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PEH:Coiled-Tubing Well Intervention and Drilling Operations
Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume II - Drilling Engineering
Robert F. Mitchell, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 16 - Coiled-Tubing Well Intervention and Drilling Operations
Birth of Coiled-Tubing (CT) Technology
Numerous continuous-length tubular service concept trials and inventions paved the way for the creation of present day CT technology. The following discussion outlines some of the inventions and major milestones that directly contributed to the evolution of the continuous-length tubular products used in modern CT services.
The origins of continuous-length, steel-tubing technology can be traced to engineering and fabrication work pioneered by Allied engineering teams during the Second World War. Project 99, code named "PLUTO" (an acronym for Pipe Lines Under The Ocean), was a top-secret Allied invasion enterprise involving the deployment of pipelines from the coast of England to several points along the coast of France. The 3-in. inside diameter (ID) continuous-length pipelines were wound upon massive hollow conundrums, which were used to spool up the entire length of individual pipeline segments. The reported dimensions of the conundrums were 60 ft in width (flange-to-flange), a core diameter of 40 ft, and a flange diameter of 80 ft. These conundrums were designed to be sufficiently buoyant with a full spool of pipeline to enable deployment when towed behind cable-laying ships. Six of the 17 pipelines deployed across the English Channel were constructed of 3-in.-ID steel pipe (0.212-in. wall thickness). The 3-in.-ID steel pipelines, described as "Hamel Pipe," were fabricated by butt-welding 40-ft lengths of pipe into approximately 4,000-ft segments of pipeline. These 4,000-ft segments were then butt-welded together and spooled onto the conundrums. A total of 172,000,000 gallons of petrol was reported to have been delivered to the allied armies through PLUTO pipelines at a rate of more than 1 million gal/D.
Although the initial development effort of spoolable steel tubulars was reported to have occurred in the early 1940s, the first concept developed for use of continuous-length tubing in oil/gas wellbore services can be found in U.S. Patent 1,965,563, "Well Boring Machine," awarded on 10 July 1934 to Clyde E. Bannister. This approach utilized "reelable drillpipe," which was flexible enough to be coiled within a basket for storage when it was run into or out of the borehole (Fig. 16.1). This original concept used a rubber hose as the drillpipe, with the hose couplings designed to accommodate the attachment of two steel cables to provide the axial load support for the weight of the hose and bottomhole drilling assembly. The hose-coupling-cable-attachment clamps were also designed to allow removal of the steel cables as the flexible drillstring was removed from the wellbore. When pulling the flexible drillstring out of the wellbore, the separate cable lines were spooled onto drums for storage.
The reeled drillstring system repeatedly used a bottomhole mud percussor and an oscillator (at different times) to drive the bit. In 1935, a total of 4,000 ft of borehole was drilled with this system, with a maximum single borehole depth of 2,000 ft. The Bannister reelable drillpipe system reportedly became inactive in or about 1940 because of the lack of suitable downhole motors available.
The first concept on record for use of continuous-length steel tubing in well-service work was proposed by George D. Priestman and Gerald Priestman, as seen in U.S. Patent 2,548,616, "Well Drilling," awarded 10 April 1951. The patent claimed the invention of a reeled, rigid-pipe drilling system in which the steel pipe is spooled onto a carrier reel. The reeled drillpipe was proposed to be deployed into the wellbore through a series of rollers mounted above the carrier reel, which was also fashioned to serve as a pipe bender (Fig. 16.2). Once the steel pipe was run through the pipe-bending device, the pipe was oriented vertically and entered a pipe straightener mounted on the wellhead. This straightener was proposed as a series of motor-powered rollers and also served as the drive mechanism for deploying and retrieving the drillpipe.
Modern CT Technology
The chronology of modern-day steel CT technology development appears to begin in the early 1950s with U.S. Patent 2,567,009, "Equipment for Inserting Small Flexible Tubing into High Pressure Wells," awarded to George H. Calhoun and Herbert Allen on 4 September 1951. The fundamental concepts developed and claimed by Calhoun and Allen served as the basis for the vertical, counter-rotating chain tractor device, which was upscaled to serve as the design for the first CT injector placed in operation.
This apparatus provided the ability to insert, suspend, and extract strings of elongated cylindrical elements (such as tubing) for well-intervention services with surface pressure present. A modified version of this device was originally developed to enable submarine vessels to deploy a radio communications antenna up to the ocean surface while still submerged. Using the Calhoun and Allen concept, Bowen Tools developed a vertical, counter-rotating chain tractor device called the "A/N Bra-18 Antenna Transfer System," which was designed to deploy a ⅝-in. outside diameter (OD) polyethylene encapsulated brass antenna from as deep as 600 ft beneath the water level. Fabric-reinforced phenolic "saddle blocks" grooved to match the OD of the tube were installed as the middle section of the drive chain sets, securing the antenna during operations. The antenna was stored on a carrier reel located beneath the antenna transfer system for ease of deployment and retrieval. The pressure seal was provided by a stripper-type element, which allowed the antenna to penetrate the hull of the vessel. The basic principles of this design concept aided in the development of the prototype Bowen Tools CT injector system.
In 1962, the California Oil Co. and Bowen Tools developed the first working prototype "continuous-string light workover unit" for use in washing out sand bridges in U.S. Gulf of Mexico oil/gas wells (Fig. 16.3). The original "Unit No. 1" injector was designed as a vertical, counter-rotating, chaindrive system built to run a string of 1.315-in.-OD tubing and operate with surface loads of up to 30,000 lbf. The core diameter of the tubing reel was 9 ft and was equipped with a rotating swivel mounted on the reel axle to allow continuous pumping down the tubing throughout the workover operation.
The first full-scale continuous length of CT was fabricated from highly ductile 40-ksi-yield, low-alloy Columbium steel. This low-alloy Columbium "skelp" was reportedly rolled to a thickness of 0.125 in. by the Great Lakes Steel Co. (Detroit, Michigan) and then milled into 1.315-in.-OD tubing by Standard Tube Co. (Detroit, Michigan). The 50-ft milled tube lengths were butt-welded together using a combination tungsten inert gas (TIG) and metal inert gas (MIG) process. The assembled tubing string was spooled onto a reel with a 9-ft core diameter to a total length of 15,000 ft and then subjected to numerous bending and loading cycles. The performance of this tubing string and CT unit was tested in several wells (located inland and offshore of south Louisiana) in the early to mid-1960s. The services performed by this original CT unit included sand washing and fishing a storm choke out of the existing completion tubing.
CT Equipment Design
There are several CT equipment manufacturers presently marketing various designs of CT injectors, service tubing reels, and related well-control equipment in the industry today. The injector designs available within the industry include the opposed counter-rotating, chaindrive system, arched-chain roller drive, single-chain opposed-gripper-drive system, and the sheavedrive system. At present, the predominant equipment design for CT well-intervention and drilling services incorporates the vertically mounted, counter-rotating chaindrive type of injector. For purposes of practical demonstration, the following descriptions of CT equipment focus on the specific unit components supporting the vertical, counter-rotating chaindrive type of injector.
The CT unit is a portable, hydraulically powered service system that is designed to inject and retrieve a continuous string of tubing concentric to larger-ID production tubing or casing strings. At the present time, CT manufactured for well intervention and drilling application is available in sizes ranging from 0.750 to 3.500 in. OD. A simplified illustration of a CT unit is shown in Fig. 16.4.
The basic components of a CT unit are listed next.
- Injector and tubing guide arch.
- Service reel with CT.
- Power supply/prime mover.
- Control console.
- Control and monitoring equipment.
- Downhole CT connectors and bottomhole assembly (BHA) components.
- Well-control equipment.
The CT injector is the equipment component used to grip the continuous-length tubing and provide the forces needed for deployment and retrieval of the tube into and out of the wellbore. The injector assembly is designed to perform three basic functions:
- Provide the thrust required to snub the tubing into the well against surface pressure and/or to overcome wellbore friction forces.
- Control the rate of lowering the tubing into the well under various well conditions.
- Support the full weight of the tubing and accelerate it to operating speed when extracting it from the well.
Fig. 16.5 illustrates a typical rig-up of a CT injector and well-control stack on a wellhead. There are several types of counter-rotating, chaindrive injectors working within the industry, and the manner in which the gripper blocks are loaded onto the tubing varies depending on design. These types of injectors manipulate the continuous tubing string using two opposed sprocketdrive traction chains, which are powered by counter-rotating hydraulic motors.
The fundamental operating concept of the counter-rotating, opposed-chain injector is one that utilizes drive chains fabricated with interlocking gripper blocks mounted between the chain links (Fig. 16.6). These types of gripper blocks are designed to minimize damage to the CT and may be machined to fit the circumference of the CT string or formed in a "V" shape to accommodate variable OD sizes of CT (Fig. 16.7). The chaindrive assembly operates on the principle of frictional restraint, in that the CT is loaded by the opposing gripper blocks with sufficient magnitude of applied normal force that the resulting tangential friction forces are greater than the axial tubing loads (tension or compression).
In all traction-loading systems, hydraulic cylinders are used to supply the traction pressure and subsequent normal force applied to the CT (Fig. 16.8). The primary means of applying hydraulic pressure to this circuit may be through pumps on the prime mover, air-over-hydraulic pumps, or manual hand pumps. In addition, chain-loading systems require an emergency pressure source to maintain traction in case of a loss of hydraulic pressure supply. Typically, this system consists of an accumulator and a manual hydraulic pump or air-over-hydraulic pump located in the control cabin.
It is critical that the injector be equipped with a weight indicator that measures the tensile load in the CT (above the stripper), with the weight measurement displayed to the equipment operator during well intervention or drilling services. There should also be a weight indicator that measures the compressive force in the tubing below the injector when CT is being thrust into the well (often referred to as negative weight). Some weight indicators are capable of measuring a limited amount of negative weight—typically equal to the weight of the chaindrive assembly mounted in the injector frame. If this type of weight indicator is being used, the thrust force applied during the CT operation should not exceed the weight of the chaindrive assembly.
The counter-rotating, opposed-chaindrive injectors used in well intervention and drilling operations utilize a tubing guide arch, located directly above the injector. The tubing guide arch supports the tubing through the 90°+ bending radius and guides the CT from the service reel into the injector chains. The tubing guide arch assembly may incorporate a series of rollers along the arch to support the tubing or may be equipped with a fluoropolymer-type slide pad run along the length of the arch. The tubing guide arch should also include a series of secondary rollers mounted above the CT to center the tubing as it travels over the guide arch. The number, size, material, and spacing of the rollers can vary significantly with different tubing guide arch designs.
For CT used repeatedly in well intervention and drilling applications, the radius of the tubing guide arch should be at least 30 times the specified OD of the CT in service. This factor may be less for CT that will be bend-cycled only a few times, such as in permanent installations. The continuous-length tubing should enter and exit the tubing guide arch tangent to the curve formed by the guide arch. Any abrupt bending angle over which the CT passes causes increased bending strains, dramatically increasing the fatigue damage applied to the tubing. During normal CT operations, the reel tension applies a bending moment to the base of the tubing guide arch. Therefore, the tubing guide arch must be designed to be strong enough to withstand the bending caused by the required reel back tension for the applicable tubing size.
The injector should be stabilized when rigged up to minimize the potential for applying damaging bending loads to the well-control stack and surface wellhead during the well-intervention program. The injector may be stabilized above the wellhead using telescoping legs, an elevating frame, or a mast or rig-type structure. The injector support is the means provided to the injector to prevent a bending moment (such as reel back tension) from being applied to the wellhead of such magnitude as to cause damage to the wellhead or well-control stack under normal planned operating conditions. Precautions should be taken to minimize the transfer of loads resulting from the weight of the injector, well-control equipment, and the hanging weight of the CT into the tree along the axis of the wellhead.
Telescoping legs are generally used in rig-ups where the height of the injector or wellhead does not permit the use of an elevating frame. When telescoping legs are used, the top sections are inserted into the four cylinders located on the corners of the injector frame and then secured with pins at the required height.
Footpads are placed beneath each telescoping leg to distribute the weight of the injector to the surface grade. Further stiffness of the legs is achieved by tightening the turnbuckles mounted beneath the leg sections. When telescoping legs are used, the weight and operating forces of the injector and well-control stack assembly are transferred directly to the wellhead, requiring that the rig-up load be supported with a crane or traveling block to minimize the load applied onto the wellhead.
In rig-up scenarios where an unobstructed surface is available (e.g., offshore platforms), it is recommended to support the injector using a hydraulically or mechanically controlled elevating frame structure. Once the desired height of the stand is achieved, the four legs on the perimeter of the stand are pinned and secured in place. The base of the elevating frame distributes the weight of the injector evenly around the perimeter of the frame. The benefits of using an elevating frame over the telescoping legs include greater stability, latitude in releasing the overhead crane support in noncritical service, and safety.
In rig-up scenarios in which a mast or derrick is required, precautions must be taken to minimize the axial load placed on the wellhead by the injector and well-control stack. In addition, the injector should be secured in some fashion within the mast or derrick to minimize the pitch and yaw motion of the injector during service.
The service reel serves as the CT storage apparatus during transport and as the spooling device during CT well-intervention and drilling operations. Figs. 16.9 and 16.10 show the side view and front view of a typical service reel.
The inboard end of the CT may be connected either to the hollow segment of the reel shaft (spoke and axle design) or to a high-pressure piping segment (concave flange plates), both of which are then connected to a high-pressure rotating swivel. This high-pressure fluid swivel is secured to a stationary piping manifold, which provides connection to the treatment-fluid pumping system. As a result, continuous pumping and circulation can be maintained throughout the job. A high-pressure shutoff valve should be installed between the CT and reel shaft swivel for emergency use in isolating the tubing from the surface pump lines. The reel should also have a mechanism to prevent accidental rotational movement of the drum when it is required to remain stationary. In any event, the reel supporting structure should be secured to the deck or surface grade on location to prevent movement during operations.
In addition to the fluid-pumping service of the reel, electric wireline may be installed within the CT string to provide a means for conducting logging and downhole tool manipulation operations. The wireline is run inside the CT and is terminated at the reel shaft within a pressure bulkhead on the CT manifold. The single or multiconductor cable is then run from the pressure bulkhead to a rotating electric connection (slip collector ring) similar to that found on electric wireline units. On reels equipped for electric-line service, this electric connection may be located on the reel shaft opposite the rotating fluid swivel or at the pressure bulkhead adjacent to the inboard swivel piping.
In preparation for initial installation, a wing union is typically welded onto the end of the CT to be hooked up to the high-pressure piping within the reel (typically referred to as the "reference" end). The mechanical connection is then inserted through a slot in the reel core drum and made up to the high-pressure piping. Once the connection has been properly terminated, the tube is then bent over a preset guide to create a reasonably smooth bend transition to the outer surface of the core drum.
The initial layer of the tubing is spooled across the core drum until the tubing wrap reaches the opposing flange. The tubing is then spooled back over the base layer, resting in the recesses between the tubes on the previous layer. This wrapping process is continued through the remaining successive layers until the desired amount of tubing is spooled onto the reel. The manner in which the tubing is wrapped onto the reel allows the tube to be supported within the space formed by the previously wrapped tubing and offers a unique stacking geometry.
The core radius of the service reel defines the smallest bending radius for the tubing. For CT used repeatedly in well intervention and drilling applications, the core radius should be at least 20 times the specified OD of the CT. This factor may be less for CT that will be bend-cycled only a few times, such as for permanent installations.
The rotation of the service reel is controlled by a hydraulic motor, which may be mounted as a direct drive on the reel shaft or operated by a chain-and-sprocket drive assembly. This motor is used to provide a given tension on the tubing, thereby maintaining the pipe tightly wrapped on the reel. Back-pressure is kept on the reel motor during deployment, keeping tension on the tubing between the injector and service reel. This tensile load applied to the tubing by the reel motor is commonly called "reel back tension," requiring the injector to pull the tubing off the reel. The amount of reel back tension required increases with an increase in CT OD, yield strength (increased bending stiffness of the tubing), and distance between the service reel and injector. In addition, the required load on the reel drive system increases as the size of the core radius increases. Note that this tension results in an axial load imposed onto the tubing guide arch and creates a bending moment that is applied to the top of the injector. Therefore, it is critical that the injector is secured properly so that the bending moment is not translated to the well-control stack components or wellhead.
During operations, the reel back tension also prevents the tubing from "springing." Although the CT stored on a service reel has been plastically deformed during the spooling process, the tubing still has internal residual stresses that create a condition for potential unwrapping and outward springing of the tubing from the reel if the back tension is released. To prevent the CT from "springing," the free end of the tubing must always be kept in tension. When not in operation, the free end of the CT must be restrained to prevent springing.
The reel drive system must produce the tension required to bend the CT over the tubing guide arch and onto the reel. When CT is retrieved from the wellbore, the hydraulic pressure in the reel motor circuit is increased, providing the torque needed to allow reel rotation to keep up with the extraction rate of the tubing injector. Also, the reel drive system should have enough torque to accelerate the reel drum from stop to maximum injector speed at an acceptable rate. The torque should be capable of handling a fully loaded reel drum with the tubing full of fluid.
Additional safety items should also be included in the reel package to provide for an ancillary remote-activated braking system. The primary function of the reel brake is to stop drum rotation if the tubing accidentally parts between the reel and injector and limit tubing-reel rotation if a runaway condition develops. This braking system is not intended to halt the uncontrolled dispensing or retrieval of tubing in a runaway mode but only to offer resistance to slow down the reel rotation. The brake can also minimize tubing on the reel from springing in the case of loss of hydraulic pressure and, thus, the loss in reel back tension. When the reel is being transported, the brake should be engaged to prevent reel rotation. Many units incorporate a device in their hydraulic power systems to impose backpressure at the motor to slow the reel down. Other units employ a caliper-type or friction-pad braking system, which is hydraulically or mechanically applied onto the outer diameter of the reel flange to aid in slowing the reel rotation down.
The tubing is typically guided between the service reel and injector using a mechanism called the "levelwind assembly," which properly aligns the tubing as it is wrapped onto or spooled off the reel. The levelwind assembly spans across the width of the service reel drum and can be raised to any height, which will line up the CT between the tubing guide arch and the reel. Generally, a mechanical depth counter is mounted on the levelwind assembly, which typically incorporates a series of roller wheels placed in contact with the CT and geared to mechanically measure the footage of the tubing dispensed through it. The levelwind must be strong enough to handle the bending and side loads of the CT. During transportation, the free end of the CT is usually clamped to the levelwind to prevent springing. The levelwind may also be equipped with a hydraulically or pneumatically operated clamp, which can be manipulated to secure the CT at the crossbar of the levelwind frame.
In many cases, the service reel is equipped with a system for lubricating the outside of the CT. This tube lubricating system acts to protect against atmospheric corrosion and reduces the frictional loads encountered when deploying the tubing through an energized stripper assembly.
The high-pressure rotating swivel and treatment fluid plumbing must have a working pressure rating greater than the maximum anticipated pressure for the specified job. Special consideration should be given to cases in which the swivel and piping may come in contact with native wellbore fluids. These components must be suitable for the type of service and fluids encountered (e.g., H2S, high temperature, etc.). At least one high-pressure isolation valve should be incorporated between the high-pressure swivel and the surface-treatment piping.
CT power supply units are built in many different configurations depending on the operating environment. Most are hydraulic-pressure pump systems powered by diesel engines, though a limited few employ electrical power. In general, the prime mover packages used on CT units are equipped with diesel engines and multistage hydraulic pumps that are typically rated for operating pressures of 3,000 to 5,000 psig. The hydraulic drive unit is supplied in the size necessary to operate all of the CT components in use and will vary with the needs of the hydraulic circuits employed.
The most common hydraulic power pack system is described as an "open loop" circuit, in which the fluid is discharged from the prescribed motor and returned to the hydraulic reservoir at atmospheric pressure. In general, open-loop power packs are equipped with vane-type hydraulic pumps and are rated for a maximum 3,000 psig service pressure applied to the hydraulic circuit. The pumps in these power packs provide source power for the injector, service reel, levelwind, well-control stack accumulators, console priority, and auxiliary panels as needed.
Where additional power to the injector circuit is needed, the hydraulic power pack may be designed as a "high-pressure, open-loop" system or as a "closed-loop" system. In both of these enhanced hydraulic power systems, the high-pressure circuit is limited to the injector hydraulics, with the remaining circuits powered by the vane-type pumps. The increased pressure in the hydraulic circuit for the injector provides the means for generating higher force loads within the injector motors as compared to the vane pumps, which are limited to 3,000 psig service. The high-pressure open-loop system typically uses a piston pump to provide hydraulic pressure as high as 5,000 psig to the injector circuit. The hydraulic fluid is discharged from the injector motors to the hydraulic reservoir tank at atmospheric pressure. The closed-loop hydraulic system also provides injector pressure to a maximum of 5,000 psig, with the distinction being that the hydraulic fluid is recirculated to the injector without returning to the hydraulic reservoir. The hydraulic fluid losses experienced through the injector motors are compensated by a charge pump incorporated into the closed loop circuit.
In general, the hydraulic pumps on the power pack are equipped with pressure-relief valves or unloader valves that limit the amount of hydraulic pressure the pump can deliver to the prescribed circuit. These pressure-relief or unloader valves are set at the desired pressure for the respective circuit and must be checked periodically to ensure that they are functioning properly.
Specifically, the pressure-relief or unloader valve on the injector circuit should be set at a pressure that limits the amount of force that can be applied to the tubing in tension (pulling) and compression (thrust). Before dispatch of CT service equipment from the vendor facility, the unloader valve on the injector circuit (either on the power pack or in the console) should be set to a pressure which does not exceed the safe load limit of the CT in service. Tests should be performed before equipment load-out to verify the sustained pressure output and fluid flow rate for the hydraulic pumps.
In current power pack design, an accumulator circuit is typically included to provide fluid volume and pressure for the well-control stack operation. The number of accumulator bottles typically ranges from one to six, depending on the size and pressure rating of the well-control stack in service. The accumulator package for well-control operation must have sufficient volume and pressure capacity to complete three complete function cycles of all the rams incorporated within the well-control stack without recharge from the power pack. These function cycles are typically described as "close-open-close" cycles and should be performed periodically to ensure that the accumulators are precharged to the appropriate pressure and that the circuit is free of hydraulic leaks.
The control-console design for the CT unit may vary with manufacturers, but normally, all controls are positioned on one remote console panel. A diagram of a typical well-intervention unit control panel is seen in Fig. 16.11. The console assembly is complete with all controls and gauges required to operate and monitor all of the components in use and may be skid-mounted for offshore use or permanently mounted as with the land units. The skid-mounted console may be placed where needed at the wellsite as desired by the operator. The reel and injector motors are activated from the control panel through valves that determine the direction of tubing motion and operating speed. Also located on the console are the control systems that regulate the pressure for the drive chain, stripper assembly, and various well-control components.
Control and Monitoring Equipment
The CT equipment-related parameters that should be monitored to ensure the equipment is functioning correctly include traction force, chain tension, well-control system hydraulic pressure, reel motor pressure, injector motor pressure, and stripper hydraulic pressure. The critical job parameters that must be monitored throughout the job are discussed next.
Load Measurement. Load may be defined as the tensile or compressive force in the CT just above the stripper and is one of the most important measurements needed for proper operation of the prescribed service. Load may be affected by several parameters other than the hang weight of the CT and include wellhead pressure, stripper friction, reel back tension, and the density of the fluids inside and outside the tubing. Load should be measured directly using a load cell that measures the tensile and compressive forces applied to the CT by the injector. A secondary load measurement may be obtained indirectly by measuring the hydraulic pressure applied to the injector motors where the specified hydraulic pressure-to-load ratio is known.
Measured Depth. Measured depth is the length of CT deployed through the injector. Measured depth may be significantly different from the actual depth of the CT in the well because of stretch, thermal expansion, mechanical elongation, etc. Measured depth can be directly observed at several places on a CT unit using a friction-type wheel that contacts the tubing. Measured depth may also be obtained indirectly by measuring the rotation of the injector shafts. A CT unit should not be operated without a dedicated depth measurement system being displayed to the CT operator. Measured depth should be recorded as a function of time and in relation to internal pressure applied to the CT string for use in bend-cycle fatigue calculations.
Speed Measurement. Speed may be calculated from the change in measured depth over a specified time period.
CT Inlet Pressure. Pumping pressure at the inlet to the CT should be monitored and displayed to the CT operator, as well as recorded for use in bend-cycle fatigue calculations or for post-job reviews. This pressure-measurement system must incorporate a method of isolating the pumped-fluid circuit, eliminating the possibility for pumped fluid to discharge into the control cabin if gauge failure occurs. It is recommended that a pressure recorder be incorporated in the CT pressure-monitoring package to record pump pressure throughout the prescribed service.
Wellhead Pressure. Well pressure around the outside of the CT at the wellhead should be monitored and displayed to the CT operator, as well as recorded for use in post-job reviews. This pressure-measurement system must incorporate a method of isolating the wellbore fluid circuit, eliminating the possibility for well fluids to discharge into the control cabin if gauge failure occurs. It is recommended that a pressure recorder be incorporated in the CT pressure-monitoring package to record well pressure throughout the prescribed service.
Downhole CT Tool Connections
There are several connections used in CT services for the purpose of isolating pressure and transferring tension, compression, and torsional loads from tools and bottomhole assemblies onto the tube. These connections are typically designed to be field installed and reusable. The most common CT connections are discussed next.
Nonyielding Connections. The following connections have the capability of securing loads and pressure to the end of the CT in a manner that, during makeup, does not result in yielding of the tube body.
External Slip Type. The external slip-type connection requires the use of a slip or grapple-type load ferrule placed on the OD of the tube body. The load ferrule is typically constructed with sharp "spiraled" teeth that secure the ferrule onto the CT. The tool connection mechanically wedges the load ferrule onto the CT OD during connection makeup.
Pressure integrity of this connection is typically maintained with the use of O-rings or other types of elastomeric seals on the OD of the CT body. The external CT surface must be prepared to allow for an effective seal.
Internal Slip Type. The internal slip-type connection requires the use of a slip or grapple-type load ferrule placed within the ID of the tube body. The load ferrule is typically constructed with sharp "spiraled" teeth that secure the ferrule onto the ID wall of the CT. The tool connection mechanically wedges the load ferrule into the CT ID during connection makeup. Pressure integrity of this connection is typically maintained with the use of O-rings or other types of elastomeric seals applied against the ID of the CT body. The internal CT seam must be removed and the ID prepared for an effective seal by smoothing and buffing the ID surface scars and imperfections.
It should be noted that these nonyielding connections require that the terminated end of the CT be reasonably round, with OD/ID dimensions within the connector size tolerance. Problems often arise when using these connections on older, used CT that have become oval (distortion of tube roundness) or have experienced diametral growth (see 16.5.3).
The changes in CT geometry caused by ovality and diametral growth make sealing difficult when using common O-ring technology. Other elastomeric seals are often employed in larger OD CT when the diametric clearance may exceed O-ring sealing parameters.
Changes in CT OD geometry also present problems when trying to install the connectors onto the CT. Where CT geometry changes, resulting from ovality, are present (typical in larger OD CT sizes), a swaging tool may be used to return the tube body to a "near round" condition. The swaging tool is constructed similar to a muffler-pipe expander, with a hollow-core hydraulic jack pulling a short swaging cone up through a longer split skirt expander. The diameters of the swaging cone and skirt expander are chosen for a given CT size to yield the tube body OD a few thousandths larger than desired. After swaging, the CT body springs back, providing a CT OD with minimal ovality.
Yielding Connections. The following connections have the capability of securing loads and pressure at the end of the CT in a manner that, during makeup, results in yielding of the tube body.
External Dimple Type. The external-dimple-type connection is secured onto the tube body through the use of numerous mechanical screws. Forces exceeding the CT material yield strength create "dimples" in the tubing. These "dimples" serve as recessed receptacles for the mechanical screws that secure the connection to the tube body OD. Other variations of this basic connection method include pressure actuated dimpling tools used in conjunction with a template. Pressure integrity of this connection is typically maintained with the use of O-rings or other types of elastomeric seals on the OD of the CT body.
