Most of the Malaysian oil fields are mature and the need for IOR/EOR driven development planning is vital to maintain the national production. The most common EOR methods employed in Malaysia are immiscible WAG and CEOR. However, one of the main problems in WAG is how to control gas mobility to minimize the conformance issue and maximize the 3-phase region in the reservoir. Using Foam is a relatively cost effective way of controlling gas mobility by means of low concentration of surfactant. However, the practical implementation has been hindered due to the lack of general understanding of the complex process of foam phase behavior and flow dynamics in porous media, the absence of reliable predictive models of multi-phase foam flow, and also the challenges in upscaling the lab results to the field application.The data integration, fundamental understanding, input evaluation and predictive modeling of WAG and Foam Assisted WAG (FAWAG) have been reviewed in this work using two extensive core flooding data of one of the Malaysian oil field in two different simulators. Review of the laboratory procedure showed the importance of taking proper pre-design measures to be able to achieve conclusive results. The modeling practice shows that output parameters from coreflood experiments might be affected by forced history matching and consequently unrealistic simulation input parameters as well as the shortcomings of the predictive capability of different simulators.The study showed that in the core flood experiments and simulations, various aspects need to be carefully considered including:• Reliable data integration and understanding of the physics/dynamics involved in the process are important for proper evaluation of the foam effect. • Simulation studies to be used for the pre-design and optimization of the coreflood experiment and parameters (i.e., rate, cycles, pore volume, etc.). • The measured rates and pressures must be of consistent resolution to be able to capture the exact phase breakthroughs and precise fractional flows of the experiment. • The SCAL endpoints and WAG parameters must be measured and fixed prior to FAWAG experiment and simulation.• Capillary end effect, formation water salinity effect on contact angle and capillary pressure impact on coreflood results needs to be carefully considered in both laboratory and modeling stages. • Different commercial simulators may results in different prediction on foam output and the effect, hence proper evaluation, de-risking and sensitivity analysis should be performed to capture the foam EOR window of opportunity.

Chemical EOR projects were very active during 1980"s, however, during 90"s the interest in chemical EOR has fallen due to the low oil prices and also technical challenges that the methods poses. While surfactant flooding has difficult design considerations of chemicals, large capital requirements and is very sensitive to local reservoir heterogeneities, alkali can react strongly with minerals in the connate water and reservoir rocks may adversely impact the process. This complex process is yet to be understood. If the field is offshore, chemical EOR becomes even more challenging due to sophisticated logistics, incremental costs, highly deviated wells, larger well spacing and limited well slots on the platform. However, recently there has been a renewed interest in chemical flooding mainly due to valuable insights gained through chemical floods done in the past and better technical understanding of the processes and favorable economic conditions.

Securing long-term energy supply for Malaysia is one of the prime responsibilities of PETRONAS; and Malaysia Petroleum Management (MPM) has been entrusted to shape the industry and enable efficient exploitation strategies and optimal development planning of Malaysian hydrocarbon assets. Production sustainability and reserve growth/addition are among the key focus area in MPM; hence, strategies and efforts are being formulated to improve the average oil field RF to more than 40%. Objective assessment of field performance, identification of recovery gaps and defining roadmap to improve field's ultimate recovery factor are critical steps to maximize the field potential ad ultimate value. This paper demonstrates the application of a hybrid workflow, comprising of data analytics-based performance benchmarking and Field Development Plan (FDP) analog assessment, to identify potential development and field management opportunities for improving economic recovery factor of an oilfield. This novel workflow consists of three key steps. First step involves reservoir performance assessment through application of diagnostic plots, decline trends and pressure/production/injection history to validate existing reserves classified as ‘No Further Activity’ (NFA). NFA reserves along with maturity assessment of undeveloped/contingent resources will provide validated recovery factor for the field. Second step is gap analysis of validated recovery factor against benchmark RF computed through data analytics carried out in Reservoir Performance Benchmarking (RPB) tool. The third and final step focusses on monetizing the RF gap and replicating best development practices through assessment of analogue reservoirs and Field Development Plans (FDPs). Analogue development cases can be from reservoirs within same field or reservoirs with similar complexity index based on RPB tool. This step involves making various cross-plots to identify opportunities like infill drilling, secondary recovery requirement, optimal producer to injector ratio, waterflood & production optimization and operational excellence. This workflow has been successfully applied to various oilfields (mature & greenfield) within Malaysia and results have been presented in this paper. The workflow has helped to identify numerous development opportunities to improve economic recovery factor e.g. new producer/injector wells, monetization plan for minor oil reservoirs, waterflood optimization and voidage management plans. These opportunities (subsurface/well/surface) are being matured for execution through MPM's enabling processes like Asset Value Framing (AVF), Asset Development Integrated Review (ADIR) and Asset Management Integrated Review (AMIR). Application of recovery factor improvement workflow coupled with reservoir benchmarking results has facilitated opportunity identification in Malaysian oilfields and defined roadmap to augment nation's oil reserves base and improve the average oil field RF to more than 40%. Using this workflow, RF gap identification in existing oilfields can be completed in relatively short period of time and actionable plans can be framed for maximizing recovery factor of the respective field.

