TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMany of the recently discovered reservoirs in deepwater/subsea environments are prime candidates for horizontal open-hole gravel packs. Presence of multiple reactive shale breaks and penetration of different sand bodies along these holes introduce a formidable challenge for selection of proper carrier fluids, considering that most of these wells require oilbased (OB) drilling fluids.Various procedures were practiced for gravel-packing wells drilled with OB fluids, most utilizing water-based (WB) carrier fluids. Primary concern in using WB carrier fluids is the destabilization of the shales.If the displacements to WB fluids are performed prior to running in hole with the sandface completion assembly, inability to run the screen assembly to target zone is the risk. Consequently, operators were forced to use a two-step process, whereby a predrilled liner is run in hole in OB fluid environment, followed by displacements to WB fluids and gravel-packing with WB fluids. This approach introduces additional rig time and increases completion costs.If the displacements to WB fluids are performed after running in hole with completion assembly, primary challenge is the prevention of screen plugging. This necessitates a comparison of the benefits and risks of displacements to solids-free oil-based fluids and conditioning of the OB drilling fluid, considering logistics.An additional consideration in gravel packing with WB fluids in reactive-shale environments is the risk of intermixing of gravel with shales, thus reduced gravel-pack permeability. Various approaches may be taken to minimize this risk. The type of carrier fluid must also be kept in mind from a formation and gravel pack damage standpoints, should losses be experienced during gravel packing.Another approach in reactive shale environments is to use an oil-based carrier fluid and avoid exposure of the open hole to WB fluids both prior to and during gravel packing. This approach, practiced in two applications, also has its limitations.In this paper, a critical review of gravel-packing practices in oil-based drilling environments is provided, along with some of the recent developments and recommendations for future applications based on lessons learned from earlier practices.
Summary In this article we describe the key planning and operational experiences gained during the perforation and completion phases of the world record step-out extended reach well at the Wytch Farm oilfield in Dorset, England. We present an overview of how the M-11 well was completed successfully and describe how a combination of existing and new technology was applied to achieve Wytch Farm's most prolific producer. Well 1M-11SPy (M-11) the world record for the highest horizontal departure, 10 114 m, at any vertical depth, and a record departure to true vertical depth ratio of 6.24. The Wytch Farm extended reach wells are completed with cemented, perforated liners and electrical submersible pumps (ESP's). A new technique for perforating the well was developed to maximize inflow efficiency. This technique enables underbalance perforating without any subsequent requirement for a well kill. The impact of these improvements on completion efficiency is discussed, along with associated operational issues. The large departure required the ESP to be set at 8625 m, another world record, with the 1,000 HP motor requiring a new 7 kV cable system and a 1500 kVA variable speed controller (VSC) at the surface. We describe the VSC selection and the physical testing of the complete ESP/cable/VSC system, which was conducted before installation to ensure that sufficient torque could be generated at the ESP for a range of startup and operating conditions and to configure the new type of VSC used for optimal system performance. We also report the experience gained and review the lessons learned. Introduction The Wytch Farm development is located in an unusually sensitive environmental area on the southern coast of England. The main Sherwood sandstone reservoir lies under Poole Harbour and extends offshore under Poole Bay (Fig. 1). The Sherwood is a Triassic sandstone with the reservoir top at 1585 m true vertical depth (TVD) subsea with a maximum 110 m column of oil-bearing sand above the oil/water contact. Approximately 90% of the field total reserve basis is contained within the Sherwood reservoir. Nearly one half of the Sherwood's 430 million barrel reserves lies in the offshore extension. During 1991, advances in drilling technology enabled offshore recovery to be considered as the preferred option, utilizing extended reach wells drilled from existing offshore facilities. Since the start of extended reach drilling (ERD) in 1993, 15 ERD wells have been drilled with stepouts ranging from 3800 m up to the record breaking result of 10 114 m for well M-11. The geoscience planning, drilling, and completion of Wytch Farm ERD wells have been extensively documented. The field is now in a mature development stage and was producing approximately 100 thousand BOPD. Background Drilling Summary. Figs. 2 and 3 show the final well trajectory. A 9 5/8 in. casing was set just above the Sherwood reservoir top, which allowed 8 1/2 in. drilling of the reservoir. After drilling approximately an 800 m horizontal section into the reservoir, it was apparent that the wellbore was high within the structure, and had insufficient permeability thickness (kh) to achieve the well objectives (M-11z). At this point, it was