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Collaborating Authors
SPE/ICoTA Coiled Tubing Conference and Exhibition
Abstract Today's drilling environments require a CTD bottom hole assembly (BHA) be designed to perform in harsh environment. These include drilling in Underbalanced conditions (UB), challenging formations and high temperatures. This paper details findings from Coiled Tubing Drilling (CTD) operations in Alaska, Algeria and Sharjah. These challenging operations required a complex CTD BHA that should be capable of withstanding temperatures in excess of 150°C (300° F), severe vibrations, over-speeding of motors, high-performance positive displacement motors (PDM's), nitrogen intrusion in BHA and PDM elastomer as well as many other challenges. As a result, the CTD BHA was engineered to meet these various challenges. For example, in order to reduce (or better manage) BHA dynamics under extreme vibration levels, a multi-axis vibration sensor was used to optimize the BHA with weight and flexible bars. This permitted the driller to monitor vibration levels in real-time and adjust drilling procedures and parameters (WOB, mud flow, use of circulating sub, etc.) to reduce excessive vibrations. The BHA also had to address telemetry issues and, on the Sharjah nitrogen-drilled wells, an E-line CTD BHA was employed as it was the only way to transmit MWD/LWD data in the multiphase mud flow. The paper will also describe some of the special BHA features like multi-cycle circulating sub use, ECD/pressure management, high-speed motor use and more. And the results of these efforts will be documented with performance and vibration graph comparison. In the previous two years, drilling processes on the Sharjah and Alaska wells were significantly improved for increased footage per day and lower overall well costs. As a result, these projects have been recognized as economic successes and the findings from these wells can be applied to optimize the drill string and drilling parameters for enhanced performance in other challenging environments. Introduction From 2002 to 2004 Coiled Tubing Drilling (CTD) activity for horizontal drilling in both underbalanced and overbalanced mode has increased considerably (approximately from about 3.000 m to 70.000 m per year1). As CTD became a reliable and cost efficient drilling technology, more operators began to consider this technology more often for reentry drilling and the CTD is now regularly considered for re-entry and UB drilling projects Based on continuous activities, service providers and key operators developed guidelines to optimize operating practices and BHA design for various CTD applications. This paper will share some of these experiences and lessons learned with a focus on harsh drilling environments based on an e-line controlled CTD system (Figure 1). Underbalanced Drilling / Multiphase Flow One of the most challenging drilling environments is under balanced drilling. For underbalanced drilling with single phase flow light drilling fluids (e.g., crude oil, diesel and other oil-based muds) are often used. These fluids are highly reactive and damaging to all elastomer components and could limit the BHA's reliability and durability. In the project planning phase, it is critical that the various BHA components be matched to the specific drilling fluid. Multi-phase fluids, in particular a mixture of Nitrogen and the drilling fluid, can create elastomer damage due to swelling as well as high vibrations that could cause low hour failures on electronic components. High Vibrations in multi-phase flow Drillstring dynamics, hole cleaning and weight transfer problems are limiting factors in CTD applications. The reasons for drillstring vibrations are mainly due to the engagement of the bit with the formation and the contact of the BHA with the borehole wall. Those vibrations generate axial, lateral and torsional movements.
