Data-Acquisition Optimization Maximizes Value of Mature Oil-Rim Reservoirs
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The XamXung field offshore Sarawak, Malaysia, is a 47-year brownfield with thin remaining oil rims that have made field management challenging. The dynamic oil-rim movement has been a key subsurface uncertainty, particularly with the commencing of a redevelopment project. A reservoir, well, and facilities-management (RWFM) plan was implemented to optimize development decisions. This paper is a continuation of paper SPE 174638 and outlines the outcome of the RWFM plan and the results’ effect on development decisions such as infill well placement and gas/water injection-scheme optimization (Fig. 1). Key decisions affected by the RWFM findings are highlighted in the complete paper.
The XamXung field was discovered in 1967, with commercial production established in 1972. The field is a simple faulted anticline bounded by two major faults in the north and south. The field consists primarily of clastic deposits characterized by thick sands interbedded with thin shale layers of late Miocene to Pliocene age.
The field consists of multiple stacked gas and oil reservoirs, with key producing intervals being the oil-rim reservoirs XE/XF and XH/XI, and the deeper oil reservoir XL, as well as major nonassociated gas reservoirs XA, XC, XD, XM, and XN. The main discussion of the complete paper focuses on XE/XF and XH/XI reservoir redevelopment.
XE/XF is a saturated oil-rim reservoir with initial oil-rim thicknesses of 95 and 85 ft, respectively. The XE/XF oil rim is overlain by a gas cap with m size (ratio of initial free-gas reservoir volume to initial reservoir oil volume) of 1.1 and 0.4, respectively. XE and XF reservoirs are separated by a fieldwide sealed shale layer of 10–20-ft thickness. Initial reservoir pressure and well log data acquired during the early production history suggested that XE/XF reservoirs originally shared a common gas/oil contact (GOC) but different free-water levels.
XE/XF reservoirs have an average porosity of 27–32% and average permeability of 500–1500 md. They started production in 1974 and reached peak production in 1977. The reservoir pressure has declined by only 200 psi after 45 years of production, indicating that the reservoir is under a strong aquifer drive. Gas injection into XE reservoir commenced in 1995 following an increasing water-cut trend in most of the producers, with the objective to counteract the aquifer influx and to allow uniform gas-cap gas expansion throughout the reservoir. However, the reservoir historically has produced more free gas compared with the amount of gas reinjected, resulting in the reservoir gas-cap shrinkage.
XH and XI are two major reservoirs with average oil-rim thickness of 105 ft throughout the field, overlain by 300 ft of gas cap, with m size of 2.0. The initial pressure and well-log data acquired during the early production history suggested that XH/XI reservoirs initially shared a GOC. Although the XH/XI reservoirs have a common GOC, they are geologically distinct units separated by laterally extensive shale with thickness from 6–16 ft, increasing from east to west. The nonuniform pressure depletion in XH and XI indicates that the shale layer is partially sealing. The reservoir has an average porosity of 20–25% and permeability of 50–800 md. Historical field performance indicated that XH reservoir energy was heavily supported by gas-cap expansion, whereas XI reservoir was supported by a moderate aquifer strength. Two gas injectors were drilled after 20 years of production to maintain reservoir pressure and to manage oil-rim movement; reservoir pressure was observed declining because of high production withdrawal.
A field development plan (FDP) for XamXung was approved in 2014 to improve oil recovery from the major reservoirs. An RWFM plan prepared in 2015 has been implemented to manage the oil rim and reduce reservoir uncertainties.
One of the aspects of the RWFM plan is oil-rim monitoring through saturation logging to locate the current GOC and oil/water contact (OWC). Casedhole saturation logs were acquired at the identified observation wells across the reservoir to map time-lapse oil-rim movement and its thickness distribution. Pressure monitoring with regular static pressure-gradient surveys (SGS), as well as production data, aided understanding of the balance of aquifer strength between the eastern and western flanks. Data-acquisition opportunities during infill drilling were also fully leveraged. An extensive data-acquisition program, including conventional techniques such as openhole logs, wireline pressure tests, formation-pressure-while-drilling, and reservoir-mapping-while-drilling, was implemented.
The paper includes detailed discussion of the methodology for the RWFM and FDP plans, including casedhole logging in 2016 and 2018, two phases of drilling campaigns and openhole data acquisition, and reservoir-pressure-surveillance strategy.
