The presence of a large gas cap in an oil reservoir usually presents unique depletion challenges and opportunities. While the gas provides a significant source of drive energy that contributes to oil recovery, the expansion of the gas cap typically leads to gas cusping or coning, potentially resulting in lower than optimal recovery. This case study is a large reservoir with a complex combination of stratigraphic and structural trap. The reservoir consists of middle Miocene stacked and slope-confined deepwater turbidite channel complexes. Three major canyon-type channel complex sets can be distinguished in the field, each consisting of smaller channels that display a certain degree of amalgamation.The initial depletion strategy for shallowest channel complex reservoir with limited aquifer was gas injection updip of producing wells. However, the steady ingress of gas from the crestal gas injector (as seen in 4D), into one of the most prolific wells located in this voidage region has resulted in decline of the well productivity due to increasing GOR. Moreover, the field is produced under a strict gas processing capacity and the increased gas production from the shallowest channel backs out oil production from other channelized reservoirs. To counter this GOR increase, a downdip water injector was proposed.The study evaluated the impact of simultaneous updip gas injection and downdip water injection in the subject reservoir using reservoir simulation. Analysis showed that the introduction of downdip water injector in addition to the existing gas injection resulted in an overall 2% increase in the field EUR. The increase was largely attributed to the observable reduction in the well GOR with corresponding production boost, in addition to creating gas ullage for other wells in the field. This expected gain was sufficient to justify the cost of a deepwater infill injector well.

No abstract