New materials used in deepwater production tubulars, and the increasingly complex and costly deepwater projects, demand greater attention to the design and selection of completion and packer fluids. This requires an integrated approach, from mud displacement through final sand control completion, in order to optimize fluid compatibility and effectiveness. In addition to standard compatibilities with reservoir rock and fluid, compatibilities of completion or packer fluid with control line, stimulation, and production fluids must be considered. Furthermore, compatibility of completion and packer fluids with production tubular metallurgies must be assured in order to prevent environmental cracking. The impact of the production environment on the potential formation of gas hydrates or crystallization of brine due to pressure, at the near-freezing mudline temperatures, must be understood for each of the wellbore fluids used during the completion process. For some projects, more than one completion or packer fluid choice is available, in which case each fluid should be evaluated to select the best ‘fit-for-purpose’ fluid. This paper presents a new paradigm for testing and evaluating completion and packer fluids for selection in deepwater applications. Details for each test procedure and evaluation method are presented and include completion or packer fluid compatibilities with formation or synthetic formation water, control line fluids, and produced fluids. Core flow studies used to test fluid compatibility with the formation rock, and standard stress-cracking tests, conducted according to NACE guidelines, used to avoid the potential for environmentally assisted cracking of chrome production tubulars, are presented. Specialized evaluation methods to avoid the formation of gas hydrates and the pressure crystallization of completion and packer fluids are also presented. The best fit-for-purpose fluid was selected by following this new paradigm for a GOM deepwater project. Lessons learned are summarized in the paper. Introduction Deepwater wells have been completed successfully in the Gulf of Mexico for nearly 10 years, during which time numerous new learnings were experienced. One dramatic example is the crystallization of completion brine above its True Crystallization Temperature (TCT) due to the application of high pressure1. This phenomenon was encountered while running screen and washpipe at Shell's Ram/Powell development in 3,214 ft of water when CaCl2/CaBr2brine crystallized unexpectedly and completely blocked the wellbore flow path2. The entire assembly had to be retrieved in order to remove the plugging. Since then, the Pressure Crystallization Temperature (PCT) of completion brine has been evaluated in some detail and currently an API work group is reviewing the available test methods and apparatus3. Now, completion brine PCT evaluation must be incorporated into the pre-planning process for completing deepwater wells. Pre-Planning and evaluation for deepwater projects has taken on new dimensions, and testing technologies that were routinely used for some time have been re-evaluated and enhanced to provide optimum results. New testing regimes and paradigms have continuously been introduced into every phase of the completion process, from mud displacement to packer fluid selection. Another powerful experience impacting deepwater projects is the formation of gas hydrates that are capable of totally blocking inflow and outflow from a well. Gas hydrates of oilfield interest, known for more than 100 years, have been widely published4, 5 and can be generated at temperatures well above the freezing point of water when high pressure is exerted on a hydrocarbon gas-water mixture. Hydrate formation is of intense interest around the mudline in deepwater applications where the water temperature is about 38°F and high pressure is expected. Whenever hydrocarbon gas is produced, the operator necessarily controls the fluid environment within the production tubing especially during startups and in the packer annulus, should this fluid contact produced gas, in order to prevent hydrate formation and the potential blocking of production and well entry.
