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Solution gas driven sandstone reservoir with water and gas injection

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This page provides a reservoir management case study for an offshore sandstone field under solution-gas drive in which water and gas injection techniques have been implemented.

Background and geological information

The highly faulted structure produces from six different productive horizons. The depositional settings range from deepwater marine turbidite fans through near shore and delta san facies to fluvial deposits. Reservoir quality ranges from high permeability (350 md) in highly continuous tidal shoals to fair quality (100 md) in moderate continuity fluvial channels. The reservoir has been developed from two separate platforms and has an extensive subsea development of satellite fields. More than 140 wells have been drilled from two platforms since initial development in 1976 with well lengths varying from 9,800 to 19,000 ft. Six subsea fields have been developed with 28 subsea producing wells. There are 28 reservoirs that are managed separately.

Program used

The primary recovery mechanism in the majority of these reservoirs was solution-gas drive with weak aquifer support, although some of the satellite fields have strong bottomwater drives. The main reservoir was developed from the two platforms: the Alpha platform began production in 1976, followed by the Bravo platform in 1984. Crestal gas injection and peripheral water injection were used in both areas in the main reservoir to maintain reservoir pressure and displace the oil zone. The secondary reservoir formations were developed with solution-gas drive mechanisms with water and gas injection applied where economically viable. The Alpha main reservoir achieved a 52% oil recovery factor. Gas-cap blowdown started in 1993. The pressure maintenance schemes continue to be used in the Bravo and Satellite fields.

Recovery performance

The expected recovery in the main formation is expected to exceed 50% of the original oil in place (OOIP) on both the Alpha and Bravo platforms, with the average recovery factor for all sands expected to reach 39% of the OOIP. The cumulative recovery to date of 33% of the OOIP compares with the 15 to 20% expected under primary depletion.

Field surveillance and management

Reservoir management in this complex field relied on a multidisciplinary team approach. The complex geological and structural natures of the fields are represented in detailed geological models. Improvements in the structural imaging of the fields through the use of ocean-bottom cable seismic and detailed sequence stratagraphic work has improved the understanding of the fields. Black oil reservoir simulation models have been built for all the major producing reservoirs. These models have sufficient detail to represent the geological and structural complexity properly. A surveillance program for each reservoir unit is defined so that cost effective and minimum production deferral interventions can be planned in advance. Asset development and depletion plans are defined for each field/reservoir unit that define the depletion plan and integrates study plans with surveillance and drilling activities. An opportunity list is developed that is reviewed routinely by the multidisciplinary asset team to ensure appropriate prioritization of resources. Reservoir surveillance data is combined with classical reservoir engineering techniques to create surveillance maps for each of the reservoir flow units. Surveillance techniques combined with simulation results are used to ensure quality forecasts and robust infill-drilling targets. Infill wells typically have a full suite of measurement while drilling (MWD) logs and modular formation dynamics testers. More complex horizontal wells tend to have less comprehensive data gathering because of cost and the risk of losing the hole.

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See also

Reservoir management

Immiscible gas injection in oil reservoirs

Immiscible gas injection case studies