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Collaborating Authors
SPE/ICoTA Coiled Tubing Roundtable
Abstract A new high-pressure coiled-tubing (CT) drilling system has been developed with support from the DOE that drills 2 to 3 times faster than conventional CT motors. Downhole motors have been developed that utilize diamond thrust bearings, titanium flexshafts, high-pressure rotor/stator sections and other advanced features that allow these motors to operate at high pressures. Laboratory tests have been conducted using the high-pressure system to cut 1 to 2 inch deep helical slots in wellbore walls to remove formation damage (patent pending) and to drill cement out of drillpipe at rates up to 1,400 ft/hr compared to 60 ft/hr for conventional motors. This jet-drilling system can also be used to remove barite scale from tubing, to clean slotted liners, to ream holes at high rates, and to under-ream when drilling with casing. The high-pressure system will be field tested and commercialized during the next phase of this DOE project. Introduction Maurer Engineering Inc. (MEI), under contract to the United States Department of Energy (DOE), has completed laboratory testing of a high-pressure CT drilling system. The system is now ready for field trials. High-pressure (10,000 psi) jet drilling systems have shown they can drill oil and gas well at high rates, but they have not been commercialized due to problems with leaking drill-pipe tool joints. CT is a continuous reel of tubing that contains no connections and therefore eliminates leakage problems associated with drillpipe. This feature offers the opportunity for successful implementation of high-pressure drilling. MEI developed a special high-pressure motor for use with the high-pressure CT drilling system and has successfully completed laboratory tests of critical components. With jet assisted drilling, high-pressure jets cut kerfs into rock ahead of the bit and then mechanical cutters break the rock ledges between the kerfs (Figure 1). Jet assisted drilling has the potential to significantly increase penetration rates in many formations. Figure 2 shows the results of laboratory drilling tests conducted for the Air Force in 19861 where jet-assisted bits drilled at 1000 ft/hr compared to 300 ft/hr for conventional drilling motors and 100 ft/hr for rotary drills. Figure 3 shows the high-pressure CT system. The two critical components of the system are the downhole motor that must operate at 10,000 psi and the CT that must not fatigue at high operating fluid pressures. MEI developed a Moineau motor that operates at 10,000 psi (Figure 4). This motor uses diamond thrust bearings to absorb the high loads caused by the pressure drop across the bit. A proprietary rotor/stator design is used that allows the motor to operate at high pressures. Additional design details on the high-pressure motors are presented in the ASME paper ETCE2000/Drill-10098. Coiled Tubing As coiled tubing (CT) is reeled on and off the reel and over the gooseneck, it yields and eventually fails from fatigue. Fatigue life of the tubing is significantly reduced when CT is operated at high pressures. Grades of CT readily available today will fail after about 50 to 90 cycles when operating at 10,000 psi pressure. Therefore, improved CT had to be developed for use with this high-pressure drilling system. Quantity Tubing worked with MEI to develop QT-1200 CT, which provides much longer fatigue life than conventional grades. The new tubing was extensively tested on the fatigue machine shown in Figure 5. The laboratory tests showed that QT-1200 CT will operate for 240 cycles at 10,000 psi before it fails, compared to 90 cycles for QT-1000 tubing (Figure 6). In addition, other manufacturers have developed composite CT that will operate at 10,000 psi pressure for over 1000 cycles without fatigue failure.
- Geology > Mineral (0.56)
- Geology > Rock Type > Sedimentary Rock (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.89)
Abstract In the past, tubing, casing and drill pipe recovery has been employed where chemical and explosive severing tools could not effectively sever the pipe. A coiled-tubing-conveyed hydromechanical pipe cutting system has proven to be a viable alternative to pipe recovery when conventional severing systems are not effective. The system does not contain or require any hazardous materials, which makes it safer to use than conventional systems. The pipe cutting system incorporates modular stabilizing devices that decrease the risk of the coiled tubing forces and the wellbore deviation from interfering with the cutting operation. The pipe-cutting mechanism uses several unique blade configurations that were designed specifically to address various metallurgical properties and dimensions. The cutting blades contain state-of-the-art cutting inserts, which were previously proved in various metal milling and cutting applications within subterranean wells. A detailed description of the coiled-tubing-conveyed hydromechanical pipe cutting system, its operational function and a variety of case histories are discussed in this paper. Introduction Electrical wireline-conveyed explosive jet and chemical cutters are currently the preferred choices for cutting pipe in slimhole wellbores. Explosive jet cutters are used for severing common sizes of production tubing, drill pipe and casing. The cutting action is produced by a circular-shaped charge. Typically, this type of cutter leaves a flare on the severed pipe string. In order to perform subsequent pipe recovery operations, it is necessary to smooth the top end of the tubing left in the wellbore with an internal mill insert that is usually run with an overshot. Chemical cutters are designed to cut through one string of pipe while not damaging the adjacent string. They produce a flare-free and undistorted cut. The topside of the severed pipe can be engaged with an overshot without dressing with a mill. A wireline-conveyance operation provides several advantages when compared to using coiled tubing and threaded pipe. Wireline equipment can be mobilized and disassembled quickly; the wireline can be run in and out of a hole much faster; and the cost of a wireline operation is usually less than other methods. The success rate can be reduced, however, when wireline-conveyed cutting tools are used for exotic applications such as cutting through plastic coated or corrosion-resistant alloys. High-density wellbore fluids, a greater-than-standard pipe wall thickness and distance between the cutter and the internal wall of the pipe also reduce the effectiveness of the wireline-conveyed systems. Another drawback is that the wireline systems are designed to cut only one string of pipe per operation. Therefore, several trips into the wellbore are required to separate multiple, adjacent strings internally. The limitations of wireline-conveyed cutters can be overcome for the specific applications noted above with a hydromechanical pipe cutting system (HPCS) that takes advantage of proven, downhole metal cutting technology. The HPCS is activated by weight or hydraulic pressure. It can be rotated by a downhole workover motor or from the surface using a rotary rig or power swivel. The HPCS provides the power needed to cleanly cut single or multiple strings of pipe downhole. Such non-distorted pipe cuts are especially beneficial when it is necessary to recover pipe that is stuck in open hole. Time is a critical factor for a successful pipe recovery operation. The quicker the fishing jar assembly can be employed the greater the chances of a successful pipe recovery operation. The clean top of the severed drillpipe left by the HPCS improves efficiency in employing the fishing assembly. History Until the early 1990s, very few pipe-cutting operations were attempted using coiled tubing as a conveyance means.
- Well Drilling > Drillstring Design > Drill pipe selection (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well Intervention (1.00)
Abstract Coiled Tubing is a common method of diverting treatment fluids into wellbore formations in open hole and cased hole completions. The efficiency of the treatment can be significantly improved by increasing the impact force of the fluid on the formation. The recently developed JetBlaster™ Tool has been used on some cases as the optimum BHA that can be used with Coiled Tubing for the efficient delivery of treatment fluids. The software JetADVISOR supports system hydraulic analysis and the design of the tool configuration in terms of nozzle and orifice diameter. This allows optimization of jet impact force or hydraulic horsepower, and ensures a sufficiently high rotational speed to effectively divert the treatment around the circumference of the wellbore. The addition of velocity increases the affectivity of the treatment. In order to assist evaluation of the efficiency of the technique we have primarily attempted to treat a well that had formation drilling damage with the tool while pumping a non corrosive fluid that has no direct chemical reaction with the formation filter cake. The well was then put on the test to see the increase in production and wellhead pressure and the results recorded and compared. Then the same treatment was repeated but while jetting acid, then the well was once again put on test. Introduction The use of Jetting technology for oil well drilling systems and for other downhole applications has been widely reported. In recent times, drilling technology has revolutionized well designs. The majority of wells are now drilled horizontally thus exposing a relatively large reservoir area for drainage or injection. More recently the use of jetting technology to deliver acid treatment fluids effectively in long open hole horizontal well sections have been developed. The main advantage perceived is the delivery of acid over the entire length of the section giving effective filtercake breakdown and in the case of carbonate reservoirs dissolution of the reservoir rock to enhance production. The use of water jets has also been considered for removal of filtercake and to possibly generate new fractures and flow paths in carbonate formations. This paper will discuss in detail a field study of the effectiveness of the technology and how to optimize the operating condition. As the horizontal wells usually have long open holes, the use of acidization to remove drilling damage requires large volumes of acid. As a result acidization is very expensive. The acid utilization can be very inefficient if most of the acid leaks into thief zones. ADCO introduced the concept of effectively removing formation damage and drilling mud filter cake by applying jetting techniques compared to conventional coiled tubing acid treatment methods used previously. A well (A) was selected as a typical candidate for the trial. The well had recently been drilled as an oil producer, with a 2000 ft of horizontal open hole section. The horizontal section was treated with Enzyme after drilling and a subsequent initial PBU evaluated to show evidence of damage, with a skin of +3.7 recorded. It was proposed to treat the well in two stages:simply jetting treated water ie: water & surfactant as a primary treatment. Jetting with acid. Evaluation of the first stage of the treatment could only be performed from surface pressure and rate data, as it was impractical to conduct a PBU before the second stage of treatment.
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Well Drilling > Drilling Operations > Directional drilling (0.89)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.68)
Abstract A large number of Mærsk Olie Og Gas AS completions in the Danish Sector of the North Sea utilise Sliding Side Doors (SSD's) as a means of zonal isolation. As the majority of the completions are in highly deviated / horizontal wells, these sleeves are manipulated by shifting tools on coiled tubing (CT). Experience has shown that the operating of SSD's on coiled tubing can lead to uncertainties in the true status of the sleeve position. Several cases have arisen where subsequent Memory Production Logging Tool (MPLT) surveys have identified SSD's that were not in their expected status. Though MPLT's were successful in the determination of SSD status, operational and cost considerations required a new approach. What was required was a reliable, accurate means of verifying SSD sleeve position with data acquired on the same run as the sleeve manipulation tool. There were two strands to this project, the proof of concept in the ability to identify sleeve position using Memory Casing Collar Locator (MCCL) data, and the development of a "stand-alone" MCCL tool, rugged enough to be run in conjunction with the SSD manipulation tools. Background Memory Casing Collar Locator (MCCL) tools have long been used as a simple indicator as to the position of tubular connections during runs in hole. In this usage they are limited to providing depth correlation. The tool output has purely been regarded as a "twitch" that occurs as the tool passes changes in wall thickness. Very little attention is usually given to the quality of the tool data providing the magnitude of the signal is adequate to provide a depth correlation. A large number of Mærsk Olie Og Gas AS completions in the Danish Sector of the North Sea utilise Sliding Side Doors (SSD's) as a means of zonal isolation. As the majority of the completions are in highly deviated / horizontal wells, these sleeves are manipulated by tools on coiled tubing (CT). The sleeve manipulation toolstring typically includes an up and down shifting tool, dual acting impact hammer and jars. Experience has shown that the operating of SSD's on coiled tubing can lead to uncertainties in the true status of the sleeve position. Evidence for successful manipulation of the sleeve was based purely upon measurements of tension from the coiled tubing unit at surface. These measurements are subject to variables induced by: an extended horizontal reach, well deviation, and scale/debris accumulations. Several cases have arisen where subsequent Memory Production Logging surveys have identified SSD's that were not in their expected status. The chief indicators of sleeve position from these Memory Production Logging surveys were the spinner and temperature responses. With the well on flow, the ingress of production fluids through an open sleeve can easily be identified from the tool data. Such surveys are primarily run prior to any SSD manipulation to determine fluid production characteristics both quantitatively and qualitatively. The programs involve the recovery of the Memory Production Logging toolstring, the analysis of the data for effective water and or gas shut-off strategies, and then running back in hole with coiled tubing conveyed sleeve shifting tools. It is not possible to manipulate the sleeves whilst the Memory Production Logging string is in hole. Firstly the sleeve shifting strategy required the Memory Production Logging data be recovered to surface, secondly the Memory Production Logging tools are too fragile to accommodate the shocks induced by the sleeve shifting operation. As such the use of Memory Production Logging tools to ascertain successful sleeve configuration require separate runs subsequent to the sleeve manipulation run. This option is considered expensive in terms of the additional run in hole with it's inherent risks, deferred production, coiled tubing costs and logging tool run charges. The required tool needed to be reliable and able to accurately verify SSD sleeve position with data acquired on the same run as the sleeve manipulation tool run. In addition, it was desired that the running of the tool, and the analysis of the data, should be undertaken by non-specialist personnel.
- Europe > United Kingdom > North Sea (0.45)
- Europe > Norway > North Sea (0.45)
- Europe > Netherlands > North Sea (0.45)
- (2 more...)
Abstract In many wells it is advantageous, both economically and operationally to perform stimulation techniques using coiled tubing. More often than not this process will require that the zone of interest be isolated for the treatment to be effective. Several basic means of isolation are available depending on whether the application requires intervention through tubing or into a monobore, or "tubingless", completion. These basic tools require some form of pipe manipulation to set and retrieve, which in straight holes presents little difficulty, but in deviated wells becomes problematic. As the deviation from vertical increases and eventually reaches horizontal, tool manipulation becomes increasingly difficult and eventually impossible. To address this problem in highly deviated wells a new generation of downhole straddle tools has been developed which requires no pipe manipulation to set and retrieve. These tools, called Fluid Velocity Set devices, use fluid pressure build up created when pumping through a nozzle to activate and relaxation of that pressure to deactivate a tool. Two distinct types of tool have been developed:Inflatable straddle packers for through tubing applications, which can be inflated to seal in an I.D. up to 2.5 times larger than the running O.D. Mechanical straddle packers for monobore applications, which have a running O.D. small enough to pass through standard tubing mounted accessories, such as landing nipples and sliding sleeves, and set in the tubing I.D. This paper will discuss the advantages and disadvantages of commonly used isolation methods and will detail the design, development and testing of these new tools. Using recent field tests the authors will illustrate that this type of tool provides a functional and cost effective method of isolating zones in highly deviated and/or horizontal well sections. Background In recent years, the oil industry has been utilizing more highly deviated and horizontal wells, in order to more adequately and economically produce formations. This has in turn presented the Service Industry with many new challenges, not the least of which is the operationally and cost effective stimulation of the resultant well sections. One of the most effective and economical methods employed is the use of coiled tubing, which can be run in a live well, and, with the proper tools, can be used to isolate and treat zones. The original tools developed for zonal isolation were designed to meet the requirements of two distinct types of completion:the monobore completion, in which the productive zones are in well sections which have the same I.D. as the production tubing. The standard completion, in which the well is completed in casing and production is "thru-tubing" in nature. These requirements resulted in the development of several distinct tool alternatives to suit the two requirements:The opposed cup type tools (see fig. 1) required the same ID from the start of the tubing to the zone to be treated. The primary advantage of this type of tool was that it did not require manipulation of the coiled tubing to set and seal.However the cup type tool was also limited in the distance it could effectively travel in the tubing ID before resultant cup damage, due to the drag caused by the interference fit, resulted in impairment of its ability to seal. This situation was exaggerated by having to pass through tubing restrictions such as landing nipples and sliding sleeves and by the additional drag associated with highly deviated wells.
Abstract First, the paper gives a classification of the calculation models commonly used for the calculation of multiphase vertical pressure drops in oil wells. The main parameters of the experimental data used to develop the different empirical correlations are presented indicating the ranges where the correlations are expected to perform best. Next, an analysis and classification of the many possible causes of calculation error is given. Deviation of calculated and measured pressure drops is shown to stem from different sources that can have different importance from case to case. The author collected and summarizes in the paper the findings of the many previously published investigations on the accuracy of the different pressure drop calculation models. A table including all available data on calculation accuracies is also presented. Statistical parameters of these investigations are shown to be widely scattered and to be of limited use to engineers seeking the most accurate model. Differences and contradictions in the results are evaluated and explained. Finally, the author describes the petroleum engineer's proper attitude towards vertical pressure drop correlations. Practical implications of the proposed philosophy are also detailed. In conclusion, the paper provides the required insight and proper attitude to petroleum engineers facing the problem of predicting multiphase pressure drops in oil wells. Introduction The steady-state simultaneous flow of petroleum liquids and gases in wells is a common occurrence in the petroleum industry. Oil wells normally produce a mixture of fluids and gases to the surface and phase conditions usually change along the flow path. At higher pressures, especially at the well bottom flow may be single-phase but going higher up in the well, the continuous decrease of pressure causes dissolved gas gradually evolve from the flowing liquid resulting in multiphase flow. Even gas wells can produce condensed liquids and/or formation water in addition to gas. These are some of the reasons why multiphase flow in wells is a frequently occurring and important phenomenon. Multiphase flow is significantly more complex than single-phase flow. Single-phase flow problems are well defined and most often have analytical solutions developed over the years. Therefore, the most important task i.e. the calculation of pressure drop along the pipe can be solved with a high degree of calculation accuracy. This is far from being so if simultaneous flow of more than one phase takes place. The introduction of a second phase makes conditions difficult to predict due to several reasons. Friction losses, for example, are more difficult to describe since more than one phase is in contact with the pipe wall. In addition, due to the great difference in densities of the liquid and gas phases, slippage losses arise and contribute to the total pressure drop. Both of these losses vary with the spatial arrangement of the flowing phases (conventionally called flow patterns) in the pipe, etc. Multiphase flow, though, is not restricted to flowing oil or gas wells. Gas lifting, an artificial lifting method, involves injection of high-pressure gas into the well at a specific depth making the flow in the well a multiphase one. Other lifting methods like the use of rod or centrifugal pumps also involve a multiphase mixture present in well tubing. It is easy to understand then that the proper description of multiphase flow phenomena is of prime importance for petroleum engineers working in the production of oil and gas wells. It is the pressure drop or the pressure traverse curve, which the main parameters of fluid lifting can be calculated with, and which forms the basis of any design or optimization of well production. Thus the accurate calculation of vertical two-phase pressure drops not only improves the engineering work, but plays a significant economic role in producing single wells and whole fields alike.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract This paper describes scale cleanout jobs performed with Coiled Tubing offshore in the North Sea on 7 well for Phillips Petroleum Company Norway. The cleanout has been done by first perform milling runs with a standard PDM motor, then the completions jewelry has been cleaned by use of a jetting nozzle head with a metal to metal seal motor as a drive mechanism. In some of the wells multi-finger caliper has been run both before and after the cleanout. The caliper has confirmed a clean well. In others drift run has been performed and gas lift valves has successfully been replaced. An increased oil production from the wells is also achieved. Both Weatherford CTD PDM motors and the metal to metal seal Weatherford MacDrill motor together with the Weatherford MacJet head has proved to be strong and reliable tools for this kind of operations. Introduction In July 1999 the first scale removal with the jetting head and metal to metal motors was performed on well E-13 on the 2/4 E Tor platform, offshore for Phillips Petroleum Company Norway. From middle March to middle June 2000 a 5 well cleanout campaign on the 2/4 X platform was performed. The last well, A-13B on the 2/4 A platform in July 2000. The first and last well is done with 2" OD Coiled Tubing and the 5 wells on 2/4 X with 2 3/8" OD Coiled Tubing. The jetting method The new metal to metal seal motors has a higher-pressure drop over bit capacity, compared to standard PDM (moineau principle motor). This makes it a perfect drive mechanism to jetting heads. It can withstand more set down weights compared to other types jetting head, that's utilizes the jet flow as drive mechanism. Its gives all the supplied jet forces to remove scale, not to rotate the jetting head. The method does also only use water, no need for abrasives or chemicals to remove the scale. Operations summary The first well, E-13 on 2/4 E Tor Platform The object was to cleaneout scale, so the DHSV could be pulled and GLV installed in the two lower most SPM. See the completion schematic Fig 1. A 3" OD Broach was the largest OD able to run on W/L down to the DHSV, scale was tagged just below x-tree valves. A 2 1/8" OD metal to metal seal motor with a 2 3/8" OD jetting head dressed with crushed carbides and 2 ea nozzles were run down to a few feet above the DHSV nipple profile. Then a second run was done with the jetting head shaped as a bull-nose, with 2 ea nozzles in a 45° angle forward. This for cleaning the remaining feet's down and in the DHSV nipple profile. The DHSV was then pulled by W/L and a 2.26" OD broach was run on W/L down to the Model F nipple @ 11960 ft MD. A 2,5" OD broach was also run but not able to pass 630 ft MD. Two runs with a 2 1/8"OD jetting head dressed with crushed carbides and 2 ea nozzles were run to clean out the scale down to the production packer. A 2,8" OD sleeve stabilizer were run above the motor to verify the cleanout performance. Then 2,8" OD broach was run on W/L to drift the well and it was successfully run past the lower SPM, but it had to be worked over a few tight spots. An attempt to pull the two GLV's was done, but without success. One more cleanout run was then performed, this time with a 2 3/8" OD jetting head. On this run only the SPM were cleaned, and several passes were done past them. After this last cleanout both GLV's were successfully replaced without any missrun. A new DHSV was also installed successfully.