Internal Dimple Type. The internal-dimple-type connection is secured onto the CT body through the use of numerous mechanical indentations into recesses on an internal mandrel insert. Forces exceeding the CT material yield strength create "dimples" in the tubing, serving as the load transfer mechanism that secures the connection to the CT body ID. Pressure integrity of this connection is typically maintained with the use of O-rings or other types of elastomeric seals on the ID of the coiled tube body.
Roll-On Type. The roll-on type connection incorporates a machined insert mandrel designed to fit inside the CT. The mandrel is machined with circular recesses or "furrows." The connection is secured to the tube by means of mechanically yielding the tube body into the machined recesses on the mandrel. Pressure integrity of this connection is typically maintained with the use of O-rings or other types of elastomeric seals on the ID of the tube body.
Weld-On Connectors. Weld-on connectors are used in special applications such as coiled tubing drilling (CTD) in which larger CT is used and the aforementioned connectors impose operating limitations. These limitations include an excessively large OD, reduced torque or other load ratings, vibratory and oscillating load suitability, or a restricted ID that reduces the size of pump-down darts or ball.
Properly designed weld-on connectors will exhibit 100% of the torque and yield ratings of the CT material.
Important parameters to proper weld-on connector design and application include:
- A gradually tapered insertion neck several inches up from a straight-wall section that continues to the weld-bead location (Fig. 16.12). This taper provides a bend support to prevent concentrating bending loads at a single point where the CT meets the weld-on connector. The straight-wall section of the connector is used to eliminate all bending to the CT heat-affected zone.
- "Chill blocks" aid in limiting the heat-affected zone from welding operations. The connector’s straight-wall OD exceeds the ID of the CT by several thousands of an inch. The weld-on connection is therefore inserted after the CT is preheated in preparation for welding operations.
The well-control stack system is a critical part of the CT unit pressure containment package and is composed of a stripper assembly and hydraulically operated rams, which perform the functions described next.
For typical well-intervention service, the four ram compartments are equipped (from top down) with blind rams, tubing shear rams, slip rams, and pipe rams. (Fig. 16.13). The blind rams are used to seal the wellbore off at the surface when well control is lost. Sealing of the blind rams occurs when the elastomer elements in the rams are compressed against each other. For the blind rams to work properly, the tubing or other obstructions across the ram bonnets must be removed.
The tubing shear rams are used to mechanically break the CT in the event the pipe gets stuck within the well-control stack or whenever it is required to cut the tube and remove the surface equipment from the well. As the shearing blades are closed onto the CT, the forces imparted will mechanically yield the body of the tube to failure. The cut is deformed and typically must be dressed to return to the proper geometry.
The slip rams should be equipped with bidirectional teeth, which, when activated, secure against the tubing and support the weight of the CT and BHA below. An additional utility of the slip rams is the ability to close onto the tube and secure movement in the event that well-pressure risks blowing the tubing out of the borehole. The slip rams are outfitted with guide sleeves that properly center the CT into the grooved recesses of the ram body as the slips are being closed.
The pipe rams are equipped with elastomer seals preformed to the specified OD size of CT in service. When closed against the CT, the pipe rams are used to isolate the wellbore annulus pressure below the rams. These rams are also outfitted with guide sleeves that properly center the CT into the preformed recess as the rams are being closed.
Typically, a kill-line flange inlet is positioned directly below the tubing shear ram set and above the slip ram set in the well-control stack. Two valves rated to the maximum allowable working pressure (MAWP) of the well-control stack are mounted onto the kill-line flange, which typically includes a high-pressure check valve installed in the high-pressure chicksan line run to the high-pressure pump. The practice of taking returns through the kill line is not recommended because it exposes the lower sets of rams and bonnets to accumulation of solids, debris, and other return fluids that may adversely affect the performance of the rams.
On all well-intervention services that require the circulation of wellbore returns to surface (solids, debris, spent acid, etc.), the use of a separate "flow-tee" or "flow-cross" mounted directly below the primary well-control stack rams is recommended. This flow-tee or flow-cross connection should be equipped with a minimum of two high-pressure isolation valves and rated to the same working pressure and NACE classification as the well-control stack rams.
On most well-control stack assemblies, the blind ram and pipe ram compartments are equipped with ports that, when activated, allow pressure to equalize within the ram body. This allows for differential pressure to be equalized across the ram compartments before opening the rams.
The union positioned at the top of the well-control ram stack typically connects to the stripper assembly located on the bottom of the injector. The recommended connection at the bottom of the well-control ram stack is an integral high-pressure flange assembly or another suitable metal-to-metal seal connection. The pressure rating and arrangement of the well-control stack components for a given CT operation will typically depend upon the type of application employed and the maximum anticipated surface pressure in the well. When preparing for a CT well-intervention or drilling operation, the well-control equipment must be in compliance with the local regulatory authority and should reference applicable industry best practices [e.g., American Petroleum Inst. (API), Intl. Organization for Standardization (ISO), etc.].
CT is an electric-welded tube manufactured with one longitudinal seam formed by high-frequency induction welding without the addition of filler metal. The first step in the typical CT manufacturing process involves the acquisition of steel stock supplied in 40- to 48-in.-wide sheets that are wrapped onto a "master coil" to a nominal weight of approximately 40,000 lbm. As a result, the lengths of sheet steel will vary depending upon the wall thickness. For example, a 40-in.-wide sheet of steel having a wall thickness of 0.109 in. rolled to a length of 2,700 ft will weigh approximately 40,000 lbm. If the 40-in.-wide sheet steel has a wall thickness of 0.156 in., a 40,000 lbm-master coil will have a length of approximately 1,900 ft.
When the diameter of the CT is selected, the sheet steel on the master coil is "slit" into a continuous strip of a specific width to form the circumference of the specified tube. The flat skelp is then welded to another segment of skelp to form a continuous length of steel. The welded area is dressed off smooth, cleaned, and then x-ray inspected to ensure that the weld is free from defects. Once a sufficient length of the continuous skelp steel is rolled onto the skelp take-up reel, the tube milling process can begin.
The skelp is then run through a series of roller dies that mechanically work the flat steel into the shape of a tube. At a point immediately ahead of the last set of forming rollers, the edges of the tube walls are positioned very close to each other. These edges are then joined together by an electric welding process described as "high-frequency induction" (HFI) welding. The HFI coil generates the heat for welding by the resistance to flow of electric current. As the tube is run through the high-frequency induction coil positioned inches ahead of the forming rollers, the edges of the walls are heated to the temperature needed to create the seam weld when pressed together within the last set of forming rollers.
The weld flash exposed on the outside of the tube is removed, and the welded seam is annealed. The tube is allowed to cool in air and then within a liquid bath before passing through a nondestructive inspection station to inspect the tube body. The inspection is typically performed with an eddy-current device that creates a magnetic field around the tube body and looks for distortions in the field created by surface defects in the tube body.
The manufacturing process continues as the tube is run through a sizing mill that slightly reduces the diameter after welding and works the tubing to the required OD and roundness tolerances. At this time, the tubing undergoes full-body heat treatment using induction coils. The purpose of the heat treatment is to stress-relieve the entire tube, increasing the ductility of the steel. The tube is allowed to cool, first gradually in air and then within a liquid bath. This process results in the development of pearlite and ferrite grain sizes within the steel microstructure. The final product is a high-strength CT string with ductility and physical properties appropriate for the specified yield range. The tube is then spooled onto a steel or wooden take-up reel and subjected to a hydrostatic pressure test using water treated with corrosion inhibitors.
Alternative CT manufacturing processes may require that a string be constructed by butt-welding sections of tube together. The tube-to-tube welding technique may be performed using TIG or MIG welding practices, and each weld should be inspected using radiographic inspection (x-ray) or ultrasonic inspection to evaluate the quality of the weld. Note that the exterior surface of the tube-to-tube weld may or may not be dressed off and that the weld bead on the ID surface is not disturbed in any way. The string of tubing is then spooled onto the service reel or shipping reel as required.
All manufactured spools of CT are given a unique identification number that is assigned at the time of manufacture. Documentation for each spool of CT should include the identification number, OD of the tubing, material grade, wall thickness(es), weld positions, and total length. A spool of CT may be manufactured from one heat or a combination of heats that are selected according to a documented procedure provided by the manufacturer. However, the steel used to fabricate the string must have a uniform material yield strength throughout. The manufacturer should maintain traceability of the CT product throughout the manufacturing and testing process. The requirements of the purchaser often include traceability to the heat of steel.
Tapered Wall Thickness String Design
In general, tapered CT strings can be manufactured by changing the wall thickness of the tubing within the length of a spool while maintaining a constant OD. The changes in wall thickness along the string length are intended to increase the performance properties of the CT in the selected sections. The construction of a tapered CT string may be achieved in one of the following ways:
- A continuously milled string incorporating multiple single-wall-thickness skelp segments joined using skelp-end welds.
- A continuously milled string incorporating single-wall-thickness skelp segments with continuously tapered skelp segments joined using skelp-end welds.
- Continuously milled, single-wall-thickness CT segments joined to another finished tube segment of a different wall thickness using the tube-to-tube welding process.
Continuously-tapered skelp is milled having a specified wall thickness at the leading end of the steel skelp, progressively increasing in wall thickness along the length of the skelp to a second specified wall thickness at the trailing end of the skelp.
The construction of tapered CT strings conforms to the previously described manufacturing processes. Although tube segments of different wall thickness can be assembled within the string construction, it is critical that all of the segments have a uniform material yield strength. The change in specified wall thickness, t, between the adjoining CT segments should not exceed the following specified values:
- 0.008 in. where the specified wall thickness of the thicker of the adjoining segments is less than 0.110 in.
- 0.020 in. where the specified wall thickness of the thicker of the adjoining segments is between 0.110 and 0.223 in.
- 0.031 in. where the specified wall thickness of the thicker of the adjoining segments is 0.224 in. and greater.
For tapered-wall string designs, the transition point may be defined as the points along the string having a change in the specified wall thickness. For single-wall-thickness segments, the transition points are defined as the points where the different specified wall thicknesses are mechanically joined together. For continuously tapered skelp segments, the transition points are defined as the points where the ramping of the skelp occurs. The typical design criteria for selecting transition points (desired lengths of specified-wall thickness segments) within the string includes weight and overpull loading, wellbore condition, and combined pressure loading. Note that the overpull load rating increases for the adjoining tube segment with an increased wall thickness. The effect of changes in overpull load should be applied across the entire tapered string to ensure that a given overpull load does not exceed the limits of any other tube segment within the string. Therefore, the maximum length of each CT wall thickness segment should be evaluated using overpull and combined pressure loading to confirm that the stress applied to the CT string below any point on the segment does not exceed the triaxial stress load at that point for the given safety factor.
CT well intervention and drilling operations require that the continuous-length tube be subjected to repeated deployment and retrieval cycles during its working life. The tubing stored on a service reel is deployed into the wellbore to the designated depth and then retrieved back onto the service reel. The working life of the CT may be defined as the duration of service for the continuous-tubing string when subjected to the following conditions: bend-cycle fatigue, internal pressure loading, applied axial loading, corrosion, and mechanical damage.
All of the aforementioned items act on the tube body to some degree during any CT service and contribute to the eventual mechanical failure of the tubing. To ensure safe and reliable well intervention and drilling operations, the user must understand the unique behavior of CT to minimize the possibility of tubing failure. Numerous decisions must be made throughout the working life of a CT string to maximize the remaining life. From this approach, the decision to retire the tubing must be made on the basis of current tube conditions, service history, and the anticipated service loading.
Description of Fatigue
Fatigue is generally considered to be the single major factor in determining the working life of CT. The deployment and retrieval of the continuous-length tubing string require that the tube be subjected to repeated bending and straightening events, commonly referred to as "bend-cycling." The amount of strain imposed upon the tube body during the bend-cycling process is considered to be enormous, in many cases on the order of 2 to 3%. When subjecting the CT to this type of fatigue cycling, the stress and/or strain fluctuations to failure may be estimated using conventional axial fatigue life prediction approaches.
However, when the bend-cycling process is coupled with internal tube pressure loading, conventional multiaxial life prediction approaches cannot accurately predict CT behavior. Numerous tests performed have confirmed the fact that bend-cycling CT with internal pressure loading dramatically reduces the fatigue life of the tube when compared to the cycle life of unpressurized tubing. This happens despite the fact that the tangential (hoop) stresses imposed by typical "high" pressures in CT service are on the order of only 50 to 60% of nominal yield strength. However, when combined with fluctuating axial strain ranges on the order of 2 to 3%, significant cyclic ratcheting (ballooning) occurs, and fatigue damage development is accelerated. Outside of the CT industry, there are essentially no other applications involving steel alloys in which cyclic loading of this magnitude is intentionally imposed and expected to survive the prescribed service.
To better understand the abuse imposed upon CT during normal service operations, a brief review of the relationship between stress and strain in high-strength low-alloy (HSLA) steel is given next. Fig. 16.14 is a typical stress-strain curve for HSLA steels. The axial stress, α, is plotted along the Y-axis, and the corresponding axial strain, ε, is plotted along the X-axis. As stress is applied to the steel material, a corresponding strain develops as defined by Hooke’s law that states that the amount of stress is equal to the amount of strain, multiplied by the modulus of elasticity of the material. This relationship is graphically represented as the line segment O-A in Fig. 16.14, where the modulus of elasticity defines the slope. The stress at Point A is referred to as the "proportionality limit," also referred to as the "elastic limit." As long as the stress levels within the steel are held below the elastic limit, the strains are also considered to be elastic, and no permanent deformation will occur.
However, as increased stress is applied to the steel, the elastic limit is exceeded and will reach Point B, which is termed the "yield point." The yield point defines the yield strength, Sy, or the stress that causes the initiation of plastic strain in the material. Once the yield point is reached, permanent deformation occurs, and plastic strain is developed as the material begins to elongate permanently. To determine the yield strength of alloy steel materials in a consistent manner, a standard 0.2% offset plastic strain value was adopted to locate the yield point on the stress-strain curve. This is shown as the dotted line "AB-X.2%." Loading into the plastic region to Point P, followed by unloading to Point O, Line P-O is usually believed to also define the slope of the modulus of elasticity and intersect the X-axis to represent the amount of plastic strain resulting from the deformation. However, it has been shown that plastic deformation tends to reduce the modulus of the elastic unloading curves by as much as 15 to 20% for loading typically seen in CT well intervention and drilling services.
