Summary Big reservoirs in deepwater Gulf of Mexico (GOM) typically produce at world-class rates. The scale of investment is likewise world class. The energy industry's drive to invest in enhanced oil recovery from deepwater basins is sustainable in a world of volatile oil prices and increasing demand for energy. However, project economics will continue to depend on accurate risk assessment, risk-mitigation strategies, and, more fundamentally, progressive deployment of evolving technologies in brownfield deepwater secondary-recovery projects. Details of well geometry and design optimizations may prove to be minor sensitivities in high-cost deepwater developments; however, rig rate has a major impact on economics. The assessment required to minimize the number of injectors and ensure their proper placement logically takes more time than exotic choices of injection patterns. With such major constraints in mind, an optimal design for wells and materials has to take precedence. Accepting this as a given, additional, more common challenges would then follow. The waterflood-study team for the deepwater Ursa/Princess field in the GOM has spent appreciable time and effort evaluating various potential challenges affecting the surface and subsurface aspects of the development plan. The design for an optimum injection rate was a bottom-up process starting from the reservoir up to the topsides injection facilities. Reservoir-sweep efficiency and reservoir-pressure distribution logically dictated injection-well designs and injection-pump sizing. Subsurface risks, such as reservoir souring and hydrate formation, dictated materials selection and completions design. This paper addresses the challenges primarily affecting the design of the deepwater subsea-injection wells. In addition to the well cost, several other underlying factors have played an influential role in defining the boundary conditions for the injectors design. Background Industry-wide experience in the execution and the operation of waterflood projects in deepwater environments is relatively limited. With relatively few analogs, the Ursa and Princess fields are set to embark on major facilities expansion and subsea development. The aim is to deliver a high rate of specific-quality water through four subsea-injection wells into a vast and, largely thirsty, reservoir. Ursa and Princess reside 100 miles south/southeast of the Mississippi River mouth in the Mars basin, GOM. The Ursa field was discovered in 1990 and has been on production since 1999. The Princess field was discovered in 2000 and has been producing since December 2003 through a subsea tieback to Ursa. The fields have their main reservoirs in common and are in pressure communication. The working interest in the Ursa and Princess fields are Shell (45--operator), BP (23%), ExxonMobil (16%), and ConocoPhillips (16%). The Yellow reservoir is the main reservoir at both Ursa/Princess and Mars, the other major field in the Mars basin. It is a world-class Upper Miocene turbidite reservoir that stretches across the Mars basin, including the Mars field. This 12,000-acre reservoir is charged with light-oil type, though with slight variations in properties, as indicated by the analysis results of the abundant pressure-volume-temperature measurement samples. Because of limited TLP well availability, the high cost of subsea wells and the limitations of the subsea system to handle large water cuts, the waterflood will use relatively few injectors. The proposed base plan has four water injectors: two into Princess and two into Ursa. Producing wells will include three Princess subsea wells and four Ursa TLP wells. Five TLP wells are to be sidetracked updip or recompleted at a later stage. High injection rates are required to replace voidage and maintain reservoir pressure above bubblepoint. Initial injection rates per well (annual average) of 30 to 40 thousand BWPD are required. This injectivity can only be maintained by creating fractures. With the wide well spacing relative to fracture length, this is not expected to negatively impact sweep efficiency. However, because of the uniqueness of well spacing and reservoir volumes, there is a lack of analog-data points to calibrate the outcomes. Parallel evaluation of the viability of artificial lifting has shown that TLP waterflood producers would benefit from gas lifting. The base plan for waterflood wells thus includes the requirement for gas-lift completions and facilities. The original Operating Health Safety and Environmental (HSE) case for the asset did not include the potential threat of reservoir souring after seawater injection. The well casing and tubular materials, therefore, have limited resistance to sulfide-stress corrosion cracking. This resulted in the need to recomplete the Ursa TLP direct-vertical access (DVA) wells with Shell-qualified tubing. Princess producers already have Shell-qualified C100 sour-resistant casing, and will not require pre-emptive intervention for tubing change out.
Big reservoirs in deepwater Gulf of Mexico typically produce at world-class rates. The scale of investment is likewise world-class. The energy industry's drive to invest in enhanced oil recovery from deep-water basins is sustainable in a world of volatile oil prices and increasing demand for energy. However, project economics will continue to depend on accurate risk assessment, risk mitigation strategies, and more fundamentally, progressive deployment of evolving technologies in ‘brownfield’ deepwater secondary recovery projects. Details of well geometry and design optimizations may prove to be minor sensitivities in high cost deepwater developments, however rig rate has a major impact on economics. The assessment required to minimize the number of injectors and ensure their proper placement logically takes more time than exotic choices of injection patterns. With such major constraints in mind, an optimal design for wells and materials has to take precedence. Accepting this as a given, additional, more common, challenges would then follow. The waterflood study team for the deepwater Ursa- Princess field, in the Gulf of Mexico, has spent appreciable time and effort evaluating various potential challenges affecting the surface and subsurface aspects of the development plan. The design for an optimum injection rate was a bottom-up process starting from the reservoir up to the topsides injection facilities. Reservoir sweep efficiency and reservoir pressure distribution logically dictated injection well designs and injection pump sizing. Subsurface risks, such as reservoir souring and hydrate formation, dictated materials selection and completions design. This paper addresses the challenges primarily affecting the design of the deepwater subsea injection wells. In addition to the well cost, several other underlying factors have played an influential role in defining the boundary conditions for the injectors design. Background Industry-wide experience in the execution and the operation of waterflood projects in deepwater environments relatively limited. With a relatively few analogues, the Ursa and the Princess fields are set to embark on major facilities expansion and subsea development. The aim is to deliver high rate of specific quality water though four subsea injection wells into a vast and, largely thirsty, reservoir. Ursa and Princess reside 100mi SSE of the Mississippi River mouth in the Mars Basin, Gulf of Mexico (GOM). The Ursa field was discovered in 1990 and has been on production since 1999. The Princess field was discovered in 2000 and has been producing since December 2003 through a subsea tieback to Ursa. The fields have their main reservoirs common and are in pressure communication. The working interest in the Ursa and Princess fields are Shell (45.4% operator), BP (22.7%), ExxonMobil (16%), and ConocoPhillips (16%). The Yellow reservoir is the main reservoir at both Ursa/Princess and Mars, the other major field in the Mars basin. It is a world class Upper Miocene turbidite reservoir that stretches across the Mars Basin, including the Mars Field. This 12,000-acre reservoir is charged with light oil type, though with slight variations in properties as indicated by the analysis results of the abundant PVT samples.
E&P Exchange Many investigators over the years have researched the causes of sand production and searched for a reliable means to predict it. Sand production prediction is important because of the safety, environmental, and operational concerns involved when produced sand particles fill and plug the wellbore, erode downhole and surface equipment, and increase operating expense. Currently, no method of sand production prediction is universally regarded as accurate and reliable within the industry. A number of prediction models have been developed to identify completions that may be expected to produce sand. Earlier attempts to develop prediction techniques included statistical models, numerical models, mechanical properties logs, sand strength logs, and core studies. Often the individual attempts to develop a predictive model were specific to the type and locale of the reservoir being studied; i.e., water production, pore pressure depletion, perforation geometry, pressure drawdown caused by skin effects, and a variety of other critical parameters were not always considered. The dilemma of an independent U.S. operator faced with a completion decision regarding sand control is not that different from the problems considered by large North Sea production companies. Quite often, the most cost-effective method to determine the need for sand control is by analogy from data collected from offset wells. Complex 3D numerical modeling in concert with extensive laboratory analysis of core and log data is not always economically practical but is the most technically correct method with an acceptable degree of accuracy when properly performed. Historically, much attention has been given to sand production prediction. The vast differences and complexities observed between the models and techniques that have been developed suggests a multitude of engineering and geologic parameters to be considered (Table 1). Morita and Boyd cataloged and analyzed five typical sand problems observed in the field that were induced by (1) unconsolidated formations, (2) water break through in weakly to moderately consolidated formations, (3) reservoir pressure depletion in relatively strong formations, (4) abnormally high lateral tectonic forces in relatively strong formations, and (5) sudden changes in flowrate (cyclic loading) or high flow rate. They developed a core-based completion guide on the premise that completion performance in a weak formation is significantly affected by near-wellbore rock strength and permeability. Morita and Boyd determined that the strength of a reservoir rock varies significantly depending on stress levels and that sandstones deform nonlinearly with the nonlinear character varying with the stress rate. In other words, sandstone failure is a dynamic process that is dependent on changing near-wellbore stresses that are affected by some combination of the 16 factors in Table 1. An evaluation of the completion at one point in time without extrapolation into the future will not accurately predict the conditions under which failure will occur. Sonic, density, and neutron logs relate the well under study to an active sand-producing well. Openhole logs must be calibrated to a known sand producer for an analogous comparison to the well being studied. The problem is that the well must be taken to the point of formation failure before the comparison can be made, and no technique exists for forecasting reservoir performance into the future. Additionally, the effects of pressure depletion, water production(multiphase flow), and additional pressure drops caused by skin effects are not considered. Wells located offshore in the Gulf of Mexico are a good example of this decision criteria. The sand production prediction technique that will be most effective for a given area is one in which field observations, laboratory experiments, and theoretical modeling are all integrated for the formation under study. References Veecken, C.A.M. et al.: "Sand Production Prediction Review:Developing an Integrated Approach," paper SPE 22792 presented at the 1991SPE Annual Technical Conference and Exhibition, Dallas, Oct. 6-9. Morita, N. et al.: "Parametric Study of Sand Production Prediction:Analytical Approach," paper SPE 16990 presented at the 1987 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 27-30. Morita, N. and Boyd, P.A.: "Typical Sand Production Problems-Case Studies and Strategies for Sand Control," paper SPE 22739 presented at the1991 SPE Annual Technical Conference and Exhibition, Dallas, Oct. 6-9. Ghalambor, A. et al.: "Predicting Sand Production in U.S. Gulf CoastWells Producing Free Water," JPT (Dec. 1989) 1336. P. 955^
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.