Reservoir model is widely used in oil and gas industry for hydrocarbon resources assessment, development, and management with different depletion strategies. The reservoir model is built through integration of multi-disciplinary information, data and interpretation at various scales. Integration of data from various resolutions and scales is usually a big challenge in constructing reservoir model due to its impact to the model's ability to make a reliable production forecast. The objective of this study is to analyze the impact of scale changes in clastic reservoir modelling and to evaluate its implication to hydrocarbon volume in-place and fluid flow behavior. Several examples from clastic reservoirs of different geological environments were evaluated and data from various scale were incorporated in reservoir description in constructing a representative reservoir models. Reconciliation of various reservoirs properties using database such as core data, logs, DST and production/pressure were performed. Permeability upscaling was observed posing significant challenges compared to the other properties at each stage. Therefore, the paper puts more emphasize on permeability while briefly discuss the other properties. Other challenges including complex reservoir types such as thinly laminated reservoirs are also evaluated. The study demonstrates that different permeability modeling methods may give significant impact on the hydrocarbon in-place and fluid flow characteristic. In the absent of production data to verify the in-place, the uncertainty of in-place is inevitable. In addition to that, those different permeability models may also give different flow characteristic. It is concluded that by recognizing the scale difference and impact of averaging/upscaling with the guidance from production/pressure performance, robust reservoir model with representative reservoir properties could be achieved. This paper shares the best practices in integrating data from various scale/discipline and highlights the impact of the data integration at right scale in constructing robust reservoir model.

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The oil field is located 40 km offshore Sarawak, Malaysia in the southwestern part of the Baram Delta at a water depth of 250 feet. It is an anticline bounded by two (2) sealing faults and composed of multiple hydrocarbon bearing sand reservoirs separated by sealing shale layers. Oil has been produced since 1972 from more than 10 different reservoir units. Enhanced oil recovery (EOR) redevelopment project in the field will begin in 2018. The project will increase the crestal gas injection and initiate water injection at various locations in the water leg for two (2) major oil rim reservoirs. In a third relatively smaller reservoir water and immiscible gas will be injected in an immiscible Water-Alternating-Gas (iWAG) scheme. Required gas for the entire project will be supplied from five gas reservoirs, as well as by recycling the produced gas from the oil reservoirs. A Well, Reservoir and Facilities Management, or WRFM, plan was put together to prepare the reservoirs for the EOR project and to further optimise the development decisions. This paper outlines the objectives of the WRFM plan for the EOR redevelopment project. Key uncertainties that have an impact on the development plans are highlighted. A summary of surveillance activities required to manage the key uncertainties are given. At the end, focusing on the XE/XF reservoir group, reservoir surveillance required to monitor and manage a mature off-shore oil rim reservoir is discussed. XE/XF reservoir has a large gas cap and surrounded by an aquifer. The oil rim is dynamic in nature, which moved into the gas cap after the start of production due to the imbalance between the strong aquifer and gas cap expansion. For pressure maintenance purposes, as well as to prevent the rise of the oil rim, gas injection into the cap was started in 2001. Most recent saturation logs show that the current oil-water and gas-oil contacts in the field can no longer be regarded as even surfaces. The surveillance plan focuses on monitoring the saturation and pressure changes in the reservoir to locate the current gas-oil and oil-water contacts, and to understand the strength of the surrounding aquifer. The learnings will impact the number and locations of production and injection wells that are planned to be drilled as a part of the EOR project. In addition, the results will be used to update the existing dynamic reservoir model, which will be utilised for long term reservoir management.