Reservoir G-4, a depleted reservoir in field B had been producing from 1992 to 2015 with a recovery factor of 30% before the production was stopped due to low reservoir pressure. Due to the huge inplace volume. A secondary recovery screening was conducted and gas injection was identified as the most suitable solution to revive G-4 reservoir due to its low cost impact of 0.4 Mil. USD whilst managing to deliver the same results as other solutions (i.e. Water injection & Water Dumpflood). The project had utilized existing facilities in field B including a gas compressor. The project required only minor surface modification to re-route gas into the tubing of injection well BG-03. From simulation results, a continuous injection of 5 MMscf/d will increase the reservoir pressure by 150 psia in 9 months, with incremental potential reserves of atleast 5.0 MMstb from the benefitter wells, BG-02 & as well as incoming infill wells BG-14 & BG-15. It is also envisaged that with future development of additional infill wells, the recovery factor will be increased up to 60%. In term of gas management, field B is able to deliver additional 15 MMscf/d post petroleum operation reduction (i.e. Fuel Gas, Instrument Gas & Gas lift). With the initiation of gas injection, the project had managed to utilize and optimize 33% of additional gas production for reservoir rejuvenation purposes. The paper provides valuable insight into the case study and lesson learned of maximizing oil recovery through gas injection with minimal cost incurred. The approach is highly recommended to maximize oil recovery especially in mature fields with similar reservoir conditions and production facilities.

Maturing a secondary recovery project in an offshore multi-fault complex reservoir is challenging because considerable investment is required, especially in a low oil price environment and/or when the asset can no longer produce. However, an 85% reduction in cost with no reduction in reserves was achieved for such a reservoir through de-risking the opportunity and revising the development concept, allowing the project to be sanctioned during a low oil price environment. A water injection project with an estimated cost of 165 MMUSD was initially envisaged during the feasibility stage to increase the oil recovery of a depleted reservoir, and contractual expectations were agreed accordingly. This is due to the availability of seawater offshore and water injection being the standard improved recovery approach in the region. Without adhering to the familiarity, a reservoir simulation study was performed comparing multiple options of secondary recovery. The reservoir simulation indicated that gas injection would provide higher incremental recovery while the investment can be significantly reduced by utilizing the existing gas lift system as a gas injection system. Several improved oil recovery schemes were evaluated with the history matched dynamic model to address the depleted energy. This includes water dumpflood, water injection, and gas injection with recovery factors of 32%, 56%, and 58%, respectively, in comparison to the depletion drive recovery factor of 30%. The gas injection scheme provides the highest recovery factor and expected fastest response and thus was prioritized as the main focus over water injection. The existing gas compressor with ullage, gas source from current associated gas production, and existing idle wells are key enablers for the project. The existing assets also enable the acceleration and further de-risking by a pilot gas injection before drilling infills. The paper highlights the numerous examples of cost-saving initiatives while maximizing the oil recovery from the reservoir. This value-focused approach enabled the project to be sanctioned during a period where most offshore improved recovery projects were abandoned due to the low oil price.