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.

The Guntong field is one of the largest oil fields in the Malay Basin. With almost twenty years of production history and currently at 80% depletion, Guntong production has been on the decline since the late 90s. Despite the complexities resulting from its multiple stacked reservoirs that are developed by 150 wells, and the challenges of maximizing oil recovery from a mature offshore field, the various oil recovery improvement measures implemented at Guntong have successfully resulted in the addition of almost 80 million barrels of oil to the overall field recovery within the last five years. This paper is an overview of these initiatives which include workovers to decommingle selected reservoirs and perform acid stimulations, in addition to three infill drilling programs that were conducted within a span of three years. A fourth infill program, requiring a new satellite platform, is scheduled for completion in 2005. Positive results were also achieved by revising the field's reservoir pressure maintenance program along with optimizing reservoir management strategies such as water injection patterns. The underlying key to the success of these efforts has been the holistic approach in analyzing the field data. A more comprehensive understanding of the reservoir behavior was achieved by integrating production data, geology, reservoir engineering as well as findings from the recent infill programs. A more accurate representation of the reservoir behavior was attained through iterative comparisons between the geologic description updates and the results derived from the reservoir simulation models. Predictions from these models, which were further supported by seismic timelapse and AVO analyses, have led to the successful identification of bypassed oil regions within the field. Moreover, the availability of reliable simulation models was also instrumental in testing out and fine-tuning reservoir management strategies before their implementation. Introduction The Guntong field is an east/west compressional anticline in the Tabu-Guntong-Palas trend, approximately 11km long and 6.5km wide. Fig. 1 shows the field's location in the Malay Basin as well as a map of the I-25 horizon with the locations of the platforms. Two major north/south trending normal faults, with maximum throws of 280m, separate the field into west, central and east fault blocks. As shown in Fig. 2, the field is made up of twenty-nine stacked reservoirs belonging to the Group I (I-10 Upper / Lower, I-15, I-20, I-23, I-25, I-27, I-30, I-35, I-40, I-45, I-50, I-60, I-62, I-68, I-70, I-75, I-80, I-85, I-90, I-98, I-100/102, I-104) and J reservoirs (J-18, J-19, J-19.5, J-20, J-20.5, J-21 and J-30) which are generally from the Lower to Middle Miocene periods. The Group I sandstones are a combination of tidal, deltaic and braided fluvial sediments while the Group J consists of shallow marine and tidally influenced deposits. As such, a broad range of reservoir quality and characteristics exist throughout the field. Table 1 summarizes the key reservoir parameters of the three major reservoir groups: Upper I reservoirs (I-10 through I-45 sands), the Lower I reservoirs (I-60 through I-104 sands) and the Group J reservoirs (J-15 through J-30). Between 1985 and 1994, four platforms were installed to develop the field (Fig. 1), three of which, Guntong A, B and C, develop the east and central fault blocks (ECFB). In addition to production from the B and C platforms, production from the Tabu and Larut fields also flow into Guntong A. The field's west fault block (WFB) is developed by Guntong D, which is a central production and processing facility dedicated to the production from the WFB and Palas field.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Guntong field is one of the largest oil fields in the Malay Basin. With almost twenty years of production history and currently at 80% depletion, Guntong production has been on the decline since the late 90s. Despite the complexities resulting from its multiple stacked reservoirs that are developed by 150 wells, and the challenges of maximizing oil recovery from a mature offshore field, the various oil recovery improvement measures implemented at Guntong have successfully resulted in the addition of almost 80 million barrels of oil to the overall field recovery within the last five years.This paper is an overview of these initiatives which include workovers to decommingle selected reservoirs and perform acid stimulations, in addition to three infill drilling programs that were conducted within a span of three years. A fourth infill program, requiring a new satellite platform, is scheduled for completion in 2005. Positive results were also achieved by revising the field's reservoir pressure maintenance program along with optimizing reservoir management strategies such as water injection patterns.The underlying key to the success of these efforts has been the holistic approach in analyzing the field data. A more comprehensive understanding of the reservoir behavior was achieved by integrating production data, geology, reservoir engineering as well as findings from the recent infill programs. A more accurate representation of the reservoir behavior was attained through iterative comparisons between the geologic description updates and the results derived from the reservoir simulation models. Predictions from these models, which were further supported by seismic timelapse and AVO analyses, have led to the successful identification of bypassed oil regions within the field. Moreover, the availability of reliable simulation models was also instrumental in testing out and fine-tuning reservoir management strategies before their implementation.