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The development of the Central Luconia carbonate build-ups were strongly influenced by the interplay between eustatic sea-level and basinal tectonics. The Alpha field addressed here is one of the seismically best imaged isolated carbonate platforms in Central Luconia and dendritic features, interpreted as karst, were found to be very prominent throughout the field. Karst is a diagenetic facies, an overprint in sub-aerially exposed carbonate bodies produced and controlled by dissolution and migration of calcium carbonate in meteoric waters. The exploration well in the Alpha field encountered total losses while drilling which was believed to be as a result of drilling in to karst (common in Central Luconia carbonates). Some of the best features from Petrel, Landmark and Shell software packages have been integrated to generate an attribute volume for karst interpretation. Using Petrel Geobody, multiple 3D box probes with short time gate and optimum clipping value were used to extract the karst Geobodies. Using a short time gate box probe is crucial for CPU/memory performance and most importantly, to have better control on editing noise and non-karst signal later. Karst has a big impact on well planning (problem with losses and completion length), the hydrocarbon volume in-place as karst provide substantial secondary porosity; and well management and development strategy (wells nearer to karst are more likely to water-out quicker). This study incorporated an integration of well data, seismic characterization and geological understanding of the field and near-by analogues in building a subsurface model for field development. Geology The Central Luconia Province is located in offshore NW Borneo. The province is delineated by two major strike-slip faults, the West Baram in the northeast and the Rajang line in the southwest (Figure 1). Seafloor spreading in the South China Basin during the Oligocene to middle Miocene resulted in formation of a horst graben system that which controlled distribution of subsequent reefal carbonate growth. At mid-late Miocene reefs developed preferably on horst blocks (Mohammad Yamin Ali & Abolins[1]). Two major factors controlling carbonate sedimentation in the Central Luconia province are the regional tectonics and eustatic sea level changes. Tectonics played a role in creating horst and graben structures which served as basement for the onset of carbonate deposition and exerted an influence on the size and shape of the build-ups (Ting et al[2]). The latter also dictated the type of the depositional facies and their distribution which governed the reservoir properties of the carbonate platform.

Carbonate reservoirs often contain a complex mixture of pore sizes. In Bul Hanine field, Arab-DIII reservoir is almost entirely microporous throughout the field. Microporosity affects log responses and fluid flow properties. Proper identification and quantification of different porosity classes and their influence on the petrophysical parameters is crucial to accurately calculate hydrocarbon saturation. This paper presents the results of a multi-disciplinary workflow employed to identify and quantify the different porosity classes in the Arab-D reservoir.The workflow consists of core-and log-based analysis. The core-based analysis includes laser scanning confocal microscopy of thin sections from different reservoir facies, analysis of mercury injection data, and 3D pore network modeling. Confocal microscopy (0.25 micron resolution) quantified microporosity that cannot be seen or assessed through conventional petrography, while 3D pore network modeling helped evaluate the effect of the microporosity on the electrical parameters of the different reservoir facies. The log-based analysis includes analysis of Nuclear Magnetic Resonance logs (NMR) through spectral decomposition, interpretation of borehole images to evaluate the effects of diagenesis on the different reservoir facies, and other standard logs.Confocal microscopy demonstrated that pores smaller than 10 microns in diameter (micropores) in wackestone to packstone facies commonly comprise almost 100% of the total porosity. Burrowed, heterogeneous packstones and wackestones have 38 to 95% microporosity. Accurate quantification of microporosity from core using confocal microscopy permitted the computation of a continuous microporosity log using primarily NMR spectral decomposition and alