces the coiled tubing stiffness thus increasing the risk of buckling. Composite CT for instance is very flexible and can be spooled with little damage, but due to its very low stiffness it buckles quickly when put in compression. 4.1.1 Effects of cyclic loading: If a metallic specimen is loaded beyond the yield point, subsequently unloaded, then loaded in the opposite direction, the material yield point in reduced. This phenomenon is known as Bauschinger effect and it appears in the case of coiled tubing subjected to consecutive bending and straightening. Figure 4.2 summarised two tests results for a sample of 1.5 in. (38.1 mm) OD x 0.109 in. (2.77 mm) wall thickness: test A consisted of pulling to 7 times the yield strain, compressing to zero strain and then repeating this cycle 100 times – a loading sequence similar to the one experienced by the CT wall outside (convex) side of each bend; test B consisted of a loading sequence opposite to test A, experienced by the CT wall inside (concave) side. The data in figure 4.2 indicate that coiled tubing exhibits elastic perfectly plastic behaviour only in its virgin state. Reverse of loading changes the character of the stress-strain diagram, causes strain softening and eliminates the sharply defined yield point. After 100 loading cycles (corresponding to 30 round trips of the coiled tubing through the surface equipment), the force required to achieve the initial yield strain dropped by about 20%, thus resulting in a decrease of approximately 20% in the material yield stress assuming the cross sectional area did not change significantly. However, the reduction in yield stress due to bending/straightening cycles would be less than predicted by cyclic axial loading tests because the strain varies across the wall during bending. None-the-less, the coiled tubing ability to support loads (its yield strength) decreases with normal use. Plastic deformation of material also imparts fatigue on the CT string, and fatigue continues to accumulate over the life of the coiled tubing string, until such time as fatigue cracks develop, resulting in a CT string failure (Fatigue can be defined as failure under a repeated or otherwise varying load, which never reaches a level sufficient to cause failure in a single application). Fatigue crack development is governed by complex states of multiaxial cyclic plasticity and residual stress. 29

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Fig. 4.2. Cyclic Loading Test Data (Bauschinger Effect) Source: CTES, LP – CT Manual, www.ctes.com.

4.1.2 Permanent elongation of coiled tubing: Coiled tubing field personnel repeatedly reported that CT elongates with about 10 ft. (about 3 m) for each round trip into the well. Coiled tubing undergoes plastic bending and straightening followed by axial loading throughout its life, a significant portion of its cross section yielding plastically due to bending. Rotation about the longitudinal axis also occurs, causing the bending neutral axis to rotate and the entire CT cross section to experience plastic yielding. Axial loading occurs on the reel and guide arch, due to reel back tension, and in the well, due to the string weight and drag. Intuitively, applying an axial load to coiled tubing that has been plastically yielded can cause axial elongation. Several types of modelling and experimental testing showed that significant permanent elongation of coiled tubing can occur. Figure 4.3 summarises the results of a general-purpose finite element analysis program which modelled half section of coiled tubing. The total elongation of 1500 microstrain (0.15%) is equivalent to 15 ft. (4.5 m) of elongation in 10,000 ft. (3050 m) of coiled tubing. It can be noticed that the final bending and straightening (happening at the guide arch after coming up through the chains) actually removes some of the elongation. The CT engineering company CTES, LP has developed a simple numerical computer model whose results have been compared with the FEA in Figure 4.3 (they are shown as diamonds in the figure). This model has been used to generate the results presented in Figure 4.4 to 4.6. Figure 4.4 shows the results of a numerical experiment in 30

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which the coiled tubing has been bend and straightened, then axially loaded and finally the axial load was released. Figure 4.5 shows the results of experiments in which the coiled tubing was rotated between bending events, while Figure 4.6 summarises the results of studying the permanent elongation caused by axially loading CT while bending (as it happens on the reel and over the guide arch).

Fig. 4.3. Permanent Elongation, Finite Element and Numerical Results Source: CTES, LP, www.ctes.com.

Fig. 4.4. Plastic Results, Elongation Due to Axial Loading Only

Fig. 4.5. Plastic Results, Elongation Due to Rotation and Axial Loading

Fig. 4.6. Plastic Results, Elongation Due to Axial Load while Bending

Source: CTES, LP, www.ctes.com.

Source: CTES, LP, www.ctes.com.

Source: CTES, LP, www.ctes.com.

The results shown above, doubled by experimental tests and analytical modelling led to the following conclusions: ¾ For a given tensile load, elongation of plastically deformed coiled tubing is roughly twice the elastic elongation at that load. ¾ After releasing the tensile load, the permanent elongation of the coiled tubing is approximately equal to the elastic elongation at that load. ¾ Elongation due to tensile loads after plastic deformation of the coiled tubing is “permanent” only for tensile loads exceeding a transition load (see fig. 4.4), i.e. elongation due to tensile loads less than the transition load can be erased by subsequent bending. ¾ Rotation of the coiled tubing between RIH and POOH significantly increases the permanent elongation. 31

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¾ Axial loading of the CT while bending (caused by reel back tension) causes permanent elongation. The elongation between the reel and the guide arch may be greater than the one caused by the axial loading in the well. The transition load, Ft, can be calculated as a function of the CT wall thickness, t, yield stress, σy, Young’s modulus, E, and the bending radius, Rb, using the following analytical equation developed by CTES, LP within a JIP:

Ft = 0.5 ⋅ A ⋅ σ y + 3

σ y2 E

Rb ⋅ t

(4.2)

4.1.3 Mechanism for coiled tubing length change: Coiled tubing changes length every coiled tubing operation due to axial forces, temperatures, pressure differential across the CT wall, and helical buckling. Each of these can cause error between depth measured at the surface and the actual depth of the BHA downhole. Plastic length change can be recovered by subsequent plastic deformation in the surface equipment if the axial force is less than the transition force, Ft, from equation (2) above, or only partially recovered if the axial force exceeds F. Figure 4.7 below illustrates this concept for a length of coiled tubing subjected to an axial force exceeding the transition force.

Fig. 4.7. Coiled Tubing Stretch Due to Axial Load The amount of elastic stretch, ∆L, for a CT segment with the length L and the cross sectional area A, under the axial force F can be calculated as follows: ∆L = L σ / E = L F / A E (4.3) The plastic stretch can be calculated with the following equations: ∆L =

L⋅F ⎛A ⎞ ⎜ + Φ⎟⋅ E ⎝2 ⎠

if F < Ft

32

(4.4)

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Coiled Tubing Operations in Drilling & Workover ⎤ ⎡ ⎢ F − Ft ⎥ Ft ⎥ ⎢ + ∆L = L ⋅ ⎞ ⎥ ⎛A ⎞ ⎢⎛ A ⎢ ⎜⎝ 2 + Φ ⎟⎠ ⋅ E ⎜⎝ 2 − Φ ⎟⎠ ⋅ E ⎥ ⎦ ⎣

if F > Ft

(4.5)

Φ = r02 ⋅ θ 0 − ri 2 ⋅ θ i + r0 ⋅ ri ⋅ sin (θ i − θ 0 ) ,

where

⎛ 3ry ⎞ ⎟⎟ , r 2 ⎝ 0⎠

θ 0 = arcsin⎜⎜

⎛ 3ry ⎝ 2ri

θ i = arcsin⎜⎜

⎞ ⎟⎟ . ⎠

in which

r0 is the CT external radius (OD/2), ri – the CT internal radius, ry – the radius at which yielding of the CT material begins (Rb σy / E). Additional coiled tubing length change can occur due to thermal effects and to differential pressure across the wall due to Poisson effect (such length change being relatively small). Helical buckling, discussed in section 4.3.2 below, always reduces the CT apparent length (depth in the well) because the axial force is compressive, but such reduction is typically small. 4.2

Coiled Tubing String Design

The length of coiled tubing on a reel varies depending on diameter. For comparison, a small reel may only be able to hold 4,000 ft. (1220 m) of 27/8 in. (73.025 mm) tubing, but may have a 15,000 ft. (4570 m) capacity if 11/2 in. (38.1 mm) tubing is spooled on it. A properly sized coiled tubing string must have the following attributes for the planned operation: ¾ enough mechanical strength to safely withstand the combination of forces imposed by the job; ¾ adequate stiffness to RIH (run into hole) to the required depth and/or push with the required force; ¾ light weight to reduce logistics problems and total cost; ¾ maximum possible working life. Optimizing the design of a coiled tubing string to simultaneously meet the criteria listed above for a given coiled tubing operation requires a sophisticated CT numerical simulator and numerous iterations with proposed string designs. Coiled tubing strings designed in this manner usually will contain multiple sections with each one having a different wall thickness. Often called "tapered strings", the wall thickness does not necessarily taper smoothly from thick to thin (top to bottom). Instead, the wall thickness along the string will vary according to the position in the string. However, the OD of the string will remain constant and only the wall thickness changes with the position along the string. Likewise, CT strings are made from the same material from end to end. The basic procedure consists of “running” the Ct operation on the computer simulation program for a given coiled tubing string and then modifying the string design 33

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by changing the length and wall thickness of the sections to achieve the desired result. Even though this technique can provide the best Ct string for a given job, the string may not be suitable for operations in other wells or even other applications in the original well. Usually a more generic string design is desirable. The simplest method of designing a CT string considers only the wall thickness necessary at a given location for the required mechanical strength and the total weight of the string. This method assumes the open-ended CT string is hanging vertically in a fluid with the buoyed weight of the tubing being the only force acting on the string. Starting at the bottom of the string and working up, the designer selects the wall thickness at the top of each section that provides sufficient tensile force at that location (e.g. the designer could limit the stress at the top of each section to 30% of the material yield strength). 4.3

Buckling of Coiled Tubing Strings

Coiled tubing under axial compression can buckle into a sinusoidal or helical shape if the compressive force exceeds a certain “critical” value for that particular mode of buckling. Such phenomenon is common for operations in deep and/or extended reach wells. Even though plastic deformation on the reel causes residual curvature in the coiled tubing (only when the axial force is quite low), this is not a buckling state. However, such curvature may help promote buckling as axial compressive force on the coiled tubing increases. Unlike drill pipe, casing or tubing, buckling of coiled tubing by itself is not a serious problem, being an elastic deformation that does not damage the CT (a buckled coil tubing can continue to slide and transmit axial force). However, CT buckling significantly increases the normal force (drag) between the coiled tubing and the wellbore. This may lead to lock-up, if the compressive force above the buckled section increases high enough. A coiled tubing segment inside a wellbore buckles into different shapes (modes) when the axial compressive force acting on it exceeds values determined by the particular combination of geometry and physical properties of the segment. The segment remains unbuckled for lower axial compressive force. This threshold between buckling mode is normally called the critical compressive force. The buckling modes and limits are discussed in the following sections. 4.3.1 Sinusoidal buckling of coiled tubing strings: When the axial compressive force increases to the critical sinusoidal buckling limit, the segment deforms into a sinusoidal (“snake-like”) shape in continuous contact with the wellbore. The buckled segment does not move away from the wellbore nor lie in a plane and continues to change shape as the axial force increases beyond the critical limit, but the normal force exerted by the segment on the wellbore is due mainly to the weight of the segment. Sinusoidal buckling does not present a limiting condition for CT operations, but is an intermediate condition on the path to helical buckling. A schematic of the CT sinusoidal buckling is shown in Figure 4.8 for a horizontal wellbore.

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Fig. 4.8. CT Postbuckled Sinusoidal Configuration in a Horizontal Hole The critical sinusoidal buckling limit, FCS, for a straight segment inclined at an angle, θ, greater than about 15o (with respect to the vertical – it is the case of a highly inclined wellbore) can be calculated as follows: FCS = 2

EI ⋅ W ⋅ sin θ , rc

(4.6)

where rc = 0.5 (DH – OD) , in which OD is the outside diameter of the CT and DH is the hole (wellbore) diameter. It can be seen that equation (4.6) contains only the bending stiffness of the CT segment, EI, its buoyed weight (per unit length), W, and geometrical terms. they are independent of the CT yield strength. Equation (4.6) includes also the case of a horizontal wellbore for which θ = 90o and therefore sin θ = 1. 4.3.2 Helical buckling of coiled tubing strings: If the axial compressive force continues to increase past the critical helical buckling limit, the segment assumes a helical shape in continuous contact with the wellbore. After the segment is buckled helically, the normal force exerted by the segment on the wellbore gains a component proportional to the square of the axial compressive force. Thus, drag on a helical buckled segment increases rapidly with increasing axial compressive force. In order to account properly for this additional drag in the force balance, we must know when the axial force on a segment exceeds the critical helical buckling limit. A schematic of the CT helical buckling is shown in Figure 4.9 for both a horizontal and a vertical wellbore. The axial compressive force required to helically buckle an inclined CT segment is about 41% greater than FCS from equation (4.6). The critical helical buckling limit, FCH, for a straight inclined segment can be calculated as follows: 35

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FCH = 2 2

EI ⋅ W ⋅ sin θ , rc

(4.7)

The symbols from equation (4.7) are the one used in equation (4.6). The same observation applies, concerning the independence of the yield strength.

Fig. 4.9. CT Postbuckled Helical Configuration in a Horizontal / Vertical Hole The critical helical buckling limit, FVH, for a straight vertical segment, i.e. inclined at angles less than about 15o, can be calculated as follows: FVH =

1.943 EI ⋅ W 2 ,

(4.8)

It can be seen that equation (4.8) depends only on the stiffness and buoyed weigth of the segment, while the CT material yield strength is not a factor. For common coiled tubing sizes in vertical holes, FVH is typically less than 200 lbf (890 N) compression. This force may seem insignificant, but for many situations most of the coiled tubing in a vertical wellbore is in tension, and buckling is not an issue. If part of a CT string is in compression and the remainder is in tension, the location where axial force changes from tension to compression is called the neutral point (see fig. 4.9). For common coiled tubing sizes, FCH for a segment can be 20-30 times greater than FVH. This partially explains why CT usually buckles first near the bottom of the vertical portion of a well during RIH. Another reason is that drag is much higher on curved and inclined segments leading to higher axial compressive force at the bottom of the vertical section. It can be also noted that FCH increases with decreasing radial clearance and increasing segment bending stiffness, weight and inclination. This provides several options for reducing the tendency of a segment to buckle helically. If buckling could be a problem, larger diameter coiled tubing simultaneously