By applying additional stress, we will reach Point D, which is referred to as the ultimate tensile strength of the material. Once Point D is reached, the material will suffer a separation failure.
The amount of stress experienced by the HSLA material can be fully appreciated when considering the degree of bending the tube must undergo during conventional service activities. The radii of typical CT service reels and tubing guide arches are significantly less than the yield radius of curvature (RY) for any given size of CT listed. When the tubing is bent and wound onto the service reel or storage spool, the HSLA steel is yielded and becomes plastically deformed. This plastic deformation event is similar to the graphical illustration seen in Fig. 16.14 as Curve O-P. When the amount of stress applied to the tubing is relaxed, the strain remaining is permanent and has a value represented by the extension of Line P-O ′.
The fatigue imparted to the CT material during normal service operations is the result of bending the continuous-length tubing beyond its elastic limit and forcing the material into plastic deformation. Fig. 16.15 illustrates the typical operating sequence whereby bend cycles are imposed on the CT during deployment and retrieval. For this illustration, the initial state of the tubing will be in the "as wrapped" condition on the service reel. The bend event sequence is described next.
- The tubing is pulled off the service reel by the injector. The hydraulic motor on the reel provides resistance to the pull of the injector, placing the tubing in tension. The tension applied is typically limited to the amount needed to bend the tubing over the tubing guide arch and maintain control of the tube during deployment. Therefore, the tubing is straightened out somewhat, constituting the first bend event.
- Once the CT reaches the tubing guide arch, the tubing is bent over the prescribed radius. This event constitutes the second bend event experienced during deployment.
- As the tubing travels over the tubing guide arch, the tubing is returned to the straightened orientation before entering the gripper blocks in the injector (third bending event).
These three bending and straightening events are repeated in reverse as the tubing is extracted from the well, resulting in a total of six bending events commonly described as a "trip." In relative terms, the smaller the bending radius, the larger the value of bending strain induced into the tube segment. This is seen as the more severe bending strains imposed when the CT is cycled over the service reel, as compared to the less severe bending strains imposed when bending occurs over the tubing guide arch. Therefore, during a complete service trip, the tubing will experience two bending events inducing relatively higher bending strain and four bending events inducing relatively lower bending strain. Note that the pairing of two bending events with equivalent strain magnitudes is defined as a "bend cycle." Therefore, within each CT service trip, there are two relatively low-strain bend cycles and one relatively high-strain bend cycle.
In general, for CT well-intervention and drilling operations, the number of trips assigned to the tubing is not the same over the entire length of the tubing string. For example, during routine service work, it is common to periodically stop deployment and reverse the motion of the CT string, retrieving a prescribed length of tubing back out of the wellbore to check weight and drag of the tubing. The intermediate segments of the tubing string, which were subjected to these "drag checks," will have a greater number of trips allocated than that which is allocated to the remainder of the tubing string. In addition, where a prescribed service program requires repeated bend cycling over a specified segment of the tubing string, this segment will have an accumulation of fatigue damage that is significantly greater than the fatigue damage subjected to the remainder of the tubing-string length.
The discussion on CT bend cycling makes apparent that most of the material fatigue occurs at the reel and tubing guide arch, with very little, if any, within the wellbore. In CT services, the plastic deformation of the tube material that results in the cumulative damage is defined as "ultralow cycle fatigue." The loading in ultralow cycle fatigue is plastic, and failure of the material generally occurs within 2,000 bend cycles.
A consequence of ultralow cycle fatigue in CT operations is the eventual formation of microcracks in the tube body. With continued bend cycling, the cracks propagate through the tubing wall until the crack establishes full penetration from one side of the wall to the other. Once the crack has fully translated through the tube body wall, pressure integrity is lost. Typically, the initial size of the crack is very small, making detection of this type of body damage very difficult. Furthermore, cracks tend to initiate on the inner wall of the tubing, despite the fact that the bending strain is greater on the outer surface. In conditions in which high internal pressure is present, the hoop stress may cause the crack to instantaneously propagate along the circumference of the tube. In this condition, a major transverse crack will occur and may result in the mechanical separation of the tubing. For this reason, crack initiation is typically the criterion used to define "failure" within a CT section.
Loss of pressure integrity in any condition makes the CT string unfit for service. At present, the fatigue condition of a segment of tubing with an unknown bending history cannot be accurately measured nondestructively. Because fatigue appears to be a statistical phenomenon, variations can be expected in observed fatigue life for any sample, regardless of comparable bending history records.
Various types of bend-cycle fatigue test machines (Fig. 16.16) have been developed in an attempt to simulate the wellsite bendcycling of CT over a constant radius with internal pressure loading. These bend-cycle fatigue fixtures generate a statistically significant quantity of fatigue data and provide a means to estimate bend-cycle fatigue over a wide range of test conditions.
Numerous analyses of the trends recorded from the ever-increasing volumes of CT fatigue tests suggest that bend-cycle events imposed onto a given tubing specimen with high internal pressure (causing hoop stresses on the order of 30 to 60% of the yield strength) accumulate fatigue damage at a much greater rate than bendcycles imposed with low internal pressure loading. In addition, the magnitude of fatigue damage realized from a given bend-cycle event cannot be applied to working-life predictions in a linear fashion. Evidence from the volume of testing suggests that a given bend-cycle load applied later in the tube working life may cause greater fatigue damage than the equivalent bend-cycle load applied earlier in the tube working life. The bend-cycle fatigue data obtained from the test fixtures has also provided insights into several other areas of CT service behavior. These items are discussed next.
"Cyclic Softening" of CT Material
One significant consequence of repeated bend cycling of CT material is a phenomenon referred to as "cyclic softening," which results in a reduction in material yield strength as the CT performs its prescribed service. The magnitude of the cyclic softening realized in CT materials can be directly related to the amount of material strain imposed during service.
Standard strain-controlled, low-cycle fatigue testing is commonly performed on axial-test coupons of a specified material to evaluate its behavior when subjected to fluctuating strain conditions. These tests attempt to simulate the magnitude and intensity of the strain fluctuations anticipated during the prescribed service and are used to help predict the fatigue strength of the material at the test conditions. For steel CT products, similar types of stress-cycle tests have been performed to provide insight into fatigue life and performance when subjected to multiaxial plastic deformation events.
The strain-controlled fatigue-testing process is illustrated in Fig. 16.17, in which the CT material is cut into the designated test coupon geometry and installed into a fatigue test machine that subjects the material specimen to strain-controlled, axial load cycles between a maximum and minimum strain, γmax and γmin . In these tests, cyclic softening was observed because the peak stresses 3, 5, and 7 continually diminish from the initial peak at Point 1.
The stress/strain diagram shown in Fig. 16.17 illustrates the hysteresis effect observed during the strain-controlled axial-stress load-cycle tests. If plotted in terms of stress vs. time as shown schematically in Fig. 16.18, the coupons exhibit a transient stress response, in which the recorded peak stress values diminish incrementally relative to the previous value. This cyclic softening corresponds to a reduction in the material yield strength. Eventually, stable hysteresis loops form, reaching a condition described as "cyclic stabilization" of the material. In the conventional low-cycle fatigue tests conducted on the material coupons, cyclic stabilization appears to occur when the accumulated fatigue damage is within the range of 20 to 40% of expended cycle life.
The material strain imposed during bend cycling of full-body CT specimens is considered to be at the upper limit of the low-cycle fatigue regime, especially because this bending can combine with pressure to cause lives on the order of fewer than 20 cycles. As previously discussed, the category that best describes the behavior of CT bend-cycling is that of "ultralow cycle fatigue." At the strain levels realized during full-body CT bendcycling over typical bend radii, the bulk of the material softening can be seen within the first few load cycles, with continued material softening occurring over the remainder of the tube cycle life. For full-body CT bendcycling, truly stable stress responses may not be achieved, and cyclic stabilization may never be truly realized.
The importance of this discussion becomes apparent when considering that the strain range experienced in CT services varies significantly from point to point around the circumference of the tube body. At positions between the points of maximum stress (i.e., the top and bottom of the tube body) and the neutral axis, the intermediate strain ranges and transient material softening will most likely occur throughout the entire working life of the tube. As a result, material strength and performance properties can be expected to vary relative to the position around the circumference of the tube body. In some CT material samples tested, the reduction in yield strength was found to be as much as 10 to 20% of the parent material yield strength.
In actual service, the neutral bending axis on the CT when deployed into the wellbore will most likely be in a different orientation on the tube circumference from when it is retrieved from the wellbore. This change in neutral bending axis may be the result of relaxation of residual stresses in the tube when axial tensile forces are applied during deployment into the well or because of some other phenomena. During the extraction process, the tubing is retrieved into the injector gripper blocks with the previous neutral axis rotated slightly off alignment. Once the tube is secured into its "new" orientation relative to the gripper blocks, a new neutral axis will be defined as the tubing is bent over the tubing guide arch. This repositioning of the neutral axis during well intervention and drilling operations is believed to distribute the high-strain bend cycles around the circumference, creating a more uniform accumulation of fatigue damage within the tube.
When subjected to plastic deformation because of bendcycling with internal-pressure loading, the diameter of the CT tends to grow or "balloon." Even when the internal pressure loading is well below the yielding stress of the material, the tube body is subjected to hoop and radial stresses that cause the material to grow macroscopically in diameter and to decrease in wall thickness (Fig. 16.19). In uncontrolled fatigue tests, diametral growth exceeding 30% has been observed. The primary factors influencing diametral growth are material properties, bend radius, internal-pressure loading, tube OD, and tube wall thickness.
One major concern for diametral growth is the interaction with surface handling and pressure-control equipment. The injector gripper block loading on CT usually has an impact on the tube geometry, and the effect tends to vary according to the magnitude of gripper block normal force, block geometry and wear, and CT geometry, internal pressure, and material type. Most conventional counter-rotating chain injectors have gripper blocks that are machined to fit the OD of the specified size of tubing. When CT experiences diametral growth, the increase in tube size creates a nonsymmetrical loading condition, concentrating the normal force load at contact points on the edges of the gripper block. These focused stress concentrations induce additional damage into the tube body and result in added tube deformation.
Some injector manufacturers have made adjustments to the design of the gripper blocks in an attempt to minimize this additional damage to the tube. The segmented-type and "variable"-type gripper-block designs appear to better accommodate increases in tube body growth. However, as the diametral growth of the tube increases, the two-point contact loading of the gripper blocks will induce lines of concentrated stress on the tube body. With this focused stress concentration, the gripper blocks will impart greater damage onto the tube at the normal force loads typical for properly fitted gripper blocks.
Another concern for diametral growth relates to the interaction with the pressure-control equipment. The stripper assembly contains brass bushings that are used to prevent extrusion of the elastomeric elements. These bushings have an internal diameter that is slightly larger than the specified OD of the tubing. If the actual CT diameter on any axis reaches or exceeds the internal diameter of the brass bushings, the CT will bind up within the bushings, resulting in surface damage to the tubing. Once this condition is reached, the CT may no longer pass through the stripper. To prevent this situation, limitations should be placed on the maximum allowable CT diameter.
The recommended method of defining maximum allowable growth of CT is "absolute diameter," at which the CT is retired from service when the diameter reaches a given value greater than its specified dimension. The limit typically used is 0.050 in. and can be considered valid for all CT sizes when the aforementioned type of stripper apparatus is used.
Observations of bend-cycle fatigue testing directly relating to diametral growth in CT are listed next.
- The growth rate of the OD increases with increasing internal-pressure loading.
- The diametral growth of larger-diameter CT as a percentage of specified diameter is greater than that of smaller-diameter CT.
- CT specimens with higher material-yield-strength demonstrate less diametral growth than lower material-yield-strength specimens.
- Mechanical limitations of surface handling and pressure-control equipment tolerances for allowable diametral growth restrict the effective working life of CT in high-pressure service to only a fraction of the projected fatigue life.
Differential Wall Thinning
As a consequence of diametral growth, CT experiences differential wall thinning. If we assume that the cross-sectional area of the tube body is constant, then as the diameter grows, the redistribution of material causes the wall of the tube to get thinner. The concept of differential thinning is also illustrated in Fig. 16.19. As the tube is bend cycled about the neutral axis, the top and bottom of the tube are subjected to the highest stress concentrations and subsequently experience the greatest amount of thinning. Note that the wall thickness at the neutral axis (where no bending stress occurs) remains at the initial wall thickness. Therefore, the wall-thinning process is not uniform. Although the severe ballooning and localized wall-thickness reduction are typically observed on samples tested in the laboratory, such gross geometric changes are rarely seen in the field. This is because of factors such as tubing rotation (which causes the wall thinning to occur more uniformly) and the ID of the stripper brass bushings (which limit the use of tubing having excessive diametral growth).
Although extensive diametral growth and wall thinning are observed in the lab, empirical data obtained from extensive full-scale field cycle testing conducted by Walker et al. has shown that for a 3% increase in tube body diameter, the wall thickness tends to decrease approximately 7.5%, resulting in a loss of burst and collapse pressure rating of as much as 10%.
The mechanics behind the phenomena of diametral growth and wall thinning is referred to as transverse cyclic ratcheting, whereby material deforms permanently with each cycle of loading in directions transverse to the major fluctuating load directions. Conventional incremental plasticity theory has been shown to overpredict cyclic ratcheting in the typical CT loading regime. Therefore, refined plasticity models have been developed and used successfully to predict the behavior of CT samples in the lab and the field.
Tubing Length Extension
As a result of the stress/strain response exhibited by CT material (as seen in Figs. 16.14 and 16.17), the tubing enters the well with a significant distribution of residual stress. The residual stresses vary from tension on one side to compression on the other, at magnitudes equal to the material’s cyclic yield strength. This residual stress profile has a first-order influence on the load- deflection behavior of the tubing and tends to induce secondary deformation mechanisms which contribute to permanent increases in tube length. This condition is commonly described as "elongation," but should not be confused with the API definition of elongation, which represents the change in specimen gauge length once ultimate tensile strength is exceeded during a destructive tensile test. To avoid confusion, the term "extension" is used in this text to refer to the observed permanent increase in CT length resulting from realignment of residual stresses where axial force loading is applied.
