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Summary Brine displacements were one of several areas of focus in a continuous process to optimize completion methodology in Amerada Hess's Ceiba project wells, located in deepwater offshore Equatorial Guinea. The time between making up the cleaning string and laying it down, after displacement and filtration operations are completed, can exceed two days and cost U.S.$500,000. It is imperative that wellbore-cleaning operations are performed efficiently and correctly the first time. Amerada Hess and its brine suppliers, working together in a joint task force, have taken specific steps to minimize the time required for displacement and filtration operations. Introduction The Ceiba field in deepwater Equatorial Guinea was discovered in mid-1999 by Triton Energy Ltd., now Amerada Hess. To date, 20 wells have been completed, and three wells have been recompleted. Ongoing development of the field still continues at this time. Five of the wells were completed as openhole gravel-packed producers. The others were cased-hole producers or injectors. The initial average pore pressure in the field was 8.7lbm/gal, and the majority of wells in the field were completed in a 9.0 to9.2-lbm/gal CaCl2 brine. This fluid was selected because of its minimal damage effect during core tests and its ready availability at stock points in the west Africa operating area. All wells were drilled through the pay interval by use of mineral-oil-based mud. The Ceiba field lies in approximately 800 m of water. The wells flow through individual subsea flowlines for 8 to 11 km to a floating-production, storage, and offloading unit that was positioned to receive first oil in the late fall of 2000.1 The semisubmersible Sedco 700 has been on location in the field since the spring of 2000 and has drilled the majority, and completed all, of the Ceiba development wells. As part of a continuing improvement program used throughout the development of Ceiba, a critical review of brine-displacement practices was performed to optimize this process. A review of cased-hole completions by the taskforce indicated room for improvement in our displacement process and chemical usage. At the time the task force was formed, the average displacement took 25or more hours, with up to 4,000 bbl of completion brine discarded because of poor quality and filtration problems. This paper examines the stages of mud-to-brine displacement used in the cased-hole completions of the Ceiba deepwater development and demonstrates how these stages were adjusted in their relationship to one another to make a more efficient displacement. Data are presented to show simplification of procedures, improved mud-solids removal, shorter filtration time, reduced loss of brine, and shorter rig timeover the course of the development. These modifications and changes had a major impact on time and cleaning efficiency. Please note, Ceiba openhole-completion displacements are not addressed in this paper.
Abstract The Enfield development was the first oil field to be put into production in the Greater Enfield Area. These fields lie in deep water off the North West Cape area of Western Australia. Operated by Woodside on behalf of the Enfield Joint Venture, this was the first oil field development for Woodside requiring horizontal open hole completions with sand control. The challenge for this project was to deliver early oil production from a low well count with wells producing from an unconsolidated and faulted formation containing shale. The remote location posed an additional challenge for the development. The initial development consisted of 5 producers, 6 water injectors and 2 gas disposal wells, with subsequent campaigns adding 3 production well sidetracks, a new producer and a water injector to the total reservoir penetrations. Both low angle deviated and horizontal wells have been completed. A number of different sand face completion types have been used over the initial phases of the Enfield development. Both water and oil based reservoir drilling fluids were used for this field development. This paper will review the evolution of the design used for the production wells. Initial horizontal gravel packs were done with a circulating gravel placement technique using brine as the carrier fluid. Subsequently a single barrier sand control technique using expandable screens alone to control sand production was installed. Due to difficulties encountered with these approaches, completion designs reverted to gravel packing. However at this second attempt at gravel packing, a gel slurry packing technique using screen fitted with alternative paths for gravel placement was successfully used. Whilst deep water open hole gravel packing was a new challenge for Woodside; due to the high productions rates achievable, only a limited number of wells were required for the field development. This implied both a very short learning curve, and a need to react rapidly to any difficulties encountered. This paper reviews the performance of these completions and the drivers for the evolution of the completion technology during the field development. This has provided a pathway for future completions in the development of similar reservoirs in the portfolio.
A novel process for recycling polysaccharide-viscosified brine completion fluids was developed. The process uses oxidants generated directly in the used brine by electrolysis to "break" the viscosity. The treated brines can be filtered with conventional equipment, reviscosified, and reused. The process has been applied on a laboratory scale to Br-/Cl- brines containing Na+, K+, Ca+2, and Zn+2 cations. Calculations with information from pilot-scale tests on NaBr/NaCl brines indicate that the process should be attractive economically.
Brines from low-density NaCl solutions to high-density ZnBr2/CaBr2 mixtures have been used extensively in drilling, completion, and workover operations. The use of clear brine fluids has contributed to increased well productivity by minimizing solids-induced formation damage. Although clear, filtered brines are usually nondamaging, they do not effectively suspend particulates in densities below 14 lbm/gal [1678 kg/m3] or control fluid loss. For specific operations, such as workover, drilling, or gravel packing, where solids transport or low fluid loss is desired, polymeric viscosifiers and water- or acid-soluble solids are often added to brines. The widespread use of expensive bromide-containing brines has made reclamation processes, involving setting and filtration, very cost-effective, but the addition of viscosifiers to brines makes reclamation more difficult. The presence of the viscosifiers prevents settling of particulates entrained through normal fluid use. Furthermore, these polymers quickly coat filter media, creating large pressure drops during filtration operations and preventing the economical removal of particulates by filtration. It has long been recognized that viscosifiers can be degraded by various means, which allows the brines to be filtered and reused. The field techniques tried include the addition of oxidizers (such as hypochlorite and persulfate), treatment with enzymes, digestion with acid. or high-temperature degradation. None of these has been totally satisfactory for several reasons. 1. Enzymes are slow, expensive, and relatively delicate (with respect to chemical environment and temperature). 2. Addition of persulfate changes the brine's chemical composition. In particular. because the reduced form of the oxidant is sulfate, persulfate use poses the risk of precipitation of insoluble salts downhole in the presence of multivalent metal ions. Formation damage can occur from fluids containing undesirable solids. 3. The use of aqueous slurries of calcium hypochlorite can dilute the brine, which may require reformulation. The addition of calcium can cause a problem in regions where the formation fluids contain high concentrations of bicarbonate or sulfate by the precipitation of insoluble salts that could plug the formation. The application of solid calcium hypochlorite to used brines that may contain residual hydrocarbons requires care to prevent reaction with those compounds. Fires have resulted from improper use. 4. The use of sodium hypochlorite solutions causes brine dilution, making reweighting necessary. If reweighting is performed with stock liquid, additional fluid volume is generated, the use of concentrate is expensive, and evaporation increases energy consumption. 5. The use of solid lithium hypochlorite avoids the dilution problems of the sodium salt but is considerably more expensive. Also, the same potential problems that exist for calcium hypochlorite apply. 6. Acid digestion can be performed only in lined equipment. This restriction means increased costs either for lined tanks or through corrosion of unlined tanks. 7. The use of hydrogen peroxide overcomes the cross-contamination problems. Unless the peroxide concentration is at least 30 wt% and the solution is made acidic, however, the degradation rate will be slow. Furthermore, concentrated peroxide solutions can be hazardous to handle and are relatively expensive. Note that, while apparently satisfactory methods are available for specific brines, a single method applicable to any brine is desired, especially because of the potential complication of cross contamination of both polymer and brine components. Thus, we concluded that a need exists for an improved process that could leave the brine composition and density unchanged, could operate over a wide temperature range without heating or cooling, and would be relatively fast and safe. We developed such a process, which operates by the generation of the oxidant in situ by direct electrolysis of the used brine. The oxidant attacks the polymer, leading to chain scission and thus viscosity reduction. The fluid can then be filtered with standard filtration techniques. The treated and filtered brine can be reused 85 is or after reviscosification.
Summary Downhole monitoring of streaming potential, using electrodes mounted on the outside of insulated casing, is a promising new technology for monitoring water encroachment toward an intelligent well. However, there are still significant uncertainties associated with the interpretation of the measurements, particularly concerning the streaming potential coupling coefficient. This is a key petrophysical property that dictates the magnitude of the streaming potential for a given fluid potential. We present the first measured values of streaming potential coupling coefficient in sandstones saturated with natural and artificial brines relevant to oilfield conditions at higher-than-seawater salinity. We find that the coupling coefficient in quartz-rich sandstones is independent of sample type and brine composition as long as surface electrical conductivity is small. The coupling coefficient is small in magnitude, but still measurable, even when the brine salinity approaches the saturated concentration limit. Consistent results are obtained from two independent experimental setups, using specially designed electrodes and paired pumping experiments to eliminate spurious electrical potentials. We apply the new experimental data in a numerical model to predict the streaming potential signal that would be measured at a well during production. The results suggest that measured signals should be resolvable above background noise in most hydrocarbon reservoirs. Furthermore, water encroaching on a well could be monitored while it is several tens to hundreds of meters away. This contrasts with most other downhole monitoring techniques, which sample only the region immediately adjacent to the wellbore. Our results raise the novel prospect of an oil field in which the wells can detect the approach of water and can respond appropriately.
Abstract The Middle East has long been a pioneer in innovation in drilling and completion technologies for multilateral wells. It was here that the first1 multilateral tool (MLT) on coiled tubing was used to access and stimulate each openhole lateral in a trilateral well. Over the years, several2-4 applications of this and similar technologies have been made. In each instance, a conventional upper completion system was installed. In a multilateral well with a conventional upper completion and an openhole lower completion, there is no independent flow control from each lateral. Because of this, production is not optimized to account for differences in the production rate or reservoir quality of each lateral. For a well with an upper intelligent completion system (ICS), independent control of flow from each lateral is possible through the use of surface controlled flow control valves (FCVs). This feature addresses the shortcomings of the conventional upper completion mentioned earlier. The challenge in performing an acid stimulation of each openhole lateral in a well with an ICS is the inability to access any of the laterals after the ICS has been installed. Current technologies do not afford this option and designs in the pipeline do not have field proven applications. This paper chronicles a novel attempt at acid stimulating each openhole lateral of a trilateral well in a carbonate reservoir. It includes the installation of the ICS in the same well. The challenges, results, learnings and future courses of action are documented in what should provide a template for continuous improvement.