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increases I and W while decreasing rc. Another alternative is to increase the CT wall thickness which simultaneously increases I and W. It is very important to state that both alternatives increase the drag between the coiled tubing and the wellbore. Depending on the conditions, this can offset any benefit of greater stiffness. The only way to determine the effects of changing coiled tubing dimensions is by using a coiled tubing simulator program. If the coiled tubing dimensions are fixed, the only way to increase the critical helical buckling limit is to lower mud weight (increase W) or conduct the CT operation inside a smaller casing or hole size (decrease rc). 4.3.3 Effects of wellbore curvature and of friction: In general, wellbore curvature stabilizes a segment against buckling, I.e. Coiled tubing buckles more easily in straight sections of the wellbore than in dogleg or build sections. This does not necessarily means that tortuosity or curvature in the wellbore is beneficial for CT operations (reducing the buckled length would extend the CT reach into a well), because curvature also causes higher drag which may shift the location of buckling upwards. Traditionally, equation (4.7) has been used in curved holes by considering θ as the average inclination of the curved segment. However this does not account for the stabilizing effect of curvature on buckling because equation (4.7) does not take into account the direction or rate of curvature. An improved procedure accounts for the effect of curvature by including the normal force due to curvature as additional resistance to buckling. Finally, a complex quadratic polynomial equation is obtained for the axial force requires for helical buckling in a curved hole, FH. Such force value is found to be greater than FCH in building, high dropping and purely azimuthal curvatures, while it is smaller for moderately dropping curvature. Complex buckling experiments indicated that friction significantly affects buckling behaviour of tubing. In general, friction stabilizes a tubular under compression to delay the onset of buckling and also causes hysterezis in the post-buckling behaviour. Figure 4.10 below shows typical results from buckling experiments for a rod buckled inside a tube. It can be seen that hysterezis is significant and axial compressive force at unbuckling is always lower than the one at the onset of buckling. The conclusion is that current theory actually predicts axial compressive force at unbuckling and therefore predicted critical buckling forces are conservative – equation (4.7) predicts FCH values significantly lower than determined experimentally. Unfortunately, friction is very difficult to include in stability analyses (based on “energy” methods) as it is not a conservative force. Friction has a stabilizing effect on helical buckling by delaying the buckling onset. An adjusted critical helical buckling limit for an inclined segment with friction can be obtained from equation (4.7) by adding the drag force (a frictional stabilizing force equal to Cf·W·sinθ where is Cf the drag coefficient). The following equation results:

(

F’CH = 2 2 1 + C f

)

EI ⋅ W ⋅ sin θ = (1 + C f ) ⋅ FCH , rc 37

(4.9)

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Fig. 4.10. Effects of Friction on Buckling (experimental results) Equation (4.9) still seems to underestimate the measured critical helical buckling force. It implies that higher Cf values are beneficial as buckling is delayed, resulting in longer reach for RIH. However, once the coiled tubing buckles, higher Cf leads to a significantly higher post-buckling drag which will shift the buckling problem up to the wellbore by increasing the axial compressive force on the segments above. 4.3.4 Post-buckling lock-up: Once the helical buckling occurs, the total length change, ∆L, in the coiled tubing by this phenomenon can be calculated using the following equations:

⎡ ⎛ 2π ⋅ r ⎞ 2 ⎤ c ⎢ ⎟ + 1 − 1⎥ ∆L = L· ⎜ λ ⎢ ⎝ ⎥ ⎠ ⎢ ⎥ where

λ = 2π

2 EI F

(4.10)

is the helix period

and F > FCH is the axial compressive force in the buckled CT segment. By itself, helical buckling is neither a critical problem nor a limiting condition for coiled tubing. It does not damage or plastically deform the coiled tubing. However, post/buckling lock-up is the limiting condition for RIH. Lock-up can prevent the BHA from reaching the touch down point. In simple terms, lock-up is a local phenomenon that occurs during RIH when the local increase in drag exceeds the axial compressive force from the Ct segment above. When buckled coiled tubing reaches this condition, any further increase in axial compressive force at the top of the helix is lost completely to drag. Since normal force due to helical buckling increases as the square of axial compressive force, lock-up may occur almost immediately after a segment helically 38

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buckles. Attempting to force more coiled tubing into a hole after lock-up can damage the tubing. Proper modelling of post-buckling drag effects with a CT computer simulator is required to determine whether lock-up occurs. 4.4

Coiled Tubing Limits. Burst and Collapse

When there is a large pressure differential across the coiled tubing wall, especially when combined with a large axial force, there is a risk of CT failure (burst or collapse). A positive differential pressure, i.e. an internal pressure greater than the external pressure, represents a burst condition, while a negative differential pressure, i.e. a grater external pressure, represents a collapse condition. Typically the greatest risk of burst or collapse occurs at the wellhead. These limits can be predicted by using a mathematical model, usually based on the von Mises combined stress and taking into account helical buckling, maximum expected pressures, torque and diameter growth. Considering the coiled tubing geometry and the four applied loads (internal pressure - pi, external pressure - pe, axial force - F, applied torque - Mt), the principal stresses acting on a CT segment are determined (axial stress, including bending - σa, radial stress - σt, tangential / hoop stress - σh, shear stress - τ) and finally the total equivalent von Mises stress, σvM, is calculated. As the equations used for such calculation are widely known, they are not included in this module. It has only to be mentioned that when calculating the axial stress, the real force, Fa, has to be considered and not the effective force, Fe. Fa is the actual axial force (as it would be measured by a strain gauge), while Fe, also called the “weight”, is the axial force if the effects of pressure are ignored (it is the force measured by the weight indicator on the CT unit and the load upon which buckling depends). The relationship between these two forces is (where Ai is the CT internal cross sectional area and Ae the CT external cross sectional area): Fa = Fe + Ai pi – Ae pe Finally, the combined von Mises stress is compared with a given percentage (usually 80%, defined by the safety factor) of the yield strength of the given CT material. Such approach, even if it is considered a good method for calculating the mechanical limits for steel CT (due to its conservative results), ignores the following conditions: residual stress, work softening, perfectly plastic behaviour, ovality etc. Above the injector, the dominant failure mode is fatigue. Below the injector chains and above the stripper, combined compression and burst pressure are the dominant loads but they are not usually a concern. Below the stripper, the most likely failure modes are collapse and tensile failure, while excessive compression is normally not a problem. Coiled tubing mechanical limits curves can be drawn, showing the combination of the values of the axial force (real or effective) versus the ones differential pressure for which a limit condition is reached (the equivalent stress equals the yield limit) and therefore there is a risk of potential failure of the coiled tubing. Collapse failure mode is difficult to predict by means of the von Mises criterion briefly described above because it depends on factors that are seldom known accurately (CT ovality and eccentricity, yield stress). To model CT collapse, apart the plastic hinge theory proposed by Newman, API RP 5C7 proposed a set of empirical equations to predict the collapse pressure differential. 39

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5. Current Applications of Coiled Tubing Technology in Drilling and Workover The final chapter of this module discusses the most important aspects of the drilling and workover applications of coiled tubing. The limitations of CT technology and a solution to overcome the limits of present CT drilling units are also discussed. 5.1

Coiled Tubing Drilling Applications

Coiled tubing drilling has been utilized on a commercial basis for many years, and can provide significant economic benefits when applied in the proper field setting. Figure 5.1 shows a coiled tubing drilling unit detailing the subsurface standard equipment used for such operation. In addition to potential cost advantages, CT drilling can provide the following additional benefits: ¾ Safe and efficient pressure control; ¾ Faster tripping time and speed (more than 150 ft./min – 45 m/min); ¾ Smaller footprint and weight; ¾ Faster rigup/rigdown; ¾ Reduced environment impact; ¾ Less personnel; ¾ High speed telemetry (optional feature). However, the most significant disadvantage of coiled tubing drilling is the inability to rotate the CT in the borehole which implies that the energy required to rotate the drill bit must be supplied by the pressurised drilling mud driving a hydraulic motor. In addition, the lack of rotation causes increased friction between the CT and the walls of the wellbore which makes more difficult the translation of the CT string in the wellbore and may require more frequent tripping of the tubing. As a consequence, several attempts have been made to develop a CT unit capable also to rotate the coiled tubing (see figure 2.2 and 5.2). CT drilling applications have also other limitations that are commented in section 5.3, including the offshore drilling operations. Table 5.2 below contains a coiled tubing drilling applications summary divided in four major categories. The first applications have been re-entry drilling. Table 5.1. CT Drilling Applications Summary (Source: [10]) Vertical Drilling Deviated Drilling Depending on existing wells Lateral drainholes Re-entry Drilling Disposable exploration wells Steam injection Observation and delineation wells New Well Drilling Environmental observation Slim-hole production/injection wells Bit design and selection for coiled tubing drilling follows the same theory as is used in conventional rotary drilling. However, CT drilling generally uses higher bit 40

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speeds at lower weight on bit as a result of the structural differences in coiled tubing versus jointed pipe.

Fig. 5.1. Typical CT Unit for Drilling Applications 41

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Coiled Tubing Operations in Drilling & Workover 5.1.1 Directional and non-directional wells:

In general, coiled tubing drilling can be divided into two main categories consisting of directional and non-directional wells, i.e. vertical and deviated drilling. Nondirectional wells use a fairly conventional drilling assembly in conjunction with a downhole motor. Directional drilling requires the use of an orienting device to steer the well trajectory, per the well plan. CT drilling can then be further segmented into overbalance and under-balanced drilling applications. Non-directional wells represent the largest coiled tubing drilling application, and these are defined as a well that lacks downhole tools to control direction, inclination and/or azimuth. Much of the CT drilling work performed to date involved shallow gas well development in Canada, but it has also been used for shallow water injection wells and for "finishing" operations. A primary advantage that coiled tubing drilling provides in this application is the speed of the rig up/down operation, and the continuous rate of penetration (no delays to add stands of jointed pipe). The majority of this CT drilling work has been performed with hole sizes less than 7 in. (177.8 mm), but hole sizes up to 133/4 in. (about 350 mm) have been successfully drilled. Much the same as in conventional drilling, drill collars can be used in low angle wells to control inclination build-up and apply weight on bit for coiled tubing drilling applications. Coiled tubing drilling application for directional wells utilizes an orienting device in the bottom hole assembly (BHA) to control the wellbore trajectory as desired. CT drilling for this application can include new wells, extensions, side-tracks through existing completions, horizontal drainholes, or side-tracks where the completions are pulled. However, the primary use of coiled tubing drilling for directional wells is to directionally drill into new reservoir targets from existing wellbores. Directional drilling with coiled tubing has some fundamental differences compared to conventional rotary drilling techniques. One of the basic differences is the need for an orienting device to control the well trajectory, since CT cannot rotate. Orienting devices control hole direction by rotating a bent housing to a particular orientation (toolface) or controls the side loading at the bit to push the assembly in a particular direction. This control over the BHA provides directional control for coiled tubing drilling applications. A steering tool is used to measure inclination, azimuth, and tool face orientation. Two basic types of steering tools are used for directional drilling with CT. Electric steering tools are used in conjunction with a cable inside the coiled tubing to transmit data to surface. Mud pulse tools comprise the second type of steering device for CT drilling applications. Mud pulse steering tools transmit data to the surface by generating pressure pulses in the mud. In addition to orientation and steering devices, some BHAs utilized for coiled tubing drilling are equipped with additional measurement tools, including gamma ray, casing collar locator, accelerometers (shock load measurements), pressure (internal and annulus) and weight on bit. 5.1.2 Wellbore hydraulics and wellbore fluids: There are some key fluid design parameters to keep in mind for coiled tubing drilling applications versus traditional rotary drilling. For example, all CT drilling 42

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operations require the fluid to travel through the entire tubing string regardless of the current drilling depth. In addition, the frictional pressure loss for coiled tubing on the reel is considerably larger than for straight tubing. Thus, for optimum hydraulic performance, the drilling fluid must behave as a low viscosity fluid while inside the CT, and as a high viscosity fluid in the annulus (for efficient cuttings removal). Another key difference associated with coiled tubing drilling is the absence of tubing rotation while drilling. Jointed pipe is rotated during conventional drilling operations, and this movement helps keep the drill cuttings suspended in the drilling fluid, so they can be lifted to surface. Since the tube doesn't rotate in CT drilling applications, hole cleaning can be more challenging in heavily deviated/horizontal applications. This effect is partially offset by the smaller cuttings produced with coiled tubing drilling (higher RPM, lower weight on bit). In addition, special visco-elastic fluids have been developed for CT drilling, that change their rheology according to the local shear rate, i.e., become more viscous in the annulus (lower shear rate) to improve cutting suspension. 5.1.3 Overbalanced and underbalanced coiled tubing drilling: For overbalanced drilling, as with conventional well drilling operations, the drilling fluid is used for controlling subsurface pressure and the coiled tubing drilling fluid systems are typically smaller versions of conventional systems. Conventional well control principles apply except that the CT string limits the fluid flow rate and the frictional pressure loss varies with the ratio of tubing on/off the reel. To date, most underbalanced coiled tubing drilling activity has been for re-entry operations, but new wells could also benefit from this approach. CT drilling is ideal for this underbalanced applications because of it's inherent well control system. In addition, underbalanced "finishing" is a variation of underbalanced drilling used extensively in Canada and gaining acceptance in other areas. For finishing operations, a conventional rig is used to drill to the top of the reservoir and casing is run. From this point, coiled tubing drilling is utilized to drill into the reservoir with underbalanced drilling techniques. This technique attempts to leverage the respective strengths of both drilling approaches. Conventional drilling can be faster (less expensive) in the large diameter, unproductive uphole drilling intervals, while underbalanced CT drilling is faster (less expensive) in the producing interval. coiled tubing drilling is also better suited to deal with the pressure/produced hydrocarbons from the productive interval. 5.2

Coiled Tubing Workover Applications

Coiled tubing is routinely used as cost-effective solution for numerous workover applications. A key advantage of coiled tubing in this application is the ability to continuously circulate through the coiled tubing while utilizing CT pressure control equipment to treat a live well. This avoids potential formation damage associated with well killing operations. The ability to circulate with coiled tubing also enables the use of flow-activated or hydraulic tools. Other key features of coiled tubing for workover applications include the inherent stiffness of the coiled tubing string. This rigidity allows access to highly 43

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deviated/horizontal wellbores, and the ability to apply significant tensile or compression forces downhole. In addition, coiled tubing permits much faster trip times as compared to jointed pipe operations. The most common coiled tubing applications for workover operations are listed in Table 5.2 below, groped in two categories. Table 5.2. Overview of Common Workover Applications Pumping Applications Mechanical Applications Removing sand or fill from a wellbore Setting a plug or packer Fracturing/acidizing a formation Fishing Unloading a well with nitrogen Perforating Gravel packing Logging Cutting tubulars with fluid Scale removal (mechanical) Pumping slurry plugs Cutting tubulars (mechanical) Zone isolation (to control flow profiles) Sliding sleeve operation Scale removal (hydraulic) Running a completion Removal of wax, hydrocarbon, or hydrate plugs Straddles for zonal isolation Source: International Coiled Tubing Association, www.icota.com.