As with diametral growth, extension occurs despite the fact that the applied axial stress (in terms of load over cross-sectional area) is maintained to a value substantially below the material yield stress. The investigation of extension was prompted by observations in CTD operations where the BHA could not return to maximum deployed depth after the string was retrieved to surface and then redeployed to depth (referenced by painted points on the reel). The reported "stack-out" depth was several feet higher than the previously reached depth, in excess of calculated corrections for tube helix reorientation within the well. Extraction and subsequent redeployment of this CT string found the stack-out depth several feet higher than the previous "stack-out" depth, prompting concern for accurate depth control. Other onsite observations found that the amount of permanent tube length increase was greater for new tubing strings as compared to "seasoned" tubing strings.
Detailed studies have documented that extension occurs during high-pressure/constant-pressure bend cycling because of the constant axial stress caused by pressure loading on the end caps. When higher tensile loads are applied to the tube immediately after bend cycling has occurred, the section of the tube wall with residual tensile stresses equal to the yield strength cannot sustain any more axial stress. Therefore, the residual stresses within the tube body are redistributed to reach equilibrium, resulting in a permanent extension of tube length. The intensity of the residual stress distribution in the tube body is directly related to the imposed strain, which suggests that the amount of extension for a given axial load increases as the bend radius is reduced. Therefore, the location of maximum tube-length extension within the string will typically be in the region where the smallest bend radii and highest axial tensile loads are imposed. This region of the tubing string is typically located near the core diameter of the service reel (reference end), with high axial loading resulting from the weight of the tubing suspended within the wellbore.
Multiaxial plasticity models have been developed to compute stresses and strains induced by the surface handling equipment (tubing guide arch and service reel), internal pressure loading, and axial loads experienced by the tube. These complex and sophisticated algorithms handle highly nonproportional loading and must accommodate changes within the tube cross section as well as axially along the entire length of the string. Therefore, the accuracy of the plasticity model predictions depends upon the proper mapping of imposed strains throughout the service life of the tubing string.
The bend-cycle fatigue life of a CT string is also sensitive to surface damage, such as scars, scratches, gouges and dents. These types of mechanical damage serve as localized stress-strain concentrations where repeated bend cycling can cause cracks to develop in the tube body. Testing was performed by Quality Tubing to quantify the reduction in bend-cycle fatigue life for 1.750-in.-OD, 0.134-in.-wall-thickness tube samples, with and without surface damage present. The 80-ksi-yield tubing samples were subjected to bend-cycle testing over an equivalent 72-in. bend radius with a 3,000-psig internal pressure. A baseline test was performed with an undamaged tube and survived approximately 725 bend cycles before loss of internal pressure (failure). Two samples were prepared with transverse notches cut to an approximate depth of 10% of wall thickness. One sample located the notch across the longitudinal weld seam, with the other sample locating the notch 180° from the longitudinal weld seam. Both of these samples survived approximately 120 bend cycles, yielding an 83% reduction in fatigue cycle life relative to baseline. Two additional samples were prepared with the 10% wall thickness notches located at the same positions on each tube body, but these notches were ground out and polished smooth before being subjected to bend cycling. By removing the transverse notches, the tube samples survived approximately 590 bend cycles, yielding a 19% reduction in fatigue-cycle life relative to baseline. With the removal of the surface damage, the bend-cycle fatigue life increased from 120 to 590 cycles, a 390% improvement in survival life.
A recent study has noted that not only is the geometry of the defect important (length, width, depth and shape of the defect), but also the mechanism by which the defect was imposed into the tubing. For instance, ball-nosed end mills were used to cut hemispherical defects into a set of CT samples. In another set of tubes, defects with identical geometries were imposed by pressing hard balls into the surface, rather than removing material by machining. When tested under identical constant amplitude bend cycling, the samples with the milled defects reduced the life of the samples by as much as 60% (relative to defect-free baseline samples), while the impressed defects caused virtually no life reduction.
Significant research is currently under way to quantify the influence of defects on CT life, as well as the effectiveness of repair strategies, such as simple removal by surface grinding. The research currently under way is addressing the influence of loading parameters (bending radii, pressure, tube geometry) and material grade.
An important component of the research is the incorporation of CT inspection technology. The most prevalent CT inspection technique is magnetic flux leakage. Although this technique has proven effective in detecting the presence of a flaw, existing technology provides no information about the severity of the flaw. The research currently under way has made important steps toward extracting quantitative information about the geometry of the defect, as well as its influence on fatigue. Over time, a continually growing database will facilitate the development of refined signal-processing algorithms that provide important feedback directly from magnetic flux leakage results.
An additional phenomenon that occurs as a result of CT bend-cycle fatigue is described as "surface rippling." It is common to find "ripples" developing on the top surface of the CT (relative to the neutral axis) when subjected to bend cycling in combination with high internal-pressure loading. On many samples examined, the period of the ripple formation has typically been observed to be approximately twice the tube diameter. This condition has been observed to occur both in field service operations and with tube specimens tested in fatigue cycle fixtures. This consequence of bend cycling is attributed to the fact that CT does not yield continuously along its length as it is deformed. What occurs is more of a buckling phenomenon, where the outer fibers simply lengthen to a point where they buckle in compression when straightened and never quite return to a perfectly straight condition upon rewrapping. Rippling typically occurs relatively late in the fatigue life of the tubing. Therefore, if surface rippling is observed in the CT, it is recommended that the tube be immediately withdrawn from service.
Commonly Used Bend-Cycle Fatigue Derating Methods
Over the years, attempts have been made to track the working history of CT strings in service to maximize the service utility of the tube while minimizing fatigue failures. As a result, three commonly used methodologies for predicting the fatigue condition of the CT were developed.
The "Running Feet" Method
A relatively simplistic approach used to predict the working life of CT is commonly described as the "running-feet" method, in which the footage of tubing deployed into a wellbore is recorded for each job performed. This deployed footage is then added to the existing record of footage deployed in service for any given string. Depending upon the service environment, type of commonly performed services, and local field history, the CT string is retired when the total number of running feet reaches a predetermined amount.
The running-feet method offers the service vendor relative simplicity of use, requiring only that the maximum depth of CT deployed into the wellbore be recorded. However, there are numerous limitations of this fatigue-tracking method as a reliable means of determining ultimate working life of a CT service string. Several limitations are described next.
- The value of maximum footage to retirement for any CT string is based on the service vendor’s previous experience with the same type of tubing, performing wellsite operations with similar well depths and types of service. In this method, there is generally no consideration given to duration of corrosive services performed or effects of exposure to atmospheric corrosion.
- The running-feet method typically focuses on the specified OD of the CT string in service, with minimal consideration for tubing wall thickness, tube material type, and yield strength.
- The running-feet method does not have a means of accounting for variations in tubing guide arch radius, service reel core radius, internal pressure loading, or identification of specific tube segments where additional bending cycles are applied.
- The working life-derating method used in the running-feet approach cannot be extended to different tubing sizes or operating conditions. This method can be used only where working history for the specific tube material, geometry, and surface handling equipment has been gathered and analyzed to yield the prescribed maximum running-feet value.
The "Trip" or "Empirical" Method
A natural extension of the running-feet fatigue derating approach can be found in what is commonly described as the "trip" method. In the trip method, numerous improvements have been incorporated to the running-feet approach, providing greater reliability in predicting working life of the CT string. One major improvement entails evaluating the CT string as a series of partitioned segment lengths that can range from 100 to 500 ft long. This approach applies a greater sensitivity to the working life analysis by identifying sections of the CT that are subjected to more bending cycles than others during a specified service. The number of trips over the service reel and tubing guide arch for each discrete segment can then be tracked and recorded. When employing this method, a reduction in the length of the section increment increases the accuracy of the bend-cycle record. This type of analysis makes it possible to identify the CT string segments that have experienced the most bend-cycle fatigue damage.
Another major improvement with the trip method incorporates the effects of internal-pressure loading. For a given tubing guide arch and service reel core radius, CT bend-cycle fatigue life decreases significantly with increased internal pressure loading. The evolution of the trip method incorporated extensive CT bend-cycle fatigue testing using full-scale service equipment (injector, tubing guide arch, and service reel) and varying amounts of internal-pressure loading. In this scenario, numerous bend-cycle fatigue tests are performed for a given size of CT at specified amounts of internal pressure.
Data recorded in these tests were initially used to create a database for statistical projection of CT working life. From these types of tests, a segment of the CT string that had accumulated a considerable amount of bend-cycle fatigue damage can be identified, thereby providing the user with options for removing the heavily damaged segment of tubing from service.
As more full-scale fatigue cycle tests were performed, trends in CT fatigue were identified for various pipe sizes, tube geometry, and internal-pressure load conditions. Analysis of these trends provided the service vendor with the ability to "curve-fit" the data points and derive empirical coefficients that were incorporated into conventional multiaxial fatigue-life prediction approaches, yielding the early CT fatigue prediction models.
The aforementioned improvements in fatigue damage tracking realized by the trip method offer enhanced accounting of operating conditions present when the bend-cycling events occurred, along with a greater sensitivity of identifying tubing-string segments subjected to bend cycling. The limitations with the trip method of empirical modeling include:
- The derived empirical coefficients for fatigue-damage are generally different for each combination of CT material, OD, wall thickness, and bending radius.
- Bend-cycle testing using full-scale equipment is required to obtain the fatigue coefficients experimentally (expensive and time consuming).
- The trip method does not incorporate tube body damage incurred as a result of well-servicing operations. This type of damage includes exterior tube body wear, interior and exterior corrosion (atmospheric and industrial), or nicks, cuts, or scarring resulting from contact with surface handling equipment.
- The test data obtained from fatigue bend-cycling machines is usually at a constant internal pressure. In well-servicing operations in which fluid pumping is required, the amount of internal pressure present in the CT varies along the entire length of the string. Therefore, as the tubing is deployed and retrieved, each section of the string has a different internal pressure at the point where bend cycling occurs.
- The varying internal-pressure loading at the point of bend cycling requires a complicated record and prediction procedure to provide a realistic working-life prediction. This requires investment in surface recording instrumentation and sophisticated data collection systems, such as portable computers, as well as complicated tubing management software systems for tracking and maintaining up-to-date records of the compiled tubing working life.
The "Theoretical" Method
A third method for predicting bend-cycle fatigue incorporates the same approach developed in the "trip/empirical" method for estimating the bend-straighten-pressure history for each segment of tubing along a string. However, a theoretical model based on the fundamental principles of mechanics and fatigue is used to estimate the stress, strain, and fatigue behavior of each section in the string.
The theoretical modeling of fatigue typically involves use of "plasticity" algorithms and "damage" algorithms. The plasticity algorithm is used to estimate the stress and strain history of the CT material as it is bent or straightened over a particular bending radius at a particular internal pressure. The damage algorithm uses the concept of cumulative fatigue damage to quantify the reduction in working tube life caused by each bend or straighten event. The approach is very mechanistic, for instance, taking into account the fact that the pressure during each bending or straightening event can be different. The fatigue damage computed for each event is summed throughout life and is usually expressed as a percentage of the predicted working life. Since each section of tubing along the length of a string can endure differing bend-straighten-pressure histories, the damage profile can (and usually does) vary along the length of a typical working string.
The plasticity algorithm in the theoretical model requires input of the specific material properties. These properties come from two types of testing. First, the aforementioned low-cycle fatigue testing conducted on axial coupons, and second, full-scale data typically taken from a CT fatigue testing fixture, or from full-scale equipment.
The low-cycle fatigue data are used to compute both elastic material properties and the cyclic stress-strain curve for the particular CT alloy. Although these properties are generated for axial loading only, they serve as the "constitutive relations" (i.e., the relations between stress and strain) for a multiaxial plasticity algorithm, which is capable of estimating the history of all stress and strain components (axial, hoop and radial) in the tubing. Since the plastic deformation caused by bend cycling is so severe, it was determined that conventional plasticity theory was inadequate to describe the behavior of CT accurately. Conventional theories tended to overpredict phenomena such as ballooning and wall thickness reduction. To overcome this, new theories were developed specifically for CT. These models are effectively "tuned" to specific alloys by collecting data from constant pressure bend-cycling tests conducted on laboratory testing fixtures (although data from full-scale equipment can also be utilized) to supplement the low-cycle fatigue data. The empirical parameters derived from these test results cause the algorithms to do an excellent job of estimating ballooning and wall thickness reduction, as well as fatigue under complex loading histories.
The use of empirically derived data in this approach assures that the model can be mapped back to realistic behavior exhibited by real CT sections. In reality, CT mechanical properties must be allowed to vary within a particular grade. For this reason, it is important to collect as many experimental data points as possible to characterize the scatter caused by typical material variation. The greater the number of experimental data points, the stronger the statistical validity of the model.
The advantages to the use of theoretical models include greater accuracy of bend-cycle fatigue life prediction with the capability to predict fatigue life for variable loading conditions. The use of such an algorithm in the field is dependent upon the use of a reliable string-management routine that keeps track of the depth and pressure history of the string throughout its use and is capable of computing the bend-straighten-pressure history for each section of tubing, based on that depth-pressure log. Fortunately, software is available commercially to implement the approach either in real time or following the job.
The advantage of this model is its ability to make quantitative predictions that are based on statistically significant quantities of empirical data. Fig. 16.20 shows estimated trips to failure vs. internal pressure for an 80-ksi tubing material with three different diameters and a 0.134-in. wall thickness, run over a 96-in. reel core diameter and 72-in. tubing guide arch. (The life prediction algorithm used to make these predictions comes from the Flexor TU4 Life Prediction Model).
In the field, the model is capable of monitoring the fatigue life profile along the length of the tubing. But, more importantly, it can predict the effect of impending jobs on that profile. This allows the engineer to modify the use of each string to effectively maximize its life, avoiding potentially dangerous situations and reducing costs.
The limitations of theoretical models include:
- Two sets of input data are required to characterize a particular material: (a) low-cycle fatigue data taken from axial coupons and (b) constant pressure bend-cycle data taken from CT fatigue fixtures or full-scale equipment. The greater the number of data points from the latter set, the stronger the statistical validity of the model.
- Current theoretical models do not incorporate tube body mechanical damage incurred as a result of well intervention or drilling operations. This type of damage includes exterior tube body wear, interior and exterior corrosion (atmospheric and industrial), or nicks, cuts, or scarring resulting from contact with surface handling equipment. However, research is under way to develop models that can estimate the influence of surface defects. Such a model exists and is currently being refined.
