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.
The active government gas exploration programme in Oman has recently added another sizeable gas-condensate discovery that was drilled and tested by Central-C-1. Destined to unlock the first CA sandstone gas-condensate field, the well results indicated a very prolific reservoir. In the process of data gathering, a number of challenging aspects were identified and assessed. Residual gas saturation is the most interesting and potentially high impacting aspect. This paper addresses variations on the gas saturation profile as calculated from the petrophysical logs, the identification from the special core analysis measurement of high residual gas saturation rocks, and all relevant findings inferred from the production testing and the static pressure gradient measurement. Despite cautioned applicability of the SCAL measurement results to reservoir conditions, a potential evidence for part of the CA reservoir accommodating high residual gas saturation was recorded. Number of scenarios were modelled to assess the impact of high residual gas saturation in relation with other reservoir uncertainties normally associated with exploration reserve bookings. These scenarios ultimately studied the impact of the residual gas saturation uncertainty on the development economics of the field. This paper explains why major economic measures, such as gas and the condensate recovery efficiencies, well placements and aquifer influx were seen sensitive to this uncertainty. For a comprehensive evaluation of its impact, a relationship between rock properties distribution and residual gas saturation was invisaged as a comprehensive evaluation method. In a deeper concept this translates into a relationship between the interpreted original depositional model and the adopted charge model. This interesting relationship was evaluated in the simulator using a special saturation-porosity dependence that was primarily based on the SCAL measurements. This paper details the analytical and the numerical approach used to evaluate the impact of the uncertainty in residual gas saturation. It highlights how this uncertainty features within the appraisal data gathering targets and within the surveillance strategy of this field. Introduction Central-C-1 well was drilled in 2000 that resulted in discovering a sizable gas-condensate field. The well was successfully production tested. However, high residual gas saturation was interpreted in some of the penetrated reservoir zones. This posed a challenge to model particularly with good production test results. Reservoir simulation was used to assess impact of such high values on recovery efficiencies.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAs the demand for natural Gas in the Sultanate Of Oman rises both internally through domestic and industrial growth, and externally through the LNG export, the development of more gas fields becomes a necessity. Being centrally located, close to existing central processing plant, and with considerable volume in place, the rich gas-condensate Saih Nihayda field, is seen as the next candidate for development. A full field model was built for Saih Nihayda to study uncertainties and investigate the optimum development option for the three deep stacked reservoirs. The hydrostatically pressured Barik sandstone being the shallowest and the most complex is a gas-condensate reservoir, whereas the Miqrat and the Amin sandstone are both over-pressured dry gas reservoirs.This paper details an integrated approach followed in assessing the impact of various uncertainties on development options. It highlights the modelling process from seismic inversion to demand driven forecasting and economic assessment. Special attention was paid to gas-condensate specific phenomena such as condensate impairment.Beside the high technical demand associated with understanding the physical behaviours of gas-condensate reservoirs, the variability in static and dynamic characteristics of the three Saih Nihayda sandstone reservoirs offers commercially challenging development options. Comparison studies included commingled reservoir production versus non-commingled and the impact of hydraulic fracturing versus non-fracturing on reduction in total well numbers and acceleration of early condensate. The paper touches on the benefit of variability in characteristics coupled with economical and technical viability on considering exotic development options like dump-flooding and gas recycling.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn comparison to on-shore or shallow water fields, there is limited experience in the industry for deepwater well performance prediction. The development of deep offshore reservoirs is a high risk exercise: in addition to commercial and environmental exposure, the sparsity of early exploration data compounds with the inherent geological complexity of turbiditic formations, making any performance prediction, and therefore development planning, highly uncertain.Prediction of a well performance is generally a twofold matter: predicting the initial rate of the well and the longevity of the well. Historical information is often extremely useful in such an exercise. In a Deepwater field in the Gulf of Mexico, understanding the behavior of existing wells and reasons for their historical deviations from prediction has formed a major input into the design of the next Phase development wells.While the new technologies that are emerging for deepwater primarily encompass the areas of drilling and completions, and subsea systems, technologies addressing subsurface uncertainties are also rapidly surfacing. The understanding of some of the major subsurface challenges, such as compaction, compartmentalization and completion failures has, naturally, evolved as new related technologies evolved.Technological advances in the area of 4D seismic have enhanced the understanding of underground water movement and the distribution of depletion patterns. And while fault density, position, extent, direction and transmissibility remain a large uncertainty in most GOM fields, the application of state-of-the-art seismic processing and simulation technologies is believed to be a major contributor towards the mitigation of such.Reservoir sand quality and fluid properties have, typically, dictated certain completion designs for wells and a certain operating philosophy. Another example of advanced technology implementation, in GOM multi reservoir setting, is the deployment of an integrated field-planning tool, linking individual reservoir models to a surface facility network model. This tool manages overall system flow parameters, thus, enhancing the predictability of the field performance.The focus of this paper is to address the challenges associated with performance prediction for deepwater wells and the techniques used to mitigate such challenges, as related to GOM fields.
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