Integrated Full-Field Review of Betty Field for Building Predictive Models to Reduce Uncertainty in Reserves and Identifying Future Potential
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA multi-discipline integrated full field review (FFR) was conducted for Betty field, offshore Malaysia, in order to build a set of 3D predictive numerical models from multi-scale geological, seismic, petrophysical, reservoir and production engineering data. This study reassessed field stock tank oil initially in-place (STOIIP) volumes and remaining reserves, determined infill drilling potential and identified opportunities to improve both short-term and long-… Show more
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A reservoir simulation model, calibrated with 25 years of production history, was used to determine a cost effective reservoir management and production strategy, which optimises future recovery from an oil rim reservoir in the Betty Field, offshore Malaysia. The reservoirs consist of good quality sands in a coastal depositional environment with an anticlinal structure terminated at the crest with a growth fault. The history match confirmed that A6.0 reservoir, unlike all others in the field, which co-exist within a stacked sequence, is surprisingly isolated from the surrounding aquifers. Prior to its premature shut-in, oil production reached 5000 bopd. However, a drastic decline in reservoir pressure caused the evolution of a large secondary gas cap and a steeply increasing producing gas-oil ratio. The recovery factor for this reservoir stands at 25%, significantly less than for the best reservoirs in the field. After more than a decade shut-in, secondary and tertiary recovery methods investigated in this study included dump flooding from adjacent reservoirs, gas re-injection and water injection based on an extensive prior screening exercise. The limited prospective increase in reserves highlighted the need for a technically sound but also financially feasible solution. Since the current facilities were not intended for any pressure maintenance or enhanced oil recovery scheme, a number of technical limits arose due to space and weight constraints on the platform. Furthermore, fluid separation and export constraints had to be taken into account. Consequently the reservoir management plan required a field-wide optimization of the scheduled activities in order to identify bottlenecks in the gas handling capacity. Simultaneously with the model study, shut-in wells' production potentials were re-tested in order to gather additional data and, a water dumpflood pilot was implemented. Introduction and Field Overview The Betty field is located 40 km offshore Miri in the Baram Delta area of Sarawak, Malaysia. It was discovered in 1968, and its production started in 1978. The field consists of 22 stacked reservoirs of varying size and thickness at depths of 7200 to 9650 ft sub-sea. The average water depth is 225 ft. The field is operated by a single unmanned production platform that contains 24 well slots with 48 tubing strings. In the Betty field, some producing reservoirs have experienced high recovery efficiency, while in others the recovery has remained relatively low. One objective of a recent field redevelopment planning study was to investigate and resolve these recovery efficiency anomalies, and to identify areas where recovery could be improved. This is particularly important since, at the present time, no infrastructure such as a compression system or offshore water treatment facilities is available on the platform. Major changes would have to be implemented prior to any secondary or tertiary recovery method and would require economic justification. In addition, existing fluid export constraints, arising mainly from the current regional gas export scheme, had to be taken into account for an optimised field-wide reservoir management plan. A recent full field review[1] confirmed the presence of a strong aquifer drive throughout the Betty field, aquifer energy provided to the reservoirs combined with the favourable mobility ratio resulted in excellent sweep efficiency. However, one of the reservoirs (A6.0) was found to be almost entirely isolated from its aquifer, resulting in no discernible pressure support. It was estimated that the volume of the aquifer was approximately one hundredth of the aquifer in the adjacent reservoirs with about 0.25 billion barrels of water. Material balance as well as history matching with numerical simulation model confirmed solution gas drive as the predominant energy source for this reservoir. Among all the Betty reservoirs, this particular reservoir was considered the only viable candidate for investigation of secondary and tertiary recovery practices. The decision was based on the anticipated recovery targets and the economic prospects of any method for improved or enhanced oil * Now with Shell E&P
