With the increasing demand in domestic energy requirement and with declining production rates from mature fields of offshore Malaysia, PETRONAS has embarked on an aggressive campaign to address the decline in rates as well as increase the reserves through proven Enhanced Oil Recovery (EOR) application. An immiscible Water Alternating Gas (WAG) process is found to be the most favorable EOR method due to gas supply availability, proven world-wide application, and promising results in improving injection fluid sweep efficiency and reducing residual oil saturation. To reduce the uncertainty of EOR technical studies under low oil price, a comprehensive integrated procedure is required to study WAG performance and define key factors that impact flow efficiency under three-phase flow conditions for a more representative full-field reservoir simulation study results. This procedure involves a detailed comprehensive parametric study of the cycle dependent hysteresis starting from extensive literature review, followed by laboratory experiments and extracting pertinent WAG parameters from coreflood history matching and finally applying these parameters in full-field reservoir simulation study. This study demonstrated that the WAG cycle dependency of relative permeability during WAG process is one of the key factors that has significant impact on WAG performance and recovery factor. This feature cannot be captured by conventional three-phase flow models used by reservoir simulators. The study indicates additional recovery factor of about 1%-2% compared to the base-case WAG model without WAG hysteresis.

Average recovery factor in offshore field under discussion is relatively moderate due to wider well spacing and poor sweeping efficiency thus leaving significant volume of oil behind in the reservoir. Timely application of EOR is therefore necessary to enhance the recovery factor to a reasonable level. Among the various EOR processes and techniques of EOR screened, studies found immiscible water-alternating gas (IWAG) injection as the most suitable and viable option for this Malaysian mature offshore oilfield. Realistic estimate of incremental oil by EOR is paramount as IWAG application involves high CAPEX and OPEX project. Therefore, representative is required to be generated in the laboratory for constructing a realistic reservoir simulation model to understand the three phase flow in porous media and support the IWAG process for full field implementation. Important parameters in this case are residual oil saturations in sequential injection of displacing fluids water and gas and trapping of gas, injection volumes and frequency of alteration. Therefore, IWAG core flooding experiments under reservoir conditions need to be performed, results quantified and parameters for hysteresis modeling established.This paper addresses the challenges and strategies of IWAG core flooding experiment performed under reservoir conditions using representative composite native cores, live reservoir oil sample, field produced gas sample and synthetic formation brine water. The laboratory injection rates are considered equivalent to the field fluid advance velocity like in any standard displacement steps. Also, gravity stable injection mode is considered to achieve the best IWAG displacement performance. These challenges and strategies are drawn from lessons learned during accomplishment from earlier IWAG core flooding experiments. The IWAG core flooding experiments were performed on composite field core samples, arranged according to Langaas method, using current field production gas with 60 mole % CO2. The composite reservoir core samples were initially saturated with live oil and irreducible formation water and then flooded with formation water and seawater to residual oil saturation at reservoir conditions. Following, waterflooding, a number of water and gas cycle slugs were injected. The displacements were conducted at pressures well below the estimated minimum miscibility pressure during these experiments. Laboratory studies and numerical simulation study conducted on the applicability of immiscible WAG injection using high CO2 content produced gas indicated that 7.0 % additional oil recovery over waterflooding period can be recovered.

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SPE Member Abstract The Baram ‘South’ area is a largely undeveloped fault block in the Baram Field which contains some 154 MMstb of oil. Due to the elongated nature of the fault block, the moderately high in-situ oil viscosity of 6 cP. and the strong water drive, a horizontal well development has been identified to provide optimum reservoir development in the 14.0 sand. As a result, a horizontal well simulation study to support the requirement for horizontal wells has been carried out. The objectives of this study were to confirm the reserves and performance of the horizontal wells as compared to conventional wells and at the same time understand the key parameters that influence the horizontal well performance. Due to the lack of production history for this reservoir, in addition to no representative core and PVT data, the challenges lay in acquiring the most representative data to be used in the simulation study. This paper describes the approach taken in the simulation; from utilising core and PVT data from neighbouring fields, establishing a geological layering based on well log correlations and finally the setting up of the simulation model and grid system. In addition, prediction runs and sensitivity studies are also discussed, which identified the key parameters that impact horizontal well recovery and performance. The base case results confirmed the merits of a horizontal well development as compared to conventional wells. They also support the reserves, watercut and GOR performance of a horizontal well as derived from analytical calculations. However, the simulation gave new insight into the declining gross production. The sensitivity studies highlighted the need to obtain core data and fluid samples during development, for use in future simulation studies. Introduction The Baram Field is situated approximately 25km. off-shore Lutong, Sarawak, Malaysia, in about 40 to 200 ft of water (Figure 1). It is the largest and most structurally complex field in the Baram Delta Province, with in excess of 750 identified hydrocarbon bearing reservoirs. The structure is an elongated, East-West trending anticline which could be sub-divided into major and complexly faulted down-thrown blocks (‘A’ and ‘B’ Areas), and a simple, low relief up-thrown block closed against the main Baram Growth Fault (‘South’ Area) (Figures 2). The prospective interval ranges in depth from 2,500 ftss. (shallow I reservoirs) to 9,000 ftss. (deep S reservoirs); and consists of alternating sand and shale sequences deposited mainly in coastal, coastal fluviomarine and fluviomarine inner neritic environments. P. 455

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.