Deepwater completions are defined as those executed in water depths of greater than 1,500 feet. The extreme depth in itself presents challenges, but in addition to these, operators are continuing to seek completion methods that will increase reliability, flexibility, and eliminate future interventionsstrategies which further add to well-completion complexity.The Gulf of Mexico is a prime area for deepwater completions, and because of the extensive need for sand control, fracpacked completions have become the norm as they offer reliable sand control and long-term completion efficiency with higher sand-free producing rates and faster reserve recovery. The application of intelligent well designs provides operators with other advantages with respect to cost-effective development of multiple, smaller reservoirs.Operators are continually faced with the need to balance the cost and risks associated with well complexity against the cost and risks of future interventions -both of which are impacted by ever-increasing day-rates and the tight availability of rigs and multi-service vessels needed for intervention.The challenge of combining intelligent, multi-zone completions with sand control is further complicated when dealing with deep, high-pressure deepwater wells. Lessons are being learned every day in these arenas. This paper summarizes two examples of multi-zone, frac-packed, intelligent 15k deepwater completions that were recently undertaken in the Cottonwood project in the Garden Banks Block 244 operated by Petrobras America. Measures taken to streamline and mitigate risk during rig operations and to reduce non-productive time through inspection and qualitycontrol efforts will be discussed. Project Description and OverviewThe Cottonwood Deepwater Project is located in the Gulf of Mexico's Garden Banks Block 244, approximately 138 miles south of Louisiana in 2,118 feet of water. The prospect consists of Pliocene and Upper Miocene turbidite sands that have filled in pockets on the flank of a remnant salt feature. The complex structure and inherent stratigraphy as well as the potential for compartmentalization provided a myriad of challenges for the geoscientists. The many deep and highlypressured reservoirs added further challenges to the success of the well completions.In 2005, Petrobras America acquired a 100-percent working interest (WI) and became the operator of the block. Mariner Energy joined as a 20% WI partner prior to the sidetracking of Well 'B'. The sidetrack confirmed 40 meters (130 feet) of natural gas and condensate pay.In September 2005, Petrobras America announced an ambitious plan to drill an additional well, complete both wells, install production facilities, and begin production by early 2007 -less than 15 months from project sanction. Petrobras achieved this timeline, and the wells are now Petrobras' deepest and highest-pressure producing wells worldwide. Cottonwood was developed as a subsea development with a 20-mile flowline to a production platform in East Cameron block 373. The planning schedu...
This paper reports on observations of hydraulic fracturing in coal seams gained in research activities, conducted by Resource Enterprises, Inc. and sponsored by the Gas Research Institute in their Western Cretaceous Coal Seam Project. The fracture treatments span a period from 1986 through 1988 and involve activities in the Piceance and San Juan Basins. Findings resulting from this work are that hydraulic fracture designs must reflect the lithology of the bounding strata as this affects fracture height growth and fracture geometry. Where coal seams are adjacent to sandstone, diagnostics show that hydraulic fracture growth occurs in both the sandstone and the coal and fracturing pressures are less than 1.1 psi/ft. It was also demonstrated that a linear fracture fluid could be used effectively to place proppant in the coal zone if the sandstone overlies the coal. Much higher treating pressures were encountered in fracture treatments where coals were bound by shale. Diagnostics showed the fracture to be contained primarily to the coals and the high treating primarily to the coals and the high treating pressures may have resulted in part from a complex pressures may have resulted in part from a complex fracture geometry. Several possible reasons for this behavior are listed. High strength casing was found to be useful in accommodating the higher treating pressures and it allowed a larger treatment to be pumped where many jobs have had to be terminated prematurely when the burst strength of the tubulars was reached. Higher injection rates and the use of solid fluid loss material are recommended to create sufficient width in the complex geometry and thereby increase the likelihood of a successful treatment. Caution is advised in the use of conventional interpretations of NolteSmith (log net pressure vs. lot time) plots because of the abnormally high treating pressures associated with coal and the potentially-complex fracture geometry that have been observed in mineback experiments are well beyond the scope of the simple Nolte-Smith technique. Background Jones, et al (1987) has shown that hydraulic fracturing plays a critical role in the exploitation of coal bed methane because of the unique nature of coal bed methane, and because coal seams tend to have lower permeability, particularly in the deeper Cretaceous-age coals of the western U.S. Coalbed methane differs from conventional gas reservoirs in that methane is adsorbed onto the surface area of the coal as opposed to being simply compressed within the pore spaces of the reservoir. The amount of gas that is adsorbed on coal depends on reservoir pressure and this relationship follows a Langmuir-type sorption isotherm. Figure 1 compares the sorption isotherm behavior to a conventional gas reservoir. The flat part of the sorption isotherm at higher pressures requires that reservoir pressure must be pressures requires that reservoir pressure must be reduced significantly to liberate gas from the coal. Because most coal reservoirs are saturated with water and the coal must undergo an initial dewatering phase to reduce reservoir pressure. Both the flat sorption isotherm combined with water-gas relative permeability effects require a substantial reduction in reservoir pressure before a mobil gas saturation is developed and early gas production achieved. The permeability of coal is thought to be dependent on several factors, particularly, the degree of cleat and fracture development and the in-situ stresses which act to close those cleats and fractures. Cores studies conducted be GRI have shown that coal matrix itself is essentially impermeable, thus, fluid flow in a coal reservoir must occur in the cleats (natural fractures that form during the maturation of coal) and the tectonic fractures that may be present. And, it is the in situ stresse which act to close these flowpaths that determine how effectiveness the cleats and fractures are. In general, in situ stress increases with burial depth.
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