In the followings, three of the most frequent workover applications are discussed. Other applications have been commented in section 1.3. 5.2.1 Removing sand or fill from a wellbore: The removal of sand or fill from a wellbore is the most common CT operation performed in the field. The process has several names, including sand washing, sand jetting, sand cleanout, and fill removal. The objective of this process is to remove an accumulation of solid particles in the wellbore. These materials will act to impede fluid flow and reduce well productivity. In many cases coiled tubing is the only viable means of removing fill from a wellbore. Fill includes materials such as formation sand or fines, proppant flowback or fracture operation screenout, and gravel-pack failures. The typical procedure involved in this application is to circulate a fluid through the CT while slowly penetrating the fill with an appropriate jetting nozzle attached to the end of the CT string. This action causes the fill material to become entrained in the circulating fluid flow, and is subsequently transported out of the wellbore through the CT/production tubing annulus. Where consolidated fill is present, the procedure may require the assistance of a downhole motor and bit or impact drill. An alternative fill removal approach is to pump down the CT/production tubing annulus and allow the returns to be transported to surface within the CT string. This procedure, called reverse circulation, can be very useful for removing large quantities of particulate, such as frac sand, from the wellbore. It may also be applied when a particular wellbore configuration precludes annular velocities sufficient to lift the fill material. Reverse circulation is suitable only for dead wells.

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Coiled Tubing Operations in Drilling & Workover 5.2.2 Fracturing / acidizing a formation:

This coiled tubing application has experienced significant growth in recent years, and provides several advantages versus conventional formation treatment techniques. In particular, CT provides the ability to quickly move in and out of the hole (or be quickly repositioned) when fracturing multiple zones in a single well. Coiled tubing also provides the ability to facture or accurately spot the treatment fluid to ensure complete coverage of the zone of interest. When used in conjunction with an appropriate diversion technique, more uniform treating of long target zones can be achieved. This is particularly important in horizontal wellbores. At the end of the formation treating operation, coiled tubing can be used to remove any sand plugs used in the treating process, and to lift the well to be placed on production. One of the earlier concerns with coiled tubing fracturing was the erosion effects that occur when proppant is pumped during the fracturing operation and the resulting impact on CT string life. An ultrasonic thickness (UT) gauge is now used on location to measure coiled tubing thickness during the job. Data from these UT measurements can be used to adjust the coiled tubing fatigue models, and to accurately monitor remaining CT string life. 5.2.3 Unloading a well with nitrogen: The process of using coiled tubing to unload a well with nitrogen is a quick and cost-effective method used to regain sustained production. A typical field scenario consists of a wellbore that has developed a fluid column with sufficient hydrostatic pressure to prevent the reservoir fluid from flowing into the wellbore. Displacement of some of this wellbore fluid with nitrogen reduces the hydrostatic head, and this reduction of BHP allows the reservoir fluid to again flow naturally into the wellbore. If the wellbore conditions are suitable (pressure, fluid phase mixture and flow rate), production will continue after nitrogen pumping ceases. There are numerous benefits associated with the use of coiled tubing for a nitrogen kickoff operation. The rate and depth of the nitrogen injection can be adjusted to fit a wide range of field conditions. The procedure also provides a ready source of uncontaminated production fluid samples (oil, formation water). And, the procedure is extremely simple from an operational standpoint, as only a small amount of equipment and a limited number of field personnel are necessary. 5.3

Limitations of Coiled Tubing Technology

In the following, the most important limitation of CT technology are discussed, focusing mainly on the drilling applications and including a solution (a new type of CT drilling unit) to overcome some of these limitations. The major limitations to CT drilling are: reel size and weight, maximum weight on bit and frictional drag, fatigue and hydraulics. For specific applications, coiled tubing drilling has the following basic limits restraining the field of drilling applications: weight and size limits, mechanical limits, life limits, and hydraulic limits.

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Coiled Tubing Operations in Drilling & Workover

In general larger coiled tubing allows higher loads, drainhole lengths and flow rates. However, the CT diameter may be restricted by space, weight and fatigue life. Reel size and weight limits lead to limitations of the CT string length and diameter. The flow-rate limitations of downhole motors limit the flow-rate gains of large tubing in many cases. In addition, large tubing in a small wellbore has a significant annulus pressure drop. It can de concluded that coiled tubing drilling has two major limitations, friction and high cost and therefore it is not largely used to drill. The design of the first APIcertified CT drilling rig (called Revolver) developed by Reel Revolution Limited overcomes both of these limitations. This unit’s rotation overcomes friction, assists in hole cleaning, and allows the use of standard directional BHAs. The ability to rotate coil at surface marries the best of rotary jointed pipe drilling with the best of coiled tubing drilling. Initial studies into potential efficiency savings translate into a 40% saving in rig time when compared to standard jointed pipe operations. This results in more reservoirs drilled per string year. The Revolver design can be operational upon arrival at the well site within six hours. In addition, the elimination of the guide arch from the new unit reduces fatigue and increases CT life, as illustrated in figure 5.2. Coiled tubing operations on many offshore platforms are also constrained by weight limitations (due to the lifting capacity of the crane) as well as deck loading and space limitations. A loaded CT reel is typically the heaviest component of the coiled tubing system. Various solutions to address this issue have been successfully implemented in the field, including: ¾ Disassembling the CT equipment into the smallest, lightest lifts possible, and reassembling the equipment on the platform; ¾ Cut the CT string into sections, spool the sections onto lightweight shipping reels, lift the reels onto the platform, then reconnect the sections; ¾ Lift the CT unit, minus the CT string, onto the platform. Then spool the CT string onto the work reel from a loaded reel on a floating vessel; ¾ Install only the CT injector on the wellhead, leaving the CT reel and other CT unit components on a barge or jackup, positioned alongside the platform. The second option requires high quality CT welding services to be available, while the last two options require more equipment and personnel versus that of typical CT operations, with an associated increase in the cost. Finally, the limitations of CT technology for pipeline applications are briefly discussed. Regardless of the operational environment (land or offshore), post-helical buckling lockup (see § 4.3.5) of the coiled tubing is typically the primary limiting factor for such operations. Lockup limits both the horizontal reach of the coiled tubing into the pipeline, and the maximum available force that it can transmit. In addition, the radial clearance between the CT and the pipeline is usually much larger when compared to standard wellbore operations, thus reducing the downhole critical force required to helically buckle the coiled tubing. Also, oil pipelines typically have an internal coating of highly viscous oil or wax that significantly increases the CT sliding friction coefficient. This excessive drag against the coiled tubing can also reduce the length of CT that can be pushed into the pipeline prior to buckling.

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Coiled Tubing Operations in Drilling & Workover

The typical approaches used to overcome coiled tubing drag in pipelines are: the use of liquid friction modifiers to reduce the coefficient of friction between the CT and the pipeline; the addition of "skates" (rigid centralizers or stabilizers with rollers) to the CT string at regular intervals; the use of hydraulic "thrusters" consisting of jets aimed in a direction opposite to the CT movement direction.

Fig. 5.2. Comparison between Conventional and Revolver CT Fatigue Source: Reel Revolution Limited, www.reel-revolution.com.

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Coiled Tubing Operations in Drilling & Workover

References 1. API RP 5C7 Recommended Practice for Coiled Tubing Operations in Oil and Gas Services. 2. CTES, LP, Coiled Tubing Manual, Longview, Texas, 2005, www.ctes.com. 3. ICoTA (International Coiled Tubing Association), An Introduction to Coiled Tubing – History, Applications, and Benefits, www.icota.com. 4. E. Mark, World Oil’s Coiled Tubing Handbook, Gulf Publishing Company, 1993. 5. A. Sas-Jaworsky, Coiled Tubing Operation and Services, Part 1-5, World Oil, Houston, Texas, 1991-1992. 6. E.J. Walker, L. Grantt, Coiled Tubing Operation and Services, Part 7, World Oil, Houston, Texas, 1992. 7. J.L. Welch, R.R. Whitlow, Coiled Tubing Operation and Services, Part 8, World Oil, Houston, Texas, 1992. 8. J.L. Welch, R.K. Stevens, Coiled Tubing Operation and Services, Part 9, World Oil, Houston, Texas, 1992. 9. Ken Newman, Where is the Coiled Tubing Wave Headed?, Power Engineering International Magazine, Sept. 1994. 10. L.J. Leising, K.R. Newman, Coiled Tubing Drilling, SPE Paper 24594, 1992. 11. H.V. Thomas, D.M. Eslinger, Safe Deployment of Specialized Coiled Tubing Tools in Live Wells, SPE Paper 24621, 1992. 12. D.G. Zisopol, Research Concerning the Coiled Tubing Manufacturing Used in Petroleum-Gas Industry, Ph. D. Thesis, Petroleum-Gas University of Ploieşti, 2000. Web sites: 13. www.advancedcoiledtubing.com 14. www.astm.org 15. www.coiledtubingtulsa.org 16. www.drillingsystems.com 17. www.halliburton.com 18. www.nov.com 19. www.reel-revolution.com 20. www.slb.com/Schlumberger

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