decided to abandon this wellbore and perform an openhole sidetrack (M-11y). The sidetrack was completed successfully in the openhole section just below the 9 5/8 in. casing shoe and wellbore and drilled to its record-setting horizontal departure and total depth. The hole was then lined and cemented. Well Performance. Prolific productivity indices (PI's) for the project, up to 135 B/D/psi, have been achieved, of which M-11 realized a PI of 45 B/D/psi. As discussed in detail later, these high productivities, coupled with relatively low reservoir pressures, have pushed ESP technology to the technical limits in terms of capacity and power requirements. In addition, the inability to effectively interpret pressure-transient test data has resulted in uncertainty in determining precise completion efficiency and PI potential estimates. Perforating and Workover Operational Histories. The conventional tubing conveyed perforating (TCP) underbalanced shoot, kill pill, and test string recovery method has previously been adopted as the preferred completion technique. Key issues of the deployment technique, charge design criteria for debris, and kill pill formula were engineered to minimize formation damage and maximize productivity. In addition, workover operations have traditionally relied on pumping viscous, fibrous lost circulation material (LCM) kill pills that were perceived to be nondamaging to attain well control. Current production logging tool (PLT) information has indicated that select production intervals are not contributing to production. There is no obvious reason for this selective productivity other than that the intervals may be plugged with residual LCM. Because of the operational complexity and associated high costs to attain PLT data, baseline data are not readily available to distinguish between formation damage from the initial perforating vs. subsequent workover operations. With production depletion and known decreases to static reservoir pressure, the recent risk of kill pill formation damage has increased because of greater applied overbalances in combination with less available production underbalance. ESP and Drive Summary. The three different types of VSC's that Wytch Farm uses to control ESP systems are a variable voltage source quasisquare wave, a current source, and a constant voltage source pulse width modulated (PWM).
Many water injection wells in sand control environments are being completed as open holes because of the higher injectivities attainable with open-hole completions. The sandcontrol techniques used in these wells varies from standalone screens or slotted liners (including expandable screens) to gravel packing. In field practice, the drilling fluids used for injectors have also varied from water-based (either sizedCaCO3/Polymer or sized-salt/polymer) fluids to oil-basedsystems. Although a cake cleanup followed by a production period is typically desirable to maximize injectivity, often this is not feasible either due to limited storage capacity on the rigor requirement for artificial lift due to low reservoir pressure. These limitations therefore necessitate direct injection after thecompletion is installed, which is not trivial as a complete and uniform filtercake removal, including drill solids as well as thebridging agents and polymers, is essential to ensure uniform injection profile in addition to maximizing injectivity index. Although exceeding the fracturing pressure can establish injectivity through by passing of filtercake damage, this istypically not desirable from a sweep efficiency standpoint. In this paper, we present details of a series of experimentsconducted on core samples using both water-based and oilbasedreservoir drilling fluid systems and various cleanup techniques involving displacements and soaks in standalonescreen and gravel pack environments. It is shown that with theproperly selected and designed cleanup treatments, uniformand high injectivities without producing the well is achievable in long open holes. The results from the experiments are discussed in detail, along with the lessons learned and recommendations for field practice. Introduction Many water injection wells in sand control environments arebeing completed as open holes due to higher injectivities attainable in such completions. Although targeted flow rates may sometimes be achieved without any cleanup chemicals inproduction wells (granted that this may not be the bestpractice), injection wells require filter cake cleanup, especially in cases where:producing the well prior to injection is not feasible ordesirable, because of limited storage capacity on therig, or artificial lift requirements due to low pressure, in addition to associated disposal costs, andinjecting above frac pressure is either not feasible(e.g., very high frac pressures and pump limitations)or not acceptable (e.g., sweep efficiency, premature water breakthrough, etc.). It is therefore highly desirable to provide techniques that will allow high and uniform injectivity across long open holes, without requiring a production stage and without having to exceed frac pressure. Water injection above frac pressure has been discussed in the literature, and various models have been proposed for propogation of such fractures when the injection water is"dirty".1,2In fact, even in cases where injection is initiallydone below frac pressure, often the fracturing pressure is exceeded some time during the life of the well due to declining injectivity and the common practice of maintaining constant injection rate. To avoid exceeding frac pressure and maintain high injection rates, mud acids treatments can be periodically performed. The reasons for water injectivity decline have also been discussed and various models have been proposed.3,4