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
Abstract Coiled Oilfield Tubing (CT) continually finds new markets, and has experienced continued growth in extended reach wells and high-pressure service. One major improvement is in the quality possible at skelp end welds, when continuously tapered strip1 is employed to join strip of the same thickness. In this paper, the following are discussed:Tapered strip and tubing dimensional specifications at all points along the tubing. Design of CT employing continuously tapered strips. Effect of tapered wall thickness on theoretical fatigue life. Effect of skelp-end welds of the same thickness, as compared with those of conventional tapering, on overall string life. Suggested amount of tubing to be removed if needed during servicing operations. Introduction In order to support high loads and yet maintain high cycle life at skelp-end welds, continuously tapered strip is used in the production of continuously tapered CT strings. It possesses the following advantages over conventionally tapered tubing.Minimal loss in measured cycle life at gauge-to-gauge skelp-end welds, and thus an overall increase in cycle life along a string. Reduced ovality at skelp end welds, which has been a problem for tapered welds, such as 0.156 in - 0.175 in. Ease of manufacture in that no rapid changes are needed to mill set-up during the passage of a taper weld through the electric welder. Once the model for continuously tapered strip and tubing has been proved valid by measurement, then the following are possible:Acceptance of strings with continuous tapering for load, theoretical fatigue, and internal volume calculations may be validated. Determination of the amount of metal that may be removed when an imperfection is detected, within acceptable specification tolerances. This article covers the results of determining a model for continuously tapered strip, and discusses how the model is used to mathematically determine the above items. Acceptance of continuous tapering has been such that fully 90% of all possible orders for tapered well servicing strings have employed such material. Manufacture of Continuously Tapered Strip Strip is manufactured uniquely by rolling a slab of steel from dimensions such as 15 ft. long×40 in. wide×5" thick and weighing 40 tons, to values such as those shown in table 1. Figure 1 shows the continuously tapered strip purchase rolling requirement for the slab mill, illustrating 10% of the length at the two ends are held at constant but differing thicknesses (AB and CD), and a linear taper (BC) accounting for the remaining 80% of the length. With this accomplished, gauge-to-gauge strip bias (skelp-end) welds can be fabricated for an entire string, eliminating the need for step tapered welds.
Abstract This case-history paper presents details for a health, safety, and environmental (HSE) program, jointly developed by a service company and an oil company as part of an advanced, software-controlled, composite coiled-tubing, offshore drilling system. This drilling system can enable oil companies to economically harvest known hydrocarbon zones that were previously bypassed and to find and exploit new reserves. From the feasibility study forward, the latest HSE standards were incorporated into all phases of the project. The resultant Global HSE Program allowed access to the knowledge and experience of professionals from all parts of both organizations. This paper provides a detailed description of the national, cultural, engineering, and logistical challenges overcome during the development of the HSE Program. The paper also illustrates how teams from design, manufacturing, operations, maintenance, technical safety, HSE, quality verification, and management were unified for delivering a safe product. Included is an overview of the specific requirements necessary to fully define the unit for deployment in the Norwegian sector. The Historic Background HSE processes are often viewed as tasks that must be performed to keep customers and legislators happy. Despite the best intentions of the senior levels of the corporate body, the non-HSE personnel who work within the projects sometimes consider HSE processes constraining. However, times are changing, and many HSE professionals are starting to appreciate the benefits that a well thought out and constructive HSE program can bring. For many projects, a formal and rigid hazard identification and risk management process is essential because the first time that equipment is fully assembled and functional is in an operational environment with hydrocarbon contact. A similar hazard identification and risk management program was implemented in the advanced well-construction system (AWCS) project. The difference was that this project allowed the benefits of full testing of individual components, evaluation of the test program in a test well, and a complete function test of assembled components before offshore deployment. The designers, maintenance personnel, and equipment operators could exchange ideas and see the equipment perform in a controlled and risk-free environment. As a result, modifications were agreed upon and made within the early HSE program stages, optimizing equipment safety. An Introduction to AWCS In 1997, a service company and an oil company began jointly evaluating technologies that could be used to develop a revolutionary coiled-tubing (CT) and well-intervention system. This system, which will be deployed initially in the Norwegian sector of the North Sea, sets a new standard for drilling, whether conventional drilling rigs or CT drilling units are used. The system is centered around a new advanced composite coiled tubing (ACCT) with embedded wires that enable the geological steering of complex, extended-reach wellpaths that were not previously achievable. The system includes three major subsystems, digitally controlled and automated surface equipment, 2 7/8-in. ACCT with embedded wires, and the drilling and intervention bottomhole assembly (BHA). The hostile environment of the North Sea presents a number of offshore drilling challenges. The Norwegian government and the Norwegian oil company emphasize safety, and their statutory HSE requirements for offshore wells are among the most stringent in the oil and gas industry.
