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Free Download Babbel App Verified. Get these enticing deals when you use using babbel. Use babbel. This sale is hard to come by and will end soon. Grab them while you can. Learn Languages Online Verified. 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.
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.
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 "wet" liquid is then pumped down the treatment line and commingled with nitrogen in a "foam generating tee. 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.
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 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, 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. 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. 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.
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 Bannister concept for a flexible hose drillstring and the G. 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 reportedly because of the "lack of a suitable downhole motor" for the new technology. The G. 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. This initial rigid CTD effort was pioneered by Ben Gray through the drilling of approximately 18 wells over a year period in Canada. The flexible-hose Bannister work was followed up by R. Cullen in the late s and early s. 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.
OD and electric-powered cable running internal to the pipe. The BHA comprised an electric motor and drill collars. At approximately the same time period as the Cullen work in the late s and early s, Inst. The IFP drilling hose was spooled up onto a reel roughly 5 in. A four-skate injector was used to translate the spooled tubing into and out of the wellbore.
This development effort was tested both onshore and offshore. The maximum depth reportedly drilled in the IFP project was 3, ft because of length restrictions of the pipe on the reel. Advantages to the IFP flexible drillstring technology of the era included:. 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 to , 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, 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, ft, but there was insufficient support for further development of this type of drilling concept in the industry at the time.
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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. OD butt-welded X line pipe. This coiled-steel drillstring was spooled onto a ft diameter reel, and this apparatus was used to drill shallow gas wells in Canada. A sixteen near-vertical, nonsteered wells were drilled, with the deepest being approximately 1, ft. It is important to note that Flex Tube Ltd. The reasons cited for the need for this continuous drillstring included:.
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. These reasons are easy to believe even today. Following the initial Canadian spooled rigid pipe work, little activity occurred until , 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 , approximately 12 years have passed from this renaissance of CTD. Out of a fleet of approximately 1, CT units in the world today, approximately 60 to of the CT units are considered applicable for CTD, depending on reel capacity and numerous other needs and logistics limiting parameters. The total CT-drilling-based revenues are estimated to be approximately U.
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. 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. 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 to the Cerro Dragon work in Argentina during 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 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.
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. Inability to Rotate. The inability to rotate the pipe accounts for the largest single disadvantage to CTD technology. 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. 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. 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 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, 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. 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. 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. Rotary drilling is a proven technology with reasonably well understood capabilities and limitations. 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. 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. Electric line telemetry will operate with gas phases within the CT as commonly used in underbalanced drilling applications courtesy of Baker Hughes Inteq.
These rigs are often built considering local area needs and regulations.
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:. 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. Currently there are numerous ideas in various stages of development that may extend the utilization of CT for drilling operations. 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.
Brown, A. Cobb, C. Crouse, P. Cruise, D. Donald, D. Elsborg, C. Feechan, M. Field Experience with Composite Coiled Tubing. Flowers, J. Solutions to Coiled Tubing Depth Control. Flynn, T. Forgenie, V. Going, W. Hatzignatiou, D. Higdon, A. Mechanics of Materials, third edition, 87— Kirk, A. Application of C. Kumar, M. Laun, L. Loughlin, M. McCarty, T. Nirider, H. Rixse, M. Sas-Jaworsky, A. World Oil November , Wright, T. Tube Technology and Capabilities.
In Coiled Tubing Handbook, third edition, Houston, Texas: World Oil. Stanley, M. Stiles, E. Jump to: navigation , search. Publication Information. Petroleum Engineering Handbook Larry W. Lake, Editor-in-Chief. Volume II - Drilling Engineering. Copyright , Society of Petroleum Engineers. 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. The 3-in. 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. These 4,ft segments were then butt-welded together and spooled onto the conundrums. 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. Calhoun and Herbert Allen on 4 September 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. 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 , the California Oil Co. The original "Unit No. 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. 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.
A simplified illustration of a CT unit is shown in Fig. Coiled Tubing CT is an electric-welded tube manufactured with one longitudinal seam formed by high-frequency induction welding without the addition of filler metal. 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 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. The change in specified wall thickness, t , between the adjoining CT segments should not exceed the following specified values: 0.
CT Performance CT well intervention and drilling operations require that the continuous-length tube be subjected to repeated deployment and retrieval cycles during its working life. Description of Fatigue Fatigue is generally considered to be the single major factor in determining the working life of CT.
This relationship is graphically represented as the line segment O-A in Fig. The stress at Point A is referred to as the "proportionality limit," also referred to as the "elastic limit. 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. 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.
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. 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. 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. 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. CT Management 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.
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. A detailed record of any splicing or section removal that takes place along the length of the string. CT Applications 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.