This paper describes the key planning and operational experiences gained during the perforation and completion phase of the world record step-out extended reach well at the Wytch Farm oilfield in Dorset, England. The paper presents an overview of how the M- 11 well was successfully completed and describes how a combination of existing technology and new technology has been applied to achieve Wytch Farm's most prolific producer to date. Well 1M-11SPy (M-11) holds the world record for the highest horizontal departure, 10114m, at any vertical depth, and a record departure: to true vertical depth (TVD) ratio of 6.24. The Wytch Farm extended reach wells are completed with cemented, perforated liners and electrical submersible pumps (ESPs). A new technique for perforating the well was developed to maximise inflow efficiency. This technique enables underbalance perforating without any subsequent requirement for a well kill. The impact of these improvements on completion efficiency is discussed, along with the associated operational issues. The large departure required the ESP to be set at 8625m, another world record, with the 1000 HP motor requiring a new 7kV cable system and a 1500 kVA variable speed controller (VSC) at surface. This paper describes the background of VSC selection and the physical testing of the complete ESP/cable/VSC system that was conducted prior to installation to ensure that sufficient torque could be generated at the ESP for a range of start-up and operating conditions, and to configure the new type of VSC used for optimal system performance. The paper reports experience gained, and reviews lessons learned. P. 579
The world's first down hole flow control completion of an extended reach, multilateral well was implemented, achieving all objectives without any safety incident. The economics indicators are favourable. All the key parts of the Projects are captured here in a structured manner and in some detail. A great deal of learning has been covered, with an intention to cater for a variety of engineers and co-ordinators. After introductory notes including the challenges, the completion objectives were set out to which the remainder of the paper ties back. The mechanics of the Project was described next, i.e. how the completion looked and how things were done. Considerations of key engineering issues were detailed, demonstrating a sound design. Then some of the key processes in managing the Project were shared, touching on a range of topics from common sense practices and a novel economic evaluation tool to risk and crisis management. Lessons learnt revealed some most astonishing battles against potential disasters and how the Team came out stronger. The main conclusions included that downhole flow control can be achieved safely, fittingly and cost-effectively, and that the techniques developed and processes used in managing the project by the Team have shown to work well. Introduction This paper tells a success story of a unique down hole flow control completion carried out under extraordinary circumstances at Wytch Farm1. The extended-reach, multilateral well M15, that looked unable to pass the technical and financial hurdles initially, ended up with at least half a dozen world records and the costs still under the AFE. An extraordinary Team from all over the world made it happen. However, it was not without problems. The unprecedented challenges both technical and economical, the lateral thinking and creativity, the crises and recoveries from them, the conviction and the team work, all make this Project worthwhile, and worth finding out about. On an incremental basis, the net present value for reserves recovery alone on a three year projection for the flow control system is ca $4m, and the capital efficiency of >6. There are some other significant benefits delivered by this completion too. Today, the completion is performing as expected and designed, and M15 is on course to deliver business success. The Project won a BP Amoco 1999 Technical Achievements Award. This was a great honour for the Team, but the satisfaction of seeing the technical and financial success coming true would not be any less without it. Background on Wytch Farm Well M15 Wytch Farm oil field is the largest onshore oil field in Europe, and is known for its Extended-Ranch Drilling (ERD) and Completion2,3 in the Sherwood reservoir. Well M15 was based on an old ERD well M2 drilled in 1994, which had more than ints fair share of problems from the start. For example, the 5 ½" liner did not get cemented because the cement flash set and the liner was subsequently perforated without cement behind it. High water cut developed shortely afterwards with the characteristics of a conducting fault. A subsequent water shut-off job was unsuccessful. As a result, the reserves around M2 were not adequately recovered and it became apparent that side tracking would be a more reliabel option than others to access the surrounding reserves. The initial plan was to pull the old 5 ½" liner that was set in an 8 ½" hold and extended this hole by another thousand meters. Two more laterals were then to be added to this "main bore", one to the north and the other to the south.
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