- North America > United States > Texas (0.47)
- Europe > United Kingdom > North Sea (0.44)
- Europe > Norway > North Sea (0.44)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > Norway Government (0.34)
- North America > United States (0.89)
- Europe > United Kingdom > Scotland (0.89)
Abstract This paper presents a method of overcoming some of the problems associated with drilling with positive displacement motors (PDM's) using compressible fluids. The specific problems addressed are:motor over-speeding resulting from sudden drops in motor load, often leading to stator "chunking". repeated stalls resulting from poor feedback of motor performance to the operator, resulting in poor effective rates of penetration (ROP's) and reduced motor life. Transient flow conditions dictate the phenomena listed above. This paper explains the theory behind the transient conditions that occur when the load on the motor suddenly changes due to inevitable changes in drilling conditions. A methodology is given that predicts the PDM's rotational speed resulting from these sudden load changes. A solution is put forward that ensures that the total drilling "system" of the coil, the bottom hole assembly (BHA) and the motor is stable, efficient, controllable and not liable to self-destruct. Introduction Drilling with positive displacement motors using compressible fluids is not new to the industry. Many such jobs have been successfully carried out using both coiled tubing and drill pipe using both air and commingled mixtures of liquid and gas. However, there are significant additional difficulties to contend with when using compressible fluids and the success rate or motor life is typically much lower as compared to conventional drilling with single-phase fluids. Prior research and testing has been undertaken to show how the down hole motors themselves respond when compressible fluids are pumped through them. Naturally, the motor testing done is based on steady state conditions. Whereas the steady state behavior of the motor is very important, the transient behavior is critically important. Controlling a PDM with compressible fluids is made difficult by the fact that the coil operator receives little help from his surface instruments. Changes in the differential pressure across the motor are not directly reflected in changes in the surface pump pressure. This is true for steady state conditions and particularly true for transient conditions. Down hole, the load on the motor can change quite suddenly, responding to changes in WOB or changes in the target through which the motor is drilling. The compressible fluid inside the coiled tubing acts as a giant accumulator. The combined effect of the "accumulator" and the motor can be to impose destructive flow rates through the motor under transient conditions. These destructive transients can be totally transparent to the coil operator on surface. Also, the tubing weight indicator gauge can be a poor or insufficient indicator of motor performance, depending on the motor/bit configuration used. The drilling system of coil, motor and bit can be unstable and practically impossible to control if not engineered taking transients into account. An unstable system can be avoided when the physics of the system are understood and the drilling system is configured correctly. An understanding of steady state behavior is required to design the target conditions for a coil drilling job. An understanding of the transient conditions is required to prevent unstable and self-destructive behavior of the motor down hole. The fluid transient behavior is mostly a function of the fluids, the coil, additional flow restrictions, and the operating pressure range of the motor. Basic Concepts of Compressible Fluid Drilling Figure 1 shows a much-simplified picture denoting the basic components of a coil unit drilling with a down hole motor.