A reservoir simulation model, calibrated with 25 years of production history, was used to determine a cost effective reservoir management and production strategy, which optimises future recovery from an oil rim reservoir in the Betty Field, offshore Malaysia. The reservoirs consist of good quality sands in a coastal depositional environment with an anticlinal structure terminated at the crest with a growth fault. The history match confirmed that A6.0 reservoir, unlike all others in the field, which co-exist within a stacked sequence, is surprisingly isolated from the surrounding aquifers. Prior to its premature shut-in, oil production reached 5000 bopd. However, a drastic decline in reservoir pressure caused the evolution of a large secondary gas cap and a steeply increasing producing gas-oil ratio. The recovery factor for this reservoir stands at 25%, significantly less than for the best reservoirs in the field. After more than a decade shut-in, secondary and tertiary recovery methods investigated in this study included dump flooding from adjacent reservoirs, gas re-injection and water injection based on an extensive prior screening exercise. The limited prospective increase in reserves highlighted the need for a technically sound but also financially feasible solution. Since the current facilities were not intended for any pressure maintenance or enhanced oil recovery scheme, a number of technical limits arose due to space and weight constraints on the platform. Furthermore, fluid separation and export constraints had to be taken into account. Consequently the reservoir management plan required a field-wide optimization of the scheduled activities in order to identify bottlenecks in the gas handling capacity. Simultaneously with the model study, shut-in wells' production potentials were re-tested in order to gather additional data and, a water dumpflood pilot was implemented. Introduction and Field Overview The Betty field is located 40 km offshore Miri in the Baram Delta area of Sarawak, Malaysia. It was discovered in 1968, and its production started in 1978. The field consists of 22 stacked reservoirs of varying size and thickness at depths of 7200 to 9650 ft sub-sea. The average water depth is 225 ft. The field is operated by a single unmanned production platform that contains 24 well slots with 48 tubing strings. In the Betty field, some producing reservoirs have experienced high recovery efficiency, while in others the recovery has remained relatively low. One objective of a recent field redevelopment planning study was to investigate and resolve these recovery efficiency anomalies, and to identify areas where recovery could be improved. This is particularly important since, at the present time, no infrastructure such as a compression system or offshore water treatment facilities is available on the platform. Major changes would have to be implemented prior to any secondary or tertiary recovery method and would require economic justification. In addition, existing fluid export constraints, arising mainly from the current regional gas export scheme, had to be taken into account for an optimised field-wide reservoir management plan. A recent full field review[1] confirmed the presence of a strong aquifer drive throughout the Betty field, aquifer energy provided to the reservoirs combined with the favourable mobility ratio resulted in excellent sweep efficiency. However, one of the reservoirs (A6.0) was found to be almost entirely isolated from its aquifer, resulting in no discernible pressure support. It was estimated that the volume of the aquifer was approximately one hundredth of the aquifer in the adjacent reservoirs with about 0.25 billion barrels of water. Material balance as well as history matching with numerical simulation model confirmed solution gas drive as the predominant energy source for this reservoir. Among all the Betty reservoirs, this particular reservoir was considered the only viable candidate for investigation of secondary and tertiary recovery practices. The decision was based on the anticipated recovery targets and the economic prospects of any method for improved or enhanced oil * Now with Shell E&P
A revised Field Development Plan (FDP) for Betty Field was prepared based on a process that was simultaneously sensitive to reservoir and operational constraints and uncertainties. This so called "Optioneering" process was an iterative, multidisciplinary optimization task that generated an action plan based on multiple options developed by reservoir, production, drilling and facilities engineering and ranked by economics. The process specifically involved first generating a series of unconstrained production options, which then considered drilling reach and anti-collision limitations, and finally had the appropriate facilities and regional evacuation constraints imposed. To achieve this, history-matched numerical reservoir models were first run within the framework of an infill well-location optimization software package. Then, drilling constraints were imposed with drilling planning software and facility constraints were included via a surface coupling system for multiple-reservoir models. Uncertainties in the reservoir characteristics and in the facilities/evacuation schemes were addressed by quantifying their impact on the ultimate recovery efficiency. During the optioneering exercise, more than 100 unconstrained options for seventeen stacked reservoirs were identified from the perspective