- The implementation of a theoretical approach must be in concert with a routine capable of estimating the varying internal-pressure loading at the point of bend cycling. This requires a reliable record of not only the depth-pressure history of a string throughout its use, but also a record of any string modification (section splicing and/or removal). This requires investment in surface recording instrumentation and sophisticated data-collection systems, such as portable computers, as well as complicated tubing management software systems for tracking and maintaining up-to-date records of the compiled tubing working life.
As discussed in the previous section, the service vendor must maintain a history of the various services for which each CT string has been employed to ensure prudent management of CT strings. This tubing-string record should include the following information (as a minimum):
- Pressure/bending fatigue-cycle history and locations of repeated bending cycling. The data for these records should be obtained from daily service activity reports or through electronic record-keeping devices.
- If pressure bend cycling is not recorded, then the service vendor should provide the "total running feet" (records must reflect footage into and out of the well).
- Maximum pumping pressures through the CT string when stationary.
- Exposure of tubing string to acid service. This record should list the number of acid jobs performed, type and volume of the acid system pumped, duration of the acid-pumping program, and vendor-recommended derating factors for the string.
- Locations of welds, identification of type of weld, and observations of deformity, ovality, or surface damage.
- Locations in the CT string where tensile loads exceeding 80% minimum yield were placed upon the pipe.
- A detailed record of any splicing or section removal that takes place along the length of the string.
Effects of Bend-Cycle Fatigue on Welds
Welds of several types are fundamental to the manufacture of steel CT. Welds are a common concern because the bend-cycle fatigue life of certain welds can be significantly less than that of the parent tube material. As a result, the performance of welds is of critical importance to the working condition of the tubing string as a whole.
The longitudinal seam weld runs the entire length of the coiled tube and is created during the manufacturing process as the base skelp is formed into tubing in the mill. Problems with the longitudinal seam weld are usually detected at the mill during either the manufacturing process or the subsequent hydrostatic pressure testing procedure. However, failures along the seam have occurred during field services in high-pressure applications because of excessive triaxial stress loading. During laboratory CT fatigue testing, it has become common practice to place the longitudinal weld seam along the curved bending mandrel, or on the compressive side of the tube wall. In general, cracking occurs on the compressive side of the tubing at least as often as (if not more often than) it does on the tensile side of the tubing. This observation holds even for testing when the weld seam is placed along the neutral axis of the tubing. In general, tests performed on the orientation of the longitudinal weld, with respect to the bending axis, have found no correlation of cycle fatigue life reduction because of longitudinal seam-weld damage. In the process of derating the CT because of bend cycling, the longitudinal weld is generally disregarded.
The welding technique that joins base metal skelp is referred to as the skelp-end weld. The flat skelp is cut and welded at an approximate 45° angle, causing the weld to form a helical wrap around the tube girth when the strip is subsequently formed into a cylinder. The weld is typically made in ideal conditions (with full control over the geometry and weld penetration), resulting in a weld of high and consistent quality. Because of the quality control, treatment of the weld and the subsequent helical distribution of stress, the skelp-end weld performs favorably in bend-cycle fatigue tests. Experimental results taken from bend-cycle fatigue tests comparing base tube samples to skelp-end welded samples found that the skelp-end weld survival can range from 80 to 90% of the base tube working life with relatively little variation from one weld to the next. This is well within the typical range of scatter exhibited by CT fatigue lives tested in the laboratory and the field.
A butt-weld or tube-to-tube weld is a means for joining lengths of previously formed tubing. The two ends of the finished tube to be joined are cut square, slightly beveled, carefully aligned, and TIG- or MIG-welded around the circumference. The resulting weld is oriented perpendicular to the CT axis, focusing the bending stress perpendicular to the tube axis (directly through the weldment). Because the weld is made from the tubing exterior, the quality of the weld penetration through the tubing wall is paramount. There are currently two types of tube-to-tube welds in use in CT services, which are discussed next.
Factory Butt-Weld. Before the development of the skelp-end weld manufacturing process, all CT strings were constructed by butt-welding several lengths of finished tubing together using an automated welder at the tubing mill. These welds were made in carefully controlled conditions, and the quality of these welds was generally very good. However, these types of welds remain significantly inferior to skelp-end welds, with bend-cycle fatigue life observed to be in the range of 40% of base pipe working life.
Field Butt-Weld. Once the CT is delivered to the field location, tubing sections which need to be joined are typically butt-welded by hand using a TIG or MIG technique. This "field repair" is frequently the only option available at the service vendor location. Manual butt-welds require a very high level of skill to have acceptable survival rates. As a result, field butt-welds are the most problematic of all CT welds. With the high likelihood of significant variations in quality of welds, the recommended practice based on experimental tests is to derate field butt-welds to approximately 20% of base tube working life.
There are numerous well-intervention applications that are performed using CT services. The advantages of CT include:
- Deployment and retrievability while continuously circulating fluids.
- Ability to work with surface pressure present (no need to kill the well).
- Minimized formation damage when operation is performed without killing the well.
- Reduced service time as compared to jointed tubing rigs because the CT string has no connections to make or break.
- Increased personnel safety because of reduced pipe handling needs.
- Highly mobile and compact. Fewer service personnel are needed.
- Existing completion tubulars remaining in place, minimizing replacement expense for tubing and components.
- Ability to perform continuous well-control operations, especially while pipe is in motion. However, there are several disadvantages to CT operations.
- CT is subjected to plastic deformation during bend-cycling operations, causing it to accumulate fatigue damage and reduce service life of the tubing string.
- Only a limited length of CT can be spooled onto a given service reel because of reel transport limitations of height and weight.
- High pressure losses are typical when pumping fluids through CT because of small diameters and long string lengths. Allowable circulation rates through CT are typically low when compared to similar sizes of jointed tubing.
- CT cannot be rotated at the surface to date. However, interest in rotating CT has been high in recent years, and several companies are actively designing equipment that will allow rotating of CT.
The most common CT well-intervention and drilling applications involve issues related to sand cleanouts or solids-transport efficiency. The process of cleaning sand or solids out of a wellbore requires pumping a fluid down into the well, entraining the solids into the wash fluid, and subsequently carrying the solids to the surface. In most cases, the wash fluids and solids are captured in surface return tanks with sufficient volume to allow the solids to settle out of the fluid. Where practical, the cleanout fluids are recirculated in the wellbore, thereby optimizing the cleanout program economics. One of the most important concerns in designing a solids cleanout program is the correct selection of the circulated fluid system. An overview of the two types of cleanout fluids used in CT services, categorized as "compressible" and "incompressible," is offered next.
Incompressible cleanout fluids are, for this discussion, limited to aqueous and hydrocarbon liquids. This type of cleanout program is the less complicated of the two categories. The cleanout fluid selected should be one that provides for solids removal in a "piston displacement" manner. The desired cleanout fluid is one that adequately transports solids out of the annulus. If circulation pump rates achieve annular velocities sufficient to exceed the terminal particle settling velocity, then Newtonian fluids can be used. Depending on the CT OD size, Newtonian fluids are generally adequate when performing a cleanout inside of production tubing. However, when circulating cleanout fluids within large-ID bore tubing or casing, the reduced annular velocities are typically insufficient to transport the solids out of the wellbore. In these cases, the cleanout fluid should be gelled to a higher viscosity. The non-Newtonian fluids used in this situation are generally sheared biopolymer gels or gelled oil systems.
Compressible fluid cleanout programs are more difficult to design and implement than incompressible fluid cleanout programs. Compressible fluids incorporate various fractions of gas in their composition and are selected to compensate for underpressured formations or where liquid cleanout fluid annular velocities are insufficient to lift solids. Fluid volumes change relative to temperature and pressure in a compressible system; therefore, the annular velocities of these fluid returns do not travel at the same rates throughout the length of the annulus.
Once circulation is established in a compressible fluid cleanout program, unit volumes of fluid are pumped down the CT at pressures needed to overcome the total system friction pressure losses. In this condition, the compressible fluid is experiencing high pressure and occupies minimal volume. As the unit volume of compressible fluid exits the end of the CT, it begins its rise in the annulus. The decreasing hydrostatic pressure of the fluid in the annulus, coupled with a reduction in system friction pressure loss, allows the gas within the fluid to expand. The expanding gas within the fluid causes the velocity of the unit volume to increase. The expansion of the compressible fluid and subsequent increase in unit volume velocity creates an environment of high frictional pressure losses.
As a result, annular velocities and solids removal capabilities require complex mathematical calculations to predict. In these cases, it is recommended to obtain computer-generated cleanout-program predictions from the CT service companies to evaluate the performance of a compressible fluid procedure. The fluids that fall under the compressible fluid category are dry nitrogen and foam (aqueous or oil-based).
Nitrogen is an inert gas and, therefore, cannot react with hydrocarbons to form a combustible mixture. In addition, nitrogen is only slightly soluble in water and other liquids that allow it to remain in bubble form when commingled with wash liquids. Nitrogen is a nontoxic, colorless, and odorless gas that is typically brought to location in liquid form in cryogenic bottles at temperatures below –320°F. The liquid nitrogen is pumped through a triple-stage cryogenic pump at a specified rate into an expansion chamber that allows the nitrogen to absorb heat from the environment and vaporize into a dry gas. The gas is then displaced out of the expansion chamber and into the treatment piping at the required surface pressure to perform the prescribed job. Although crogenic nitrogen does not contain oxygen, several other nitrogen sources such as pulse swing adsorption or membrane units can contain significant percentages of oxygen. This oxygen content can exceed 3% and represents a potential corrosion problem in some applications such as CT drilling.
In completed wellbores that are critically underpressured or liquid-sensitive, nitrogen pumped at high rates can be used to transport solids up the annulus and out of the wellbore. The solids-removal mechanism within the wellbore is directly dependent upon the annular velocity of the nitrogen returns. If the nitrogen pump rate is interrupted during the cleanout program, all solids being transported up the annulus will immediately fall back. Of equal concern are the tremendous erosional effects on the production tube, CT, and surface flow tee or flow cross that will occur at the rates needed to maintain solids transport up the annulus. Because of the difficulty to safely execute this type of cleanout program, solids removal programs using nitrogen should be considered as a "last resort" option.
Foam may be defined as a fluid that is an emulsion of gas and liquid. For this discussion, the liquid can be aqueous or oil-based, but the gas will always be nitrogen. In a stable foam, the liquid is the continuous phase, and the nitrogen is the discontinuous phase. In order to homogeneously disperse the nitrogen gas into the cleanout liquid, a small amount of surfactant is used to reduce the surface tension and create a "wet" liquid phase. The surfactant is usually mixed into the liquid phase in concentrations ranging from 1 to 5% of liquid volume. The "wet" liquid is then pumped down the treatment line and commingled with nitrogen in a "foam generating tee." The turbulent action created by the nitrogen intermixing with the "wet" liquid provides sufficient dispersion for the formation of a homogeneous, emulsified fluid.
Foam is generally selected as the preferred fluid media when performing solids removal programs in underpressured wellbores. Foam can be generated in hydrostatic pressure gradients ranging from 0.350 psi/ft through 0.057 psi/ft, depending upon the wellbore pressures and temperatures. The rheology of stable foam most closely resembles that of a Bingham plastic fluid, where the yield stress must be overcome to initiate movement of the fluid.
The industry-accepted term for describing the volumetric gas content of a foam fluid regime is "quality," which is arithmetically defined as
A stable foam regime possesses two significantly unique wash-fluid properties. The first is a solids suspension capability as high as 10 times that of liquids or gels. The second is the ability to act as a diverting system, withstanding up to 1,000 psig applied pressure with a minimal loss of wash fluids to the completion. However, if the foam quality exceeds the stable regime limits, the solids-suspension characteristics of the foam are reduced. At this point, the gas in the foam has expanded significantly, and the velocity of the gas in the annulus is maintaining suspension of the solids particles.
Note that because foam is compressible, the quality of this fluid regime is temperature- and pressure-dependent. As a result, the quality of the system is not uniform throughout the entire wellbore annulus. At surface treatment temperatures and pressures, the foam regime occupies a specific volume, thus defining the initial quality of the system. As the unit volume of foam is pumped down the CT and back up the annulus, the total frictional pressure loss acting against this unit volume decreases. Along with the reduction in annular hydrostatic pressure, the nitrogen gas in the foam expands as it approaches the surface. The result is a dynamic profile of foam quality in which the effects of friction pressure losses, viscosity, and fluid velocity are in constant flux.
Where CT solids-cleanout services are performed to re-establish communication with an open completion interval, it is a common practice to underbalance the pressure within the annular fluid system relative to the bottomhole pressure. This minimizes the loss of circulated cleanout fluids to the formation and the damage associated with deposited solids. As the annular fluid velocities increase, the frictional pressure loss and equivalent hydrostatic pressure acting against the open formation correspondingly increase. If the formation is open to take fluids, then the volume of cleanout fluids returning to the surface decreases to a rate that maintains the proper balance of friction pressure and annular hydrostatic pressure acting on the open completion.
If the cleanout fluid was designed to hydrostatically balance the bottomhole completion pressure, then any additional pressure applied to the circulating system will cause an overbalance condition to occur. If the formation is highly permeable, then it is likely that a portion of the circulated cleanout fluids will be lost to the open completion once communication with the wash system is established. In effect, if the wellbore circulating system is balanced at a specific rate, the incremental increase in surface pump rate intended to increase circulation rates will most likely be diverted into the completion.
Note that the annular pressure losses because of friction for the circulating system are for "clean" circulated fluids. If the solids concentration within the cleanout fluids are maintained below 2 ppg, the effect of frictional pressure loss because of an increase in solids concentration in the annular wash fluids is considered to be minimal. However, a cleanout-fluid solids concentration in excess of 2 ppg is likely to cause a change in fluid rheology and a noticeable increase in annular friction pressure loss.
The rate of penetration of CT into a column of packed solids (wellbore cleanout) or drilled hole, coupled with a constant circulated fluid annular velocity, directly determines the concentration of solids captured within the cleanout fluid. The dispersion of the solids in the fluid media causes an increase in effective weight of the annular returns fluid. As a result, the hydrostatic pressure differential increases between the "clean" fluids pumped down the CT and the "dirty" fluids circulated up the annulus.