Discussion and Results
The redevelopment scheme for reservoir XE is to optimize recovery by squeezing the oil between expanding the gas-cap gas through crestal gas injection and sweeping the peripheral flank by water injection. Reservoir XF will achieve pressure maintenance through the introduction of water injection.
Data from open- and casedhole logs, SGS, and downhole pressure gauges provide clear evidence that the XE oil rim has moved into the gas cap on the eastern and southern parts of the reservoir and that the eastern area of the reservoir has a stronger aquifer strength than the western area. As a result, the FDP plan is to drill one water injector on the west earlier in Phase 1. The remaining water injectors at the south and east will be deferred to a Phase 3 campaign to allow more data acquisition through surveillance, newly drilled wells, and response of oil producers to the existing water-injector well. This will enable the location and number of the remaining water injectors to be optimized with better understanding of the reservoir performance post-water and post-gas injection. XF is under very strong waterdrive, and so will not benefit from water injection, further supporting the decision to restrategize the remaining water injectors to a later campaign.
The FDP identified two infill wells, Well A and Well B, to be drilled to reservoir XE/XF to optimize recovery from these reservoirs. Well A was accelerated to Phase 1 in 2016 while Well B was drilled in 2018 during the Phase 2 campaign.
The initial target for Well A was the XF reservoir. On the basis of observed well performance and casedhole data, the initial target was changed to a new target location. To mitigate current contacts uncertainty, casedhole logging was then planned at a nearby well to allow Well A’s optimization on the target sand. As a result, Well A was drilled at the new optimized location with a higher-than-planned initial production rate.
Well B was planned as a horizontal well, targeting two subunits of XE reservoir with approximately 30 ft of oil thickness. On the basis of lessons learned from Well A and no available recent data on current contacts at Well B’s target location, two nearby observer wells were identified as casedhole-logging candidates to obtain the current contacts. Unexpectedly, the casedhole-log results from these wells suggested further upward movement of contacts, 35–48 ft shallower OWC compared with last data, and thinner remaining oil-rim thickness.
On the basis of this new information, the trajectory and horizontal well placement of Well B was revisited and optimized to target the current oil-rim location. In addition, Well B’s drilling was further derisked to optimize well placement. As a result, Well B was successfully drilled with an additional 1,000 BOPD against what was planned.
Understanding the additional data acquired during the drilling campaign, coupled with reservoir-surveillance data and understanding reservoir performance, identified additional opportunities to increase recovery from XH/XI through infill drilling. An additional horizontal well was identified to be drilled in the Phase 3 campaign, targeting the oil column from both XH and XI subunits to drain the remaining oil with an expected oil gain of 1,400 BOPD. Additionally, the well location of the FDP infill wells to be drilled in Phase 3 was optimized to target a higher oil-saturation area compared with that of the FDP location. As a result, total redevelopment cost has been reduced, and the oil rate will increase from the initial 650 to 1,500 BOPD with reserves addition.
The paper also includes a discussion of the gas- and water-injection optimization strategy for the XH and XI reservoirs. Data-acquisition-campaign results indicate that less water injection is required in XI, and more in XH, to counteract the expanding gas cap. This will be managed by installing viscosity-based inflow-control devices in the new water injectors to allocate selectively more water injection to the XH reservoir. The viscosity-based inflow-control technology allows closer horizontal section placement toward the GOC to prevent early water breakthrough from stronger bottom waterdrive. Also, more water is injected to the west to rebalance the tilted contact.
On the basis of the updated understanding of the reservoirs in the XamXung field through integration of the latest data from newly drilled wells and surveillance data, it is confirmed that the strong aquifer drive is the main threat for future infills planned for these oil-rim reservoirs. Horizontal well geosteering using real-time reservoir-mapping-while-drilling will be replicated in the Phase 3 campaign.
This paper highlights the importance of data integration from geological knowledge, production history, reservoir understanding, and monitoring through regular SGS and time-lapse casedhole-saturation logging, coupled with extensive data acquisition during infill drilling. By analyzing and integrating the acquired data, the project team can restrategize confidently, and execute successfully, complex mature oil-rim brownfield redevelopment.
Data-Acquisition Optimization Maximizes Value of Mature Oil-Rim Reservoirs
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