- Asia > Middle East > UAE > Sharjah Emirate > Sharjah (0.66)
- North America > United States > Alaska (0.55)
- Africa > Middle East > Algeria (0.49)
- North America > United States > Alaska > North Slope Basin > Lisburne Field (0.99)
- Asia > Middle East > UAE > Sharjah > Oman Mountains Foldbelt Basin > Sajaa Field > Thamama Group Formation (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Oued Mya Basin > Hassi Messaoud Field (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Berkine Basin (Trias/Ghadames Basin) > Hassi Messaoud Field (0.99)
Improving the Efficiency of Gas-Storage-Well Completions Using Underbalanced Drilling With Coiled Tubing
Weber, James | Stilson, David William (Kinder Morgan Inc.) | McClatchie, Donald W. (BJ Services Co. Canada) | Denton, Stewart L. (BJ Services Co. Canada) | King, Lee Russell (BJ Services Company)
Abstract A key element of maximizing injection and withdrawal rates in gas storage fields is minimizing skin damage of the completions.A highly efficient completion technique can reduce the number of storage wells required to produce and refill a storage zone.It also reduces the cost of installation and operation of the compression equipment required to achieve commercial injection and withdrawal rates.The current completion methodology involves conventional overbalanced drilling through to the target zone.Casing is run and cemented from TD with communication to the reservoir achieved by perforating.Skin damage is typically reduced by flowback and acid stimulation of the well to remove drilling mud and filter cake.A different approach utilizing underbalanced vertical deepening, or "well finishing" with coiled tubing was employed in the Huntsman Storage Field, Nebraska and the Sayre Storage Field, Oklahoma in an effort to further reduce skin damage.The wells were conventionally drilled and cased to the cap rock of the storage zone then the final stage of drilling to TD was performed underbalanced by a coiled tubing unit.The storage zone was completed openhole. Introduction The United States contains over 3.8 tcf of natural gas in over 400 storage reservoirs which acts as a buffer between steady production and seasonal fluctuating consumption.[1]A key component of gas storage operations is maximizing the deliverability of a storage field either by increasing the number of wells or by improving the injection / withdrawal efficiency of individual well completions.This paper compares the conventional completion approach with the underbalanced well finishing technique.A comparison of initial well productivity, injectivity and withdrawal performance and total well cost is used to determine the most efficient completion technique.A total of seventeen wells completed in two separate storage fields using the underbalanced approach provides a large pool of data for detailed comparison with the hundreds of storage wells drilled and completed overbalanced. Formations Approximately 69% of gas storage reservoirs are sandstones and 27% are carbonates.The remaining 4% is a mixture of salt caverns and coals. [2] This case history focuses on sandstone gas storage reservoirs.High deliverabilities (injectivity and productivity) which make a formation ideal for gas storage are a characteristic of highly permeable (up to 1000 md) or fractured formations.Individual fields may have deliverabilities from 10 mmscf/d to 1.0 bcf/d.This very feature that makes reservoirs suitable for gas storage also makes them susceptible to damage from drilling fluids invasion and filter cake plugging. An example is the Huntsman Field, located on the northeastern flank of the Denver-Julesburg Basin.This field is part of a northwest trending anticline. The zone of interest is the Third Dakota "J" Sand at a depth of 4,850 ft. The majority of the reservoir is a channel sand of moderately to well sorted, fine grained sandstone interbedded with thin shale lamina. The surrounding floodplain consists of ratty sand, silt, and mudstone.The "J" Sand storage formation is 50 to 80 ft thick with porosities ranging between 18–22% and permeabilities ranging between 25 to 1,250 md.
- North America > United States > Nebraska > Cheyenne County (0.35)
- North America > United States > Texas > Kleberg County (0.24)
- North America > United States > Texas > Chambers County (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.74)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.54)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Sayre Field (0.99)
- North America > United States > Nebraska > Huntsman Field (0.99)
- (3 more...)
Abstract The concept of a tapered outside diameter coiled tubing system (TODCTS) was first presented in 2004.1 This paper laid out the basic requirements for a TODCT system and the advantages of the TODCTS in ultra-deep wells (30,000-ft range). The TODCT system includes:A modified injector that can handle more than one diameter of tubing and maintain a constant grip on the tubing throughout the length of the TODCT string. A "transition tube" that allows sections of tubing with different ODs to be joined together. Well-pressure control equipment (i.e., blowout preventer and stripper) that has the capability to grip and seal more than one diameter of tubing and can also grip and seal the transition tube. An operator control house that allows remote control of the stripper elements and injector gripper elements to open or close to different diameters of tubing while still maintaining control of well pressures inside the wellbore and grip on the tubing. This paper continues the work that was started previously. A