The type of formation fluids produced can also determine the effectiveness of the solids-removal program. In a liquid-producing wellbore (oil and water), the fluids in the wellbore are slightly compressible and can, therefore, support a "piston"-type displacement of the captured solids back up the annulus. If the produced fluid is a gas, then caution must be taken to prepare for "gas influx surges" or lost returns when breaking through sand bridges or drilled gas pockets. In addition, the difference in fluid densities between gas and liquids causes the gas to override the circulated cleanout fluid. When in communication with a permeable gas zone or completion interval, liquids are likely to be lost to the gas zone, regardless of the bottomhole pressure.
When performing a solids removal program in an underpressured oil-producing wellbore with an aqueous foam, precautions must be taken for foam degradation when commingled into the oil. The oil rapidly destabilizes the foam regime at the contact interface and breaks down into a gasified, oil/water emulsion. As this gasified oil/water emulsion continues to degenerate and move up the annulus, the solids-laden foam in the returns becomes compromised, and fallback of the solids can occur.
For wellbore cleanout applications, the selection of a wash tool should define the hydrodynamic action of the cleanout program. In other words, the wash tool should provide additional downhole turbulent action as needed. Several wash tools available within the industry are designed with ported jet nozzles for imparting hydraulic energy on packed solids or mechanical assistance in breaking up bridged solids. Many times, these wash tools can be constructed to serve as mandrel bypass tools, further extending their utility. Depending on the number and size of nozzle ports, along with the cleanout fluid system selected, frictional pressure losses can be significant.
With the evaluation of the aforementioned criteria for selecting a cleanout fluid system completed, the cleanout program can be implemented using either the "conventional-circulation" or "reverse-circulation" techniques. These two techniques are discussed next.
Conventional circulation is the process of pumping a fluid down the CT and allowing the fluid to travel back up the wellbore annulus to the surface. Conventional circulation is by far the most common CT service technique used for removing solids out of wellbores. Along with all of the aforementioned criteria used to determine the cleanout fluid system, the maximum tensile stress loads to be placed on the CT string should be estimated to ensure that the loads do not approach the minimum yield rating of the tube.
Both compressible and incompressible fluids can be used with the conventional-circulation cleanout technique. The selection of appropriate CT size depends on the minimum pump rates needed, total circulation system pressure losses, and the minimum yield load rating required to safely retrieve pipe from the wellbore. The use of downhole flow check devices (check valves) and ported wash tools should not inhibit the intended execution of conventional circulation wash programs.
Reverse circulation is the process of pumping the "clean" circulated fluid down the concentric tube annulus and forcing the "dirty" fluids to travel up the CT ID to the surface. In general, reverse-circulating solids cleanout programs are used where annular velocities are insufficient to lift solids out of normally pressured or geopressured wellbores. The cleanout program is designed to pump the clean fluids down the tubing annulus and use the higher fluid velocities within the CT to lift the solids out of the wellbore. This technique is more complicated to plan and execute than the conventional circulation cleanout program.
The planning of a reverse-circulation cleanout program requires that a minimum effective fluid pump rate be established and the frictional pressure loss through the CT and annulus be calculated for that rate with a high degree of accuracy. Information on the particle size, geometry, adhesive tendencies, and settling velocity must be obtained to ensure that no settling or plugging of the CT string is likely to occur. In a reverse-circulation cleanout program, the highest pump pressures act against the OD of the CT directly below the stripper assembly. Depending on the amount of differential pressure between the annulus and the CT ID, coupled with the condition of the CT (tensile forces, ovality, wall thickness, etc.), plastic collapse of the coiled tube can occur.
Reverse-circulating cleanout programs are generally limited to incompressible fluid applications. The selection of an appropriate CT string is limited to larger-ID tube sizes that minimize friction pressure losses. However, the larger OD of the CT causes higher annular pressure losses. In addition, reverse-circulating programs cannot be performed with downhole flow check devices or restrictive wash tools installed on the CT string.
Coiled Tubing Drilling
CTD has a rather extensive history and received a large amount of press and hype from the 1990s to date, not an insignificant amount being less than positive. There have been numerous highly successful applications of CTD technology in such regions as Alaska and the United Arab Emirates, yet CTD is still considered an immature new technology. Reasons for this are numerous, ranging from lack of understanding of CTD technology, to misapplication, to exaggerated expectations. One example is the knowledge that advantages to CT services include small footprint, high mobility, and quick operations. The aforementioned advantages may be true for conventional CT services and simple, short CTD jobs where directional control is not required and the hole can be left uncased. However, when more complex CTD services are planned, including directional drilling and cased completions, these advantages may no longer apply.
The complex drilling operations routinely require pipe handling equipment, provisions for handling long BHAs, large diameter CT, larger blowout preventer (BOP) stacks, and fluid-handling equipment for cleaning, mixing, and recirculating fluids, which are typically not required for conventional CT services. When including the additional separators and nitrogen-pumping equipment required for underbalanced drilling (UBD), the advantages related to small footprint and high mobility may no longer be the case. Numerous truckloads of equipment can take days to rig up in preparation to drill with CT.
Fig. 16.21 shows a purpose-built CTD rig working in Oman. When considering all the equipment necessary to handle completion pipe, allow fluid recirculation and provide for UBD operations. The small footprint and high mobility commonly associated with CT may no longer be a valid assumption.
However, even considering the challenges to CTD, there are certain applications in which the unique aspects and capabilities of CTD technology clearly demonstrate that it is the best tool for the job. The most common applications for directionally controlled CTD technology are re-entry drilling/sidetracking from existing wellbores (often through the existing wellbore’s production tubing) and underbalanced, managed-pressure, or low-bottomhole-pressure drilling.
Another niche market for CTD technology includes the combination of a CTD unit with a low-cost conventional rotary drilling rig. In this application, the rotary rig is used to drill a quick and simple wellbore and sets casing just above the desired zone. CT is then used to drill a small, clean penetration into the desired zone and is used to run any required completion. The following sections will further discuss CTD technology.
As previously mentioned, drilling with CT was one of the first ideas for application of continuous workstrings dating back to the 1926 Bannister concept for a flexible hose drillstring and the 1948 G.D. Priestman patent application work for the more conventional reeled rigid pipe. The Bannister work involved using hose for fluid circulation with support cables attached to the sides to carry the weight. The system was reported to be technically successful, but marginally reliable, and development work ceased in 1940 reportedly because of the "lack of a suitable downhole motor" for the new technology.
The G.D. Priestman patent conceived what is today considered modern CTD technology as far as the spooled tubing and operation is concerned. However, it was 25 years before the first actual steel coiled tube drilling found practical application with Flex Tube Ltd. and the Uni-Flex Rig Co. Ltd. by drilling numerous shallow gas wells in Canada. This initial rigid CTD effort was pioneered by Ben Gray through the drilling of approximately 18 wells over a 14-year period in Canada.
The flexible-hose Bannister work was followed up by R.H. Cullen in the late 1950s and early 1960s. R.H. Cullen Research came up with an armor-wrapped flexible-string drilling system that used off-the-rack types of motors and drill bits. The Cullen work improved on the original by braiding the hose to carry the "drillstring" weight.
This flexible braided hose had a 2⅝-in. OD and electric-powered cable running internal to the pipe. The BHA comprised an electric motor and drill collars. R.H. Cullen drilled two separate boreholes, approximately 4¾ in. in diameter, to a depth greater than 1,000 ft.
At approximately the same time period as the Cullen work in the late 1950s and early 1960s, Inst. Français du Pétrol (IFP) also showed interest in continuous-string flexible-hose drilling technology. The IFP drilling hose was spooled up onto a reel roughly 5 in. in diameter. A four-skate injector was used to translate the spooled tubing into and out of the wellbore.
The IFP spearheaded work ran turbodrills and electric drilling motors in the BHA. In this test program, over 20,000 ft of borehole was drilled, with hole sizes ranging from 6¾ up to 12¼ in. This development effort was tested both onshore and offshore. The maximum depth reportedly drilled in the IFP project was 3,380 ft because of length restrictions of the pipe on the reel.
Advantages to the IFP flexible drillstring technology of the era included:
- Reduced trip time.
- No connections.
- Continuous circulation.
- Improved well condition.
- Improved safety.
- Optimized bit performance, directional control, early kick detection, and bottomhole parameter monitoring.
Many of these same advantages are still touted today when discussing advantages of CTD technology when compared with conventional rotary drilling. What one mentioned IFP spooled-drillstring advantage, "better working conditions," was based on is somewhat difficult to understand. The project was abandoned because of lack of support.
From 1964 to 1969, there was an additional spooled-drillstring development effort in the form of a consortium of different companies to develop a longer string of spooled hose. This consortium developed a larger-diameter flexible drillstring up to 12,000 ft long. Again, the power cable was run internal to the pipe, and the BHA comprised electric motors and drill collars. One borehole was drilled to 4,500 ft, but there was insufficient support for further development of this type of drilling concept in the industry at the time. Like all previous projects based on this new technology, the project was soon abandoned.
Application of spooled rigid pipe drilling (PD) systems followed the early flexible reinforced hose work. From 1976 through 1978, Ben Gray with Flex Tube Ltd. assembled Rig No. 11, which used 3,000 ft of 2⅜-in. OD butt-welded X-42 line pipe. This coiled-steel drillstring was spooled onto a 13-ft diameter reel, and this apparatus was used to drill shallow gas wells in Canada. The BHA reportedly comprised three 4¾-in. drill collars, a 5-in. downhole PD motor and a 6⅝-in. tricone bit. A sixteen near-vertical, nonsteered wells were drilled, with the deepest being approximately 1,700 ft. It is important to note that Flex Tube Ltd. had also constructed a string of spooled aluminum drillpipe for this new drilling technology toward the end of this pioneering development period, but it was not placed in service.
The reasons cited for the need for this continuous drillstring included:
- Escalating pipe prices.
- Expensive handling equipment
- Eliminating need to handle heavy 30-ft pipe joints.
- Eliminating two men per shift at a time when the industry had problems attaining people "capable and willing to do a good job" and because "long hours requiring physical and mental endurance make [the oil industry] an unattractive career."
The first two aforementioned reasons do not appear to fit the current CT market in that CT is an expendable that typically costs more than oil country tubular goods (OCTGs) and that CT handling equipment prices have come up similar to other options. However, it is hard to disagree with the logic of the last two reasons.
The roughly one-half century of spooled-drillstring technology development reportedly ended because of
- Lack of petroleum industry sponsorship for high-tech ventures.
- Competitive market.
- Fully depreciated rigs.
- Proven rig technology.
- CTD benefits did not translate into immediate cost savings.
These reasons are easy to believe even today.
The New Era of CTD
Following the initial Canadian spooled rigid pipe work, little activity occurred until 1991, when interest in the technology was again piqued and CTD began anew in France and west Texas. This renewed interest continues today in niche markets throughout the world.
As of 2003, approximately 12 years have passed from this renaissance of CTD. Out of a fleet of approximately 1,100 CT units in the world today, approximately 60 to 100 of the CT units are considered applicable for CTD, depending on reel capacity and numerous other needs and logistics limiting parameters.
The total 2002 CT-drilling-based revenues are estimated to be approximately U.S. $43,000,000, while drilling revenues are estimated at approximately U.S. $4,000,000,000. The CTD market is then estimated to be about ½ to 3% (depending on using only the CTD portion of revenue or entire job costs) of rotary-drilling-based on revenues.
Interestingly, a market survey in 1994 put the market share somewhat less than 1%. As can be seen, the revenue growth in this industry has been flat over the last decade. However, CTD does offer some unique advantages to other options, and it does come with distinct disadvantages as well.
Advantages to CTD
UBD. The ability to work with surface pressure while flowing produced fluids and continuously pumping when tripping into and out of the hole clearly represent the most important advantage to CTD. This unique ability allows for maintaining underbalanced conditions on the formation to minimize the potential for formation damage and increase drilling penetration rate. Maintaining underbalanced conditions on the reservoir at all times is critical in reducing the potential for formation damage in sensitive reservoirs. The majority of CTD operations performed in Canada are primarily for this reason.
Managed Pressure Drilling. Again, the ability to work with surface pressure gives a unique advantage to the CTD process. Experienced coiled tubing unit (CTU) crews are well trained in working with surface pressure, and the CT equipment is designed to work with significant surface pressure. Once the BHA is pressure deployed, commonly done with a lubricated wireline rig up and deployment BOPs, there is no need to snub or strip connections through a rotary BOP stripper. This capability, combined with reduced pipe handling, helps increase the safety of the operation and minimizes the risk of spills.
CT Provides Continuous Use of Hardwired Telemetry and Conduits. As previously mentioned, CT can have electric logging line or other signal telemetry options installed that are fully operational even while tripping. These power and signal paths significantly increase the communication bandwidth available for bidirection telemetry. The hardwired telemetry data transmission rates surpass any mud pulse telemetry, allowing greater data acquisition while drilling. Hardwired telemetry also allows deeper attainable communications than other technologies, such as electromagnetic telemetry. These power and signal paths significantly increase the communication bandwidth available for bidirectional telemetry. The hardwired telemetry surpasses any mud pulse telemetry, allowing greater data acquisition while drilling. Other pressure conduit(s) such as small capillary tubing are often installed in CTD reels, which enable the unique capabilities for operating downhole tools.
Fully Contained Well Pressure. CTD operations are most often performed with fully contained well pressure via the well-control stack including a lubricator and upper stripper of hydraulic packoff. This mechanical pressure-control system is often considered a part of the primary well control as opposed to the drilling fluid in most conventional rotary-drilling operations. In properly designed and engineered jobs, taking a kick is not as much of a threat to manpower and equipment as in common rotary drilling operations.
Small Footprint and Greater Mobility. Many of the more recent CTD programs ranging from the McKittrick work in California during 1994 to the Cerro Dragon work in Argentina during 2001 chose this method over more conventional rotary equipment because of the smaller footprint and ease of mobility of CTD equipment.
Quicker Trip Times. The CTD program in Alaska is arguably the most successful continuous CTD program in the world to date. The CTD program has been operating uninterrupted for over 10 years, and yet the vast majority of the jobs are performed overbalanced. The reasons for this are simple. Many formations will not support underbalanced conditions, and CT drilled boreholes have been shown to be less expensive than rotary-drilled wells, both from a cost-per-well and cost-per-barrel perspective. The quicker trip times allow for lower-cost penetrations when multiple trips and encountering unexpected geological formation changes require operational flexibility and increase the potential for changing the target and trajectory.
