This paper describes how petrophysical thin-bed analysis is applied to an integrated static and dynamic modelling workflow to obtain a history match based on 3 years of production, for a series of relatively thin heterolithic reservoirs. Previous reservoir simulation work based on conventional petrophysical interpretation for property modelling, indicated insufficient connected STOIIP and permeability-thickness to match flow behaviour observed from surveillance data. Therefore, an alternative thin-bed approach was proposed to address this fundamental reservoir characterization issue. It is well known that across highly-laminated sandstone-shale intervals, the acquired log measurements of the sandstone laminations are adversely affected by shoulder effects due to inadequate vertical resolution of most logging tools. Furthermore, the resistivity of thin sandstones is suppressed by the high conductivity of silt-clay laminations which further compounds the problem. Thisleads tothe underestimation of reservoir properties and consequently, in the underestimation of hydrocarbon volumes and permeability-thickness. The thin-bed approach utilises available core and high-resolution resistivity-based wellbore images together with open-hole logs. These are used as inputs to generate a set of petrophysical properties, via a log resolution enhancement (LRE) method, which are more representative of the reservoirs under study. The petrophysical improvements made, relate particularly to net pay thickness, porosity, permeability and saturation estimations. This paper also demonstrates how thin-bed properties are propagated into the static modelling workflow, to produce a series of realizations which results in improved reservoir characterization, with more accurate in-place volumes and flow characteristics. In practice, the application of thin-bed analysis requires careful refinement to 3D grid design so that the effects of thin-bed heterogeneity are captured to facilitate history matching in simulation. By integrating this thin-bed approach, an improved history match is obtained more efficiently and without significant application of local modifiers. This improvement further infers that thin-bed log analysis is much more appropriate than ‘conventional’ log analysis for thinly-bedded heterolithic reservoirs not only in this field, but potentially to many similar reservoirs in this basin, and elsewhere. This work ultimately led toa successful infill drilling programme and opened up potential for extended development to include secondary recovery; as opposed to ad-hoc workover potential, as described in the original Field Development Plan.

The heterolithic thin-bedded sand and shale are very commonly associated reservoirs column in shallow water clastic depositional environment in Malaysia Basin. The complexity in reservoirs characterization of heterolithic thin-bedded sand often leads to underestimating the potential contribution of these types of the reservoir for development and exploration targets. The naturally laminated of heterolithic thin-bedded sand make it more difficult in building the realistic 3D geological model and has an impact on volumetric calculation and reserve estimation. This study is applied in the development phase by introducing Log resolution enhancement methods in laminated thin-bedded sand characterization to quantify the reservoir potential with high-resolution 3D modelling methods. The quantification of sand and shale in thin bedded analysis using core data and image logs, then transform into lithofacies classification from sand and shale volume cutoff. The distribution and computation of lithofacies and reservoir properties build into a 3D model is obtained from a geological depositional environment analog at field-scale of a conventional setting. The results indicated high-resolution 3D geological modelling successfully preserved the characterization of thin-bedded sand and shale; and revealed an excellent correlation with the image log. The presence of inter-bedded sand and shale of reservoir column in the 3D geological model provides the quantification of thin-bedded sand contribution and potential realistic volumetric estimation for the entire reservoir interval. The thin-bedded reservoir characterization and high-resolution 3D modelling technique successfully address the existent of heterolithic reservoir facies previously simplified.

Thin beds are a prominent feature in many recently discovered hydrocarbon reservoirs around the world. Not only are they typically difficult to evaluate, which leads to high reserves uncertainty, they are also frequently associated with inconsistent well performance. One of the main challenges in the evaluation of thinly-bedded reservoirs is an accurate productivity assessment. High-resolution borehole image logs provide us with detailed information on the internal structure of reservoirs sands, sand quality indications as well as a net-to-gross determination. Reliable formation evaluation requires further high-resolution petrophysical and geophysical logs (for an initial permeability estimation, free fluid volume, saturation, formation anisotropy and structural information). However, as per reservoir testing information (pressure, fluid types, PVT properties, permeability and producibility), this dynamic reservoir characterization method needs to be properly planned and evaluated. In the past, the use of full scale Drill Stem Test and Production Tests were conducted to obtain reservoir parameters including zone productivity. However, due to costly operations especially in marginal and also deepwater reservoirs, different scales of pressure transient test have been introduced1, 2, and 3. Several publications have discussed the use of smaller scale testing to obtain reservoir information. However, there have been no publications showing a complete comparison of pressure transient data obtained from several scales of measurement when heterogeneity is present in the reservoirs. This paper therefore aims to present a comparison of results obtained from alternative formation testing methods in a relatively thin (ten of meters) formation which are a single probe Wireline Formation Tester, dual packer Wireline Formation Tester, and full scale well test. This paper also discusses ways to optimise the testing methodology in such thin reservoirs. The application of an Interval Pressure Transient Test (IPTT) using a single probe as well as the dual packer WFT are illustrated and discussed in details. Their applications, specifications, advantages and disadvantages over the conventional testing method are extensively covered. This study aims to aid in devising suitable field development strategies at an acceptable cost while maintaining satisfactory operational efficiency.

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Thinly bedded sand-shale heterolithic are commonly found as a marginal reservoir in the Malay Basin. In the evaluation of heterolithic reservoirs, a key challenge is to determine the appropriate petrophysical properties cutoff. This study used the Modular Dynamic Tester (MDT) pressure tests to determine the appropriate petrophysical properties cutoff applicable to heterolithic intervals. Intrinsic permeability analysis and MDT mobility plots were used to determine the cutoffs for shale volume and total porosity. Subsequently, hydrocarbon pore volume thickness (with shale volume and porosity cutoff applied) was plotted against water saturation to determine the water saturation cut-off value. In this case study, the reservoir cutoffs applied are shale volume less than 60% and total porosity in excess of 12 %. The hydrocarbon pay cutoff was set at a water saturation less than 85 %.