review of the yard testing completed on the equipment is included along with a subsequent field trial done onshore in south Texas. The end result is a tested and qualified TODCT system capable of safely running tubing strings into ultra-deep wells. Introduction The basic concept of a coiled-tubing (CT) string using more than a single OD was introduced in 2004.1 Using the skills and efforts of an operating company, a service company, and equipment suppliers, a team approach was undertaken to design and develop a working TODCT unit. After extensive testing in both lab and yard testing, the TODCT unit was deployed to operate under field conditions in a well supplied by the operating company. The intent of this paper is to report the results of this testing and discuss future testing and development of TODCT. Background of TODCT In current CT operations, the OD of the tubing string has always been constant within a single string of tubing. As a result, CT equipment designers have assumed that the OD would not change significantly within any given string. The following are examples of this assumption made in current equipment designs:Support surfaces for the injector/tubing interface are flat and linear to maintain an even gripping force along the length of the injector/tubing interface. Gripping surfaces for the injector/tubing interface are size-specific. Changes in tubing size require that the gripping surface in the injector/tubing interface be changed to match the size of the tubing. The hydraulic fluid in the cylinders providing gripper force for the tubing string is "locked off" from the rest of the hydraulic circuit during operation. The primary purpose of locking off the hydraulic fluid is to maintain hydraulic gripping force on the tubing string in the event of a loss of hydraulic pressure from the power source. The practice of locking off the oil in the gripper circuit cylinders assumes that during operation of the unit, the cylinders will not extend because of changes in tubing size The practices discussed in the previous example also apply to the stripper circuit because this circuit also uses the lock-off philosophy to maintain pressure in the event of a loss of hydraulic power. Stripper/packer elements are designed to fit a specific diameter tubing (i.e., 1.5-, 1.75-, 2.0-in., etc.). If tubing size changes, it is expected that the stripper/packer element and supporting brass will be changed to match the size of the tubing. BOP slip and pipe functions are sized to fit a specific diameter of tubing. As with stripper/packers, it is expected that a change in tubing size will require a change-out of components within the BOP assembly.
Abstract This paper reports the field results obtained from application of a system that provides both pre-job modeling capabilities and real-time monitoring of maximum stress levels in the entire intervention stack, from the wellhead to the injector assembly.In addition, the paper documents the dynamic movement capabilities recently incorporated in the model and validation of the model calculations. Introduction Reference 2 discusses an intervention riser safety system which has become known as the ? (Zeta) Safety System.This paper documents further development and testing that has been done with this system.The system is composed of two basic components:?model - a numerical dynamic simulation model which models the stresses in an intervention stack. ?gauge - a lubricator spool, instrumented with fiber-optic strain gauges, is placed in the intervention stack. It measures axial force, internal pressure, and bending moments in the spool. The initial coiled tubing (CT) field application of this safety system was performed to satisfy several primary objectives, including:Validation of modeled calculations versus field data measured by independent devices Sensitivity of the field stress measurements provided by the system Confirmation that system design and calibration is sufficiently robust for routine field applications The ability to accurately model dynamic movement of two independent structures was driven by increased utilization of floating structures (TLPs and Spars) being deployed in deepwater projects.The tethered topside structure typically exhibits some amount of horizontal displacement in a figure-eight pattern as a result of wave motion, with the wellhead exhibiting a similar displacement pattern but with differing frequency and amplitude.The intervention stack may experience increased stress levels when each end of the rigid lubricator/riser assembly is attached to these two independently-moving bodies.A dynamic modeling capability incorporated in this model addresses these field conditions. In addition, offshore intervention stacks are becoming taller to accommodate offshore floating structure size, and often pass through multiple deck surfaces that constrain lateral stack movement.This can create a condition whereby conventional safety limits are exceeded.While counter intuitive, removal of lateral stack constraints may actually increase the safety of a given stack.Another finding is that the maximum stack stress may occur in situations where no CT hanging weight is applied to the stack. The pre-job modeling capabilities of the system are used to optimize intervention rig-up design and to determine the probability of exceeding pre-set safety limits during the operation.During the field operation, real-time stress values provided by the system enable informed decisions, rather than a judgment call, to be made if maximum stress levels are approaching unsafe limits.
