Malaysia’s oil predominantly comes from offshore fields. Malay Basin located to the East of Peninsular Malaysia contains most of the country's oil reserves. In the maturing oil fields of Malaysia, EOR options are being field-tested for enhancing and prolonging production. A Water Alternating Gas (WAG) pilot was implemented in the Dulang Field S3 Block during 2002–6. The S3 Block contained six wells (three producers and three injection wells) in two reservoirs namely E12/13 and E14. This pilot project was the first EOR pilot in Malaysia. The main objectives of the pilot project were to design and develop the EOR scheme, and to evaluate the feasibility of WAG injection to maximize the oil recovery from this and other similar oil fields. A comprehensive monitoring was undertaken to assist in evaluation of pilot performance. Identification of optimal operating conditions, Dulang field-specific screening criteria and success indicators were perceived to be germane for future WAG implementation. Oil bearing sands of the Dulang field were deposited under fluvial or near shore environments as parts of sand-shale sequences. These strata were subsequently folded and faulted, resulting in discrete compartments’ with uncertain flow continuity across various faults. Due to existence of numerous major as well as, minor faults and thinness of shale layers at certain places, the critical considerations for EOR were a) confinement of the injected fluids within individual compartments, and b) flow continuity between different injector and producer wells. It was therefore decided to use different water and gas phase tracers at each of the three injection wells within the S3 block. The data gathered were used for assessing internal communication, flow parameters and inter-well reservoir heterogeneity such as high permeability streaks. This paper discusses details of the tracer program and significant responses observed during the pilot implementation.

After 30 years of waterflooding, distributed temperature sensors (DTS) data on an oilfield has recorded up to 50% reduction in reservoir temperature from its initial value of 120°C. Literature review showed previous efforts are more inclined towards interpretating DTS data to determine layer contribution in a single well rather than studying the impact of temperature change on the field performance and recovery factor. Changes in reservoir temperature will cause a change in reservoir fluids properties and fluids mobilities and subsequent recovery factor will be impacted. In order to determine the impact of reservoir cooling on IWAG (immiscible water-alternate gas) performance, a comprehensive study has been performed combining coreflood experiment with a 3D reservoir modeling. 3D thermal reservoir model has been constructed and calibrated for the purpose of determining the temperature distribution across the field. The model indicates that with higher injection volume of water; reservoir temperature is lowered with temperature distribution highly influenced by the reservoir properties, injected volume, and fluid properties. The coreflood experiments have been performed under isothermal and reduced temperature using a stack of native cores with average properties closely match the reservoir rock that carry most of the oil in place. The results showed an incremental IWAG recovery factor of up to 4% (STOIIP) higher in the reduced temperature experiment compared to IWAG experiment under isothermal conditions. This research paper has demonstrated that ignoring the effect of reservoir cooling in IWAG project can lead to an underestimated IWAG recovery factor and eventually impacting the overall project economics.