Potentially Fewer Service Personnel Are Needed. This is not always the case, but generally speaking, CTD operations require fewer service personnel because of the reduction in pipe-handling requirements. This again, helps lower the cost of the well on a daily basis.
Disadvantages to CTD Techniques
Inability to Rotate. The inability to rotate the pipe accounts for the largest single disadvantage to CTD technology. Running drilling operations in 100% slide mode would be the closest analogy to understanding CTD limitations. The ability to prevent cuttings beds uphole, achievable depths, and tolerance of solids in the drilling fluid are all reduced with this inability to rotate.
The buildup of solids beds requires numerous short trips to stir the cuttings bed back into the drilling fluid. In Alaska, short trips to prevent "duning" in the high angle to horizontal sections of the well’s account for more than nine times the drilling penetration measured depths. On-bottom testing has confirmed that rotation and short tripping are virtually the only two ways to effectively remove solids beds once they have been deposited in the wellbore above the BHA. Some work has been applied to designing CT equipment that can be rotated, but the CT will be able to withstand the abrasive environment typical in many rotary-drilling operations. Maximum depths achievable in high-angle to horizontal holes are reduced in a large part because of the increased friction of being in essentially static rather than dynamic mode as when the drillpipe is rotated.
When drilling overbalanced, differential pressure can increase the chance of differentially sticking the drillstring or BHA. This is particularly true for CTD for a number of reasons. First, CT is run in essentially buckled mode because of residual stresses in the CT, even when low to moderate tensile loads are present in the CT string. This, coupled with the lack of standoff normally provided by the drillpipe connections, increases the surface area of the drillstring to differential sticking. Solids accumulation within the drilling fluid system further exasperate this sticking tendency. Field data have shown that drilling efficiency is greatly reduced as solids loading in the drilling fluid approached 1%.
Cost of Consumables. Jointed drillpipe can be maintained for a relatively long life by having connections recut and resurfaced, or damaged joints may simply be replaced by another 30-ft joint. CT, on the other hand, is a consumable commodity. Unlike drillpipe, CT is plastically yielded 6 times every round trip in the hole. After a finite number of trips into the hole, the entire CT string is scrapped or sold for less severe applications. This price differential can be compounded by the fact that CT typically cost more per foot than OCTG products of similar size and weight. Because the probability of having a pinhole or parted CT is higher than in a properly maintained drillpipe, a well-defined contingency plan for such an occurrence is essential. A downhole motor is required for all CTD operations because no current method of rotating CT has been applied in the field. This adds to the cost per foot.
Limited Drilling-Fluids Life. As previously mentioned, CTD requires a low-solids loading in the drilling fluid to provide the highest weight on bit (WOB), assure adequate rate of penetration (ROP), and to maximize the potential reach. Relatively low achievable CTD pump rates often mandate relatively high viscosity to assure adequate hole cleaning. This high viscosity often exceeds a low shear-rate viscosity (LSRV) of 40,000 or more and tasks the ability of solids-control equipment to efficiently remove solids. Finally, the high friction losses and associated turbulence degrade many common biopolymers used in CTD applications. All these factors result in higher costs to maintain a drilling-fluid system.
Limited Equipment and Limited Experience Manpower Base. As previously discussed, the limited equipment base and lack of widespread application of CTD technology limit the availability of equipment and experienced manpower. These factors often result in higher-cost operations, and because the experience base is not nearly as high as that for rotary technology, the potential also exists for reduced chance factor of success in some instances.
Logistics of Getting Equipment to the Work Location. Drilling requires a conduit to carry drilling fluids at a sufficient rate to lubricate and cool the bit and remove the cuttings at the depth required to reach the desired targets. The higher the achievable pump rate, the more efficient the cutting-transport back to the surface. Generally, a relatively large-diameter conduit is more desirable. The target depth is fixed. Almost without exception, all the CT required to drill a well is spooled up onto a single drum. The needs for hole cleaning and reaching the required depth often results in relatively large reels of CT, which make the logistics of getting the equipment to many potential drillsites problematic. Meeting road restrictions is a challenge for many on-site locations, and the offshore arena has its own set of equal or more challenging logistic problems. Not only is room at a premium, but, also, cranes needed to lift the spools of CT are often inadequate. These and other problems require more preplanning, engineered solutions, and often butt-welds in the CT. As previously mentioned, butt-welds significantly reduce the available useful life of a reel of CT that is already a consumable.
Reduced Pump Rates, Torque, and WOB. This is not unique to CTD operations. Drilling operations encounter the same limits when they are performed with small-diameter drillstring similar to most common CTD operations.
More Tortuous Path. Currently, CT cannot be rotated to drill the reach and horizontal sections of horizontal and high-angle holes. However, new technology is currently under development and is expected to offer some relief with the ability to continuously rotate portions of the BHA to provide a smoother trajectory.
Newer Technology with Lack of Operator Experience Base. Rotary drilling is a proven technology with reasonably well understood capabilities and limitations. This can be said for CTD only in a few geographic locations where CTD is continuously used, such as Alaska and Canada. Selling CTD technology in a new location is a difficult proposition owing in part to the truth of the following quote: "Bad memories die hard in the oil field, and many remain suspicious of the technology. Because the reputation of a project engineer or manager is always on the line, it is natural to choose the proven over the new, potentially risky technique, regardless of potential cost savings." Despite these limitations, the unique advantages to CTD technology often outweigh the disadvantages.
General Discussion of CTD Equipment
There is the common belief that CTD equipment is compact and highly mobile. In reality, the equipment required to provide drilling functions can make this a misconception.
CTD ancillary equipment needs do not significantly differ from those of jointed-pipe or rotary-drilling operations. CTD mechanics and limitations are the same as when slide drilling with rotary-drilling units. The similarities between CTD and jointed-pipe drilling in needed equipment far outweigh the differences.
Current CTD is based on the same equipment used in rotary drilling with small-diameter drillstrings. Other than common CT ancillary equipment, such as connectors, flapper check valves, disconnects, and circulation subs, the only unique CTD equipment required for directional drilling is the orienter in the BHA. With the exception of the CT itself, all other drilling physics and required equipment is the same as slide drilling with jointed pipe. Fig. 16.22 shows an example of mud pulse telemetry CTD BHA.
Fig. 16.22—Mud-pulse telemetry CTD BHA. Frictional pressure drop through the CT can be significantly reduced and problem contingencies are increased when compared to wire- or umbilical-containing CT. Data transmission, however, is significantly slower than wireline telemetry options and is not compatible with compressible gas within the CT.
Fig. 16.23 shows an example of a modular CTD BHA that relies on an electric line installed within the CT for telemetry. Although differential pressure drop through the CT is higher than CT without wire installed, this type of BHA has proven to be efficient in CTD applications.
Fig. 16.23—Modular CTD BHA that relies on an electric line installed within the CT for telemetry. Although differential pressure drop through the CT is higher than CT without wire installed, this type of BHA has proven to be efficient in CTD applications. Electric line telemetry will operate with gas phases within the CT as commonly used in underbalanced drilling applications (courtesy of Baker Hughes Inteq.)
The orienter, as the name suggests, provides a method to orient the toolface of the bottomhole drilling assembly. Early orienters included a design with a lead screw that would provide a rotational torque to the BHA when the pumps were off and slackoff weight was varied—much like the operation of a small child’s mechanical top. The new orientation was locked in once circulation was started again. The next improvement in orienting tools was indexing tools. These tools were operated by alternating the pumps on and off to index the orienter in typically 30 to 60° steps. These early orienters were often slow and less than optimally reliable, but they did and still do provide a method to directionally steer a mud-pulse BHA where no wires or umbilicals are installed inside the CT. The most recent design of an orienter for mud-pulse-directional drilling included use of a smart sub that can recognize words pumped downhole by varying the pump rate, decipher the words, and then rotate the BHA to the requested tool face.
The other category of orienters includes those that are wireline or hydraulically operated. Using these tools requires the inclusion of wire and/or one or more small-diameter umbilicals installed inside the CT. The wires and/or umbilicals reduce the effective CT ID, causing increased frictional pressure losses in the CT, and add more weight per foot. Typically, these electric or hydraulically operated orienters have a range of rotation of approximately 400°. However, these tools have provided much more predictable results, and the high-rate telemetry path of installed wireline has proven to outweigh the disadvantages to their use. Often overlooked potential problems with CT containing umbilical or wire include the contingency to cut the CT should the BHA or CT become stuck and restrictions to pumping balls or darts through the CT.
Many, if not most, drilling applications require cleaning and recirculation of viscosified drilling fluid and call for completing the zone drilled with some type of tubulars. The vast majority of common CT units are designed to effectively run CT into and out of live wells. They are not designed to handle jointed pipe and typically carry no fluid-handling equipment.
There are numerous methods used to provide needed drilling and completion capabilities during CTD operations. Many CTD service providers combine CT equipment with common drilling components including substructures, pipe-handling equipment, drilling-fluid handling and solids-removal equipment, and some sort of mast or vertical support.
Occasionally, CTD service providers simply rig up a coiled tubing drilling unit (CTDU) with a workover or drilling rig. Others build new equipment custom designed to meet the restrictions and needs of areas in which they operate.(See Fig. 16.24).
Hybrid CTDUs are available in several locations worldwide that combine CT equipment with a drilling or completion rig in an integrated package. These hybrid CTDUs are as efficient drilling with CT as they are in handling pipe or performing other common drilling, completion, and workover functions. However, with the versatility often come higher day rates and a larger and heavier equipment spread. Fig. 16.25 shows an example of a hybrid CTDU that provides all common drilling rig functions and efficient CTD. These hybrid units are extremely efficient and operationally flexible but can weigh well over 1.5 million pounds.
Guidelines for Successfully Applying CTD Technology
Although a number of operators ranging in several geographical areas have successfully applied CTD technology, its widespread use still has not been accepted. Reasons for this are numerous, with the most common probably being lack of commitment to get over the learning curve and into the exploitation mode. The following is a list of things an engineer can do to help assure a successful CTD program:
- Have the correct target and keep it simple: (a) Proper reservoir, (b) low difficulty, (c) lower-challenge drilling especially for wells early in the program, and (d) drillability considering the confines of slide drilling with small tubing.
- Have the correct program size; have enough candidate wells to get over the learning curve and into exploitation.
- Have the correct equipment for the effort.
- Have the commitment: management and technology resources from both operator and service provider.
When bringing CTD into a new area, plan on using sound engineering concepts combined with extensive preparation and planning. It is imperative to remember that CTD drilling technology is still a drilling function that relies on the same best practices for drilling. Pull together a multiexperienced crew that knows CT and drilling practices. Prepare and train for numerous contingencies. Read all available technical papers on CTD.
The following is a list of items to consider and parameters that are within the abilities of CTD technology. None of these are "records." Instead, they fall in the middle of what can be accomplished using proper CTD techniques.
- WOB is a challenge; CTD currently is 100% slide drilling.
- Depths to about 17,000 ft measured depths with reasonable geometry.
- 6 ⅛ in. or smaller hole sizes.
- Done 13 in. shallow.
- 3,000 ft or less measured-depth laterals kicking off at 10,000 ft measured depths.
- Plan on less than 55° per 100 ft build sections.
- When drilling in 4½-in. casing, the most common CT size used is 2⅜ in. or 2⅝ in. that hydraulically fits the bit for the casing size.
- In 5½-in. casing, the most commonly used CT sizes range from 2⅜ in. to 3 1/16-in., again with the 3 1/16-in. CT optimized for hydraulic requirements.
- In 3½ in. casing, the most common CT size is 2 in. OD.
The following is a list of where CTD technology may be applicable:
- Underbalanced (UB) drilling to minimize potential damage to the formation.
- Where costs to mobilize rotary rigs are high.
- Areas with campaign number of candidates.
- Where logistics/area for rig may be tight.
- Managed pressure drilling candidates.
- Through faults with high differential pressure between zones.
- In stable wells where ROP dramatically increases during UB drilling.
- Areas with access to: (a) right well candidates, (b) drillable formations within CT range, (c) personnel, (d) right people, with the right skill sets, doing the right thing, and (e) right equipment available.
Properly applied, CTD’s unique capabilities can be used to provide reliable and repeatable drilling solutions, even in demanding circumstances.
CTD Tools, Techniques, and Equipment Under Development
Currently there are numerous ideas in various stages of development that may extend the utilization of CT for drilling operations. These new developments in technology, techniques, and/or equipment target special needs:
- Allow rotating the entire string of CT to extend attainable measured depths and improve hole-cleaning efficiency.
- Include telemetry built into the CT string such as used in the Halliburton Anaconda Project. The Anaconda CT was made of composites and contained numerous conductors wound into the composite body. The composite material reduced needed crane load capacities and extended the CT fatigue life. The built-in conductors allowed for power and telemetry without intrusion into the inner diameter of the CT.
- Special designed equipment and techniques to reduce costs for exploiting existing brownfield assets.
- More-compact and lighter units for more flexible movement on existing roadways.
- Equipment to efficiently drill smaller-diameter wells, for both directional and nonsteered applications.
- More-efficient managed-pressure-drilling operations, especially in extremely low or high BHP applications
- Offshore packages for CTD intervention. This equipment is designed to address problems common to offshore environments including limited deck space, limited crane capacities, heave and swell problems, and time required to rig up and test equipment.
Only time will tell if this equipment can be successfully developed and applied to extend the utility of CTD or if these new ideas will disappear into obscurity, as have many of the early innovations in continuous conduit drilling.
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|Dc||=||specified outside diameter|
|Dx||=||outside diameter (measured along the x-axis)|
|Dy||=||outside diameter (measured along the y-axis)|
|E||=||modulus of elasticity|
|Ry||=||yield-stress radius of curvature|
|Sy||=||material yield strength|
|t’||=||reduced wall thickness owing to thinning|
|t||=||specified wall thickness|
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SI Metric Conversion
|ft||×||3.048*||E – 01||=||m|
|°F||(°F – 32)/1.8||=||°C|
|in.||×||2.54*||E + 00||=||cm|
|lbf||×||4.448 222||E + 00||=||N|
|lbm||×||4.535 924||E – 01||=||kg|
*Conversion factor is exact.