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (0.70)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (0.49)
Abstract This paper presents the results from series of experiments performed to study the effect of coiled tubing (CT) curvature on friction pressure loss of nitrogen gelled foam fluids. A ?-in., 10 ft of straight tubing and four sets of coiled tubing with curvature ratio (r/R) values of 0.01, 0.019, 0.031, and 0.075 are used in the experiment. A set of tests are performed using 20 and 30 lb/Mgal xanthan gum as base fluid and 0 to 80% quality nitrogen xanthan foams. Friction pressure data are gathered by monitoring the pressure drop across a 10-ft straight section and a given CT simultaneously.All data are gathered at ambient conditions and at a system pressure of 1000 psi. It is found that the friction pressure losses of nitrogen gelled foams in CT are significantly higher than the straight tubing even at low Reynolds number.The extent of CT curvature determines the magnitude increase in friction pressure loss. Empirical correlations for the prediction of friction pressure loss of gelled foams in both the straight and coiled tubing are developed for laminar, transition and turbulent flow regime.These are based on the dimensionless quantities of Fanning friction factor and generalized Dean number. Introduction Foam fluids have found several applications in the petroleum industry1 due to their favorable properties which can be exploited during drilling, well completion, wellbore cleanout and stimulation operations. Foams are compressible two-phase fluids formed when a large internal phase volume, typically 55 to 95 percent (usually air, N2 or CO2) is dispersed as small discrete entities through a continuous liquid phase[1]. Foam flow behavior in straight pipe and its rheological characterization has been extensively studied. The rheological character of foam fluids is quantified using foam characteristics such as foam quality, foam texture and foam stability[2]. Investigators agree that foam quality, i.e. volume fraction of dispersed-phase in continuous-phase influences the rheological characteristics of foam fluids. Blauer[3] et al divided range of foam quality on the basis of bubble interaction. It was observed that below 52 percent foam quality, spherical bubbles are well dispersed and do not interact with each other. Foams with qualities between 52 and 74 percent have bubbles closely packed and cause interference to flow. Between qualities 74 and 95 percent, bubbles must deform to make foam fluid flow and thus maximum viscosity is attained in this range. At qualities higher than 95 percent foam is no longer stable and gets converted to mist and causes a reduction in viscosity. Reidenbach et al[4] performed experimental study with aqueous and hydroxypropyl guar (HPG) gel foams to rheologically characterize foam fracturing fluids using nitrogen and carbon dioxide as dispersed phase. HPG gel foams were characterized using Herschel-Bulkley model while aqueous foams were characterized with classical Bingham plastic model. They concluded that the flow behavior index, n, of foam fluids is the same as that of liquid phase, while the foam consistency index is a function of liquid phase consistency index and foam quality. They observed that the apparent viscosity behavior of nitrogen foams and carbon-dioxide emulsion is very similar which led to the conclusion that the two phase structure for both fluids is very similar. Harris and Reidenbach[5] performed experimental study using recirculating foam flow loop to investigate the rheology of nitrogen foam at 1000 psi and at temperature up to 300oF. Hydroxypropyl guar (HPG) was used as liquid phase. They observed that foams behave as yield-pseudoplastic and can be described by Herschel-Bulkley model. Saintpere et al[6] investigated the rheological properties of aqueous foams for underbalanced drilling. Rheological characterization of gelled foams with polyacrylamide (PAA) and xanthan was performed at ambient temperature using parallel plate geometry. They observed wall slip effect which was corrected by using grooved plates. It was observed that apparent viscosity of foams is a function of quality, texture and polymer content in liquid phase. They also characterized foams as yield-pseudoplastic that can be represented by a Herschel-Bulkley model. Philips and Couchman[7] studied carbon-dioxide foam properties using high temperature (250oF), high pressure (1000 psi), pipe viscometer. They observed that increasing the gelling agent concentration improves the stability of foams. Nitrogen and carbon-dioxide foams behave differently and rheology data for one fluid is insufficient to describe behavior of the other. The laboratory generated foam rheology and stability data were used to design fracturing treatment and fluid composition. Success and contrasts of such designs were compared with the historical treatments in several tight gas sands. Khade and Shah8 performed experiments by flowing guar foam fluids through pipe viscometer at temperatures from 100 to 200oF and at 1,000-psi pressure. They characterized guar gelled foam fluids as pseudoplastic. They studied the effect of base gel concentration, quality, and temperature on apparent viscosity of foam fluids. Empirical correlations were proposed to predict the consistency and flow behavior indices of guar foam fluids.These correlations are function of liquid phase properties, temperature, and foam quality.