of infill drilling, pressure maintenance by gas injection and/or waterflooding, high pressure gas production, horizontal wells and production enhancement work. Based on typical costs and economic rank, the high potential unconstrained production options for each reservoir were determined. After imposing the drilling constraints, all reservoirs were then coupled to account for surface facility constraints. In the final analysis, five sidetrack wells reaching 12 new drainage points (NDP) over 10 reservoirs were designed. This infill drilling scheme will increase current reserves by 128%. Furthermore, a gas injection scheme identified as the optimum plan for A6.0 reservoir will increase current reserves by 28%. Field wide recovery factor will be improved by 9%. Introduction Oilfield development and management decisions are usually made under high risk and uncertain conditions that stem from both surface and subsurface unknowns. The optimized field and reservoir management can be achieved through successful uncertainty management. Uncertainty management has two main aspects: minimizing uncertainty followed by estimating risks from remaining uncertainty. Minimizing uncertainty reduces the risks and improves project economics. Uncertainty can be managed by integrating multi-discipline multi-scale data and utilizing 3-D numerical models as predictive tools. Then, estimating risk from the remaining uncertainty allows us to make informed investment decisions. An ideal FDP should not only include recommendations for an optimum development strategy with its implementation plan, but the estimated risks involved in executing the proposed plan. So the ideal plan would have two parts: optimization and risk assessment, which are also interrelated. However, ranking and screening of options for the plan should be done only after taking the risk factors into account. Therefore, an iterative procedure is required which generally converges after several iterations. Converging to an optimized field plan involves identifying the best suited activity, and then designing that activity to its optimum level. Final risk exposures for the selected activity are estimated and reported, whereby potentially high risk aspects are known to the implementation team and accounted for in economic evaluations. Generating options, and screening them to achieve an optimum FDP with its associated risks requires an optioneering process.
Oil Invasion in Gas Zone and Sweep Efficiency Due to Stratigraphic Barrier in an Active Waterdrive System, Hollin Formation, Ecuador
fax 01-972-952-9435. AbstractThe main objective of this study was to describe the nature, distribution, and physical characteristics of the reservoir, by integrating geophysical, geological, petrophysical, and production data in a three dimensional geological and simulation model that represents the behavior of the Hollin reservoir in Bermejo field. The Hollin reservoir required significantly higher effort due to the strong aquifer, the complex relationship between heterogeneity influences, the movement of the water from the aquifer into the reservoir, water and gas conning, stagnation of unproduced oil zones, and migration of oil towards gas zones.When production data was analyzed, it was determined that even thin shales (on the order of 2-5 ft. or greater) played a role in enhancing reservoir production by delaying water and gas conning and water influx in the Hollin fluvial sandstone. Mapping the shale barriers was as important as mapping the sand bodies. It was decided to correlate the shales interpreted from well log data and introduce shale tops and bases in the geological model. Therefore, in the geological and simulation models shales have been modeled explicitly, down to a five foot resolution. A Stratigraphic geocellular model was constructed to describe the 3D petrophysical properties, calculate hydrocarbons in place and to prepare reservoir simulation grids. Geological models incorporating shales were modeled. If shale was locally absent, the "shale zone" was assigned the appropriate reservoir properties determined from well and/or seismically derived attributes. J-Function analysis was implemented successfully in assigning oil saturation. Calculated oil saturation profiles at initial and current times were compared with initial well log oil saturations.History matching and initialization were conducted to validate geological, petrophysical, PVT, and reservoir models. Flooded and non-flooded regions of reservoir, current WOC and GOC were identified. Areal extent of localized thin shale lenses were modified during history, matching active water breakthrough well by well. The amount of oil invasion in the original gas zone, stagnated oil, and gas contraction volumes were calculated in the most productive marker, Naranja. Current GOC has moved from the original GOC position. Actually, the amount of oil invasion was not significant when it was compared to the volume of stagnated oil.When geological and simulation models are built and data gathered according reservoir specific problems, successful history matching and predictions can be obtained.
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