Deep water fields are commonly subject to high development cost, challenging topside and subsurface issues and uncertainties. The level of heterogeneity, compartmentalization, fault intensity, reservoir connectivity, pressure and flow communication across the field, sand/fine production, wellbore stability are commonly less well understood at the time the development decision is made. The reservoirs may also consist of very thin beds to thick blocky sands and the reservoir properties can vary significantly both laterally and vertically throughout the field.Pressure maintenance and water/gas injection can be part of the selected development strategies from day one. Due to the high uncertainties and development cost, both producers and injectors might be pragmatically commingled across various reservoirs with no additional sandface control and operational flexibility. Reservoir management strategies may rely on field/reservoir level voidage replacement ratio (VRR) control with no additional selectivity and control on water/gas injection. This strategy combined with the above mentioned uncertainty issues can potentially lead to injection conformance issues and reduced recovery factor due to sub-optimal sweep efficiency at the sand by sand levels. A deep water example has been studied in this work showing the conformance issue and uneven pressure distribution confirmed by different PLT campaigns and MDT pressure surveys for various reservoirs under VRR control. TX 75083-3836, U.S.A., fax +1-972-952-9435

It shall never be over-emphasized that the balance of cost and value is very crucial in determining the commercial feasibility of a field development or redevelopment project. The values are generated by wells that could fetch higher productivity and could effectively drain out larger reservoir hydrocarbon fluid volume. Well drilling and completion costs and their surface production supporting facilities costs have been steadily increasing in recent years. Subsurface engineering studies shall therefore also focus on optimizing the well placement and orientation, the well type and completion selection, the life-cycle control of well inflow and outflow, with the minimum well count to yield higher values. This paper entails various methodologies of selecting drainage and injection points by combining the remaining mobile oil, current productivity, and current pressure depletion maps constructed from history matched reservoir simulation models. Base on predominant drive mechanisms in the reservoirs studied, governing parameters were coupled in 3 property groups and normalized individually. A known heuristic approach was also adapted to construct a Simulated Opportunity Index (SOI) map. A correlation between the SOI and recoverable reserve (EUR) was established by simulation prediction runs for each drainage or injection point selected, sand by sand in the studied reservoirs. The studied reservoir cases including a vast thin oil-rim reservoir, a huge multiple stacked reservoir, a complex compartmentalized reservoir, and a prolific deep-water reservoir. Clustering the selected drainage and injection points in several sands to further maximize the well productivity, optimization of the inflow control for the selected commingled sands, and the design of cost effective completions, shall be addressed later sequentially in separate papers. Introduction The technical challenge is getting difficult as fields are reaching maturity. The complexity and uncertainty of the field require a detail understanding of both reservoir characteristics and facilities performance in order to identify and optimally exploit the field potential. In multi layered reservoirs, substantial reserves is located in minor reservoirs that demand innovative solution for cost effective redevelopment. The wells drilled in later part of the brown field especially require maximizing reservoir contact, higher well productivity for higher recovery to justify the well cost. Various well architecture options with elaborated smart bottom-hole devices is being deployed to control drawdown and sand production. To achieve maximum recovery with suitable well architecture, meticulous selection of optimum drainage and injection point is critical to boosting recovery from a brown field. Drainage point can be selected once confidence over complex remaining oil evaluation is established. Qualitative and quantitative methodologies ranging from surveillance and performance evaluation to 3D models are used to establish drainage and injection points in matured or brown reservoirs.