Abstract Drilling and workover rigs use a drawworks to pull up on the tubulars deployed into a well. The drawworks is attached to a mast or derrick, which in turn is supported by the ground or a floating vessel. The tubular's weight is not transferred to the wellhead. Coiled Tubing uses an injector head, instead of a drawworks, to pull and push tubing in and out of a well. The injector is generally mounted directly onto the wellhead, unavoidably transferring some of the reactive loads to the wellhead. These loads can be very substantial. They not only include the tubing's weight in the well but also loads generated by the Coiled Tubing on surface, that tubing which is being bent and pulled sideways. Often additional support is required to at least partially isolate these loads from the wellhead. This paper identifies the various loads that Coiled Tubing imparts to a wellhead and how support mechanisms provide protection to the wellhead. Introduction General industry practice is to connect Coiled Tubing injectors directly to a wellhead stack. This stack typically includes blow out preventers (BOP's), flow tees and risers, mounted directly on top of a Christmas Tree, a casing flange, a tubing hanger or a drill pipe stub. Connections between the injector and the well itself are generally flanges or some form of quick union. In the absence of any secondary support device, all the loads applied by the injector to the Coiled Tubing entering or exiting the injector, need to be supported by the wellhead. How the forces applied to the Coiled Tubing are transferred to the wellhead is shown in Figure 1. Historically, simple chains have been used to anchor the injector, preventing it from moving laterally and thereby bending the wellhead stack. Increasingly, much more rigid frames are being used which are designed to stop the injector moving relative to the wellhead. These frames transmit bending loads to the ground or platform rather than onto the wellhead. This paper will describe how the support systems work and show where the systems do not protect the wellhead.
Abstract Removal of scale depositions from wellbore tubulars has always posed a challenge to operators. Traditional methods to do so have included chemical treatments, mechanical methods, or even removal of affected tubulars. All of these methods have varying degrees of success, as well as varying cost to operators depending on the type and amount of deposition in the tubulars. Barium Sulfate scale removal has traditionally posed the greatest challenge to operators and service companies alike. Chemical soaks have been developed and applied as well as mechanical methods, usually meeting with limited success. As a result of these failures, a dependable, engineered and cost effective approach has been developed. The process combines the use of traditional coiled tubing operations and a high-pressure rotary jetting tool to remove the Barium Sulfate scale - without use of solvents. The process has been successfully utilized to completely remove over 9,000' of Barium Sulfate scale in subject wells that have not been effectively cleaned when tradition methods have been tried. This paper will look at well conditions conducive to the formation of barium sulfate scale, as well as why it is such a difficult material to remove. Coiled tubing solutions will be discussed, culminating in a collection of case histories where a unified mechanical / jetting program has had best results. Introduction Barium sulfate scale is one of the most problematic scales that oil and gas operators have to deal with.With no known chemical treatments for rapid dissolution of the material, other removal techniques are typically called upon, usually incorporating some mechanical rather than chemical solution. Mechanical methods have, however, limitations which prevent them from either succeeding, or removing 100% of the scale.Therefore a "unified approach" has been adopted - with positive results.This unified approach incorporates two different CT operations, one following right after the first.The first run involves using an appropriately sized drilling motor and bit, the second uses a unique high energy rotary jetting system. This methodology has proven itself to be very effective in field applications. Barium Sulfate Scale Barium sulfate scaling occurs in oilfield wellbores throught the world, and has been identified at least as far back as 1914, in the Saratoga Field, Texas(1).Of all the various wellbore deposits, barium sulfate tends to be the most problematic due to its relative insolubility in most known solvents, and its strong mechanical properties.Progress has been made in the development of specialized chemicals addressing barium sulfate dissolution, but typically, these require long soak periods to be effective.Depending on the location and configuration of the scale, as well as a number of well details, operations requiring extended fluid contact time often are just not practical.Therefore, removal methods usually have to involve an aggressive mechanical solution.
Multilateral/High-Pressure Jet-Wash Tool System Successfully Employed in Multilateral Wells
Lesinszki, Allan (Talisman Energy Inc.) | Stewart, Clarence (Talisman Energy Inc.) | Ortiz, Avel (Schlumberger) | Heap, David (Schlumberger Well Services) | Pipchuk, Douglas A. (Schlumberger) | Zemlak, Kean James (Schlumberger)
Abstract Multilateral wells provide optimal recovery of reservoir pay and can become more prolific with stimulation or cleanout treatments.Downhole tools exist that index and allow the coiled tubing string to find and enter additional legs; however, they function using flow rate modulation.Any additional tool component beneath the multilateral tool that requires high pressure will suffer in performance because of the indexing multilateral tool.This technical paper addresses the performance of a new system that allows the indexing tool to find the lateral and then effectively treat the reservoir through the stimulation tool at the end.The entire cycle can be repeated for all laterals in the wellbore. The results of field tests using this multilateral jetting system were similar to what was seen in yard tests perform at test facilities in Rosharon TX.Field tests showed that operating parameters produced clear indications that the system was operating correctly.All legs were efficiently and effectively treated to improve well production.Additionally, this system reduced the number of trips into the well from three to one, resulting in a 50 % reduction of time at the client's well site. Introduction Advances in multilateral drilling, completion and remedial technology promise reduced costs, greater flexibility and increased profit potential.In the last 10 years, thousands of multilateral wells have been drilled worldwide.However, this is still only a small percentage of the total number of wells drilled.Lack of concise information and misconceptions surrounding the costs and perceived risks have conspired to hinder large-scale implementation. However, recent advances in the capabilities of the systems and applications have proved multilateral drilling, completion and treatment to be a truly revolutionary and cost-effective solution for the industry. What makes this revolutionary?Simply put, multilaterals provide options that help mitigate adverse economic climates and operating conditions.Stiff decline rates have compelled key industry decision makers to renew their reservoir management efforts to increase the productivity of fields and wells during their entire economic lives.In saying this, an effective stimulation treatment in multilateral wells has proven difficult over the years. Technologies have been developed to successfully enter multilaterals without the aid of complex completion hardware; however pairing this with advanced jetting/fluid placement technology has allowed for effective stimulation of multilateral wells. In this paper, testing results and a case history will be reviewed where two technologies have been paired to successfully enter a multilateral and place a treatment, enabling improved production with a cost effective solution. Well Type & Formation Characteristics The field and formations utilized for trial use of the new system was the Mississippian reservoir of the Turner Valley.The structure consists of two porous units within the dolomitic lithofacies of the Rundle Group know as the Upper Porous and Lower Porous units.These units are characterized by dolograinstones and dolopackstones with porosity types consisting of primary intergranular, secondary moldic and fracture porosity ranging from 3–12%. The optimal drilling profile used by Talisman Energy in the Turner Valley field primarily consists of two-legged horizontal wellbores targeting the Upper Porous and Lower Porous units separately.As historical data suggests these two porosity units are compartmentalized and not in communication thus requiring the need for multi-legged completions.
- North America > Canada > Alberta (0.34)
- North America > United States > Texas (0.28)
- North America > Canada > Alberta > Turner Valley Field (0.99)
- North America > United States > Texas > Meramec Formation > Meramec Formation > Mississippi Chat > Mississippi Lime > St. Louis Formation (0.98)
- North America > United States > Texas > Meramec Formation > Meramec Formation > Mississippi Chat > Meramec Formation > St. Louis Formation (0.98)
- (22 more...)
Abstract As the number of deepwater installations increase, so will the number of coiled-tubing (CT) operations that are needed to support these deepwater fields. This need will grow significantly as rigs on spar platforms and tension leg platforms (TLP) are eventually demobilized for work on new installations, leaving CT as the most economical option for performing future well maintenance on these platforms. The need to operate without a rig is a critical factor in the success of future coiled-tubing work in the deepwater environment. Rigless operation is complicated by the fact that each platform type has its own unique heave-compensation issues that must be addressed for an effective CT operation to take place. An additional challenge to deepwater CT operations has been the assembly and installation of tension lift frames or heave-compensated jacking frames. This equipment is typically cumbersome and time-consuming to install and has many safety-related risks associated with the installation of coiled-tubing components. A new coiled-tubing heave-compensation system has been created to address issues associated with rigging up and operating coiled tubing on deepwater installations. This system was designed with particular focus on operational safety and efficiency to meet the complete range of floating platform coiled-tubing deployment scenarios. There are three primary modes of operation. As a stand-alone system, it can operate as a heave-compensated jacking frame; with a rig, it can operate as a standard tension lift frame or as a self-compensating tension lift frame. The adaptive heave-compensation system uses automated process control to maintain wellhead loads within the American Petroleum Institute-specified allowable stress limits. A specially designed proprietary titanium flex joint incorporated in the system reduces the effect of lateral loads and bending moments transmitted to the wellhead. The total heave-compensation package is composed of three skids (injector tension frame, blowout preventer (BOP) tension frame, and hydraulic power unit). The injector, gooseneck, and all well control equipment come preassembled within the injector and BOP tension frames. This improves the overall efficiency of the rig-up and eliminates most safety issues associated with the rig-up/rig-down process. The heave-compensation system not only improves the efficiency of the rig-up process but also makes tool changeouts more efficient. The initial field test data and the associated job case history establish the benefit that this new heave-compensation system has brought to the deepwater market. Introduction In April of 2002, at the request of several deepwater operators, a newly initiated study focused on improving the performance of coiled-tubing surface equipment to meet the growing demands of the deepwater market. There was a need for a new type of heave-compensation system that would allow horizontal and angular movement of wellheads on TLPs. The added capability to perform coiled-tubing work outside of the rig or even without the rig while mitigating the stress on the wellhead connection was also desirable. An improved system would address heave issues on multiple types of platforms including spars, semi submersibles, drill ships and TLPs. Understanding the value to the future of deepwater coiled-tubing operations, it was decided to pursue a heave-compensation system design that could meet the demands of wellhead movement on TLP platforms. The new system represents a complete solution for addressing heave complication issues on spars, semi submersibles, drill ships and TLPs.
Abstract Wellbore cleanouts represent the main application of coiled-tubing (CT) services. Despite a long history of utilizing CT to remove sand and other fill material from oil and gas wells, advancement in the technology, and a growing body of experience, many wells are still not cleaned adequately, some wells cannot be cleaned at all, and a downhole stuck CT or other serious problems are encountered too often. Based on gathered experience and extensive research and development of new tools and techniques, a new, highly engineered and integrated system for wellbore cleanouts was developed. This paper presents the new integrated system approach, which can eliminate wellbore fill-removal problems and provide effective wellbore cleanouts under virtually any wellbore conditions. Case studies are included that show the performance of the new system in difficult field environments. Introduction The removal of fill material (well-produced sand and fines, proppant, etc.) from producing wells has been the most common application of CT services. The primary reason for wellbore fill removal is, generally, to restore the production of the well. Additionally, fill removal may be necessary to permit the free passage of wireline or service tools, or to remove material that may interfere with subsequent well service or completion operations. Wellbore fill removal is frequently considered inadequate, leaving large quantities of fill material in the well, which often requires repeating well cleanouts within relatively short time intervals. Additionally, wellbore cleanouts are extremely time-consuming, preventing timely return of wells to production and increasing the cost of well maintenance. Many wells, such as large-casing, higher-temperature or very deep wells, cannot be cleaned at all with older technology. In this study, theoretical and experimental work was performed to understand the behavior of particles (sand, bauxite, etc.) that are transported by a cleanout fluid. A wide range of cleanout conditions were studied. The study included comprehensive experiments in 3.5-in. and 7.0-in. transparent flow loops at various deviation angles, and a range of cleanout nozzles, fluids, and procedures at realistic flow rates. A long flow loop was used to determine the ability of various fluids to transport solids over long distances. In addition to a better understanding of particle transport phenomena, the main result of the study was development of a highly engineered, integrated system that can effectively clean the entire wellbore fill from most difficult wells. The new system consists of improved cleanout nozzles, specialized fluids, an enhanced analytical model and software for simulating the cleanout process under specific well conditions, and a system for monitoring particle returns at surface in real time. This paper presents the main theoretical and experimental work along with major findings from this study. Some major misconceptions about wellbore cleanouts are presented and explained. Additionally, case studies are provided that illustrate results from the integrated system in a multitude of field applications. Background Removing wellbore fill, such as formation-produced sand and fines and/or proppant left over from fracturing operations, was one of the first applications of CT services. It also has been the largest CT application, approaching 50% of all CT operations industrywide. CT cleanout technology has gradually evolved in an effort to keep up with developments in well design and the increased complexity of wellbore conditions, such as higher well deviations, deeper wells, larger completions, and higher bottomhole temperatures. New equipment, tools, fluids, and cleanout methods have been developed to keep up with a constantly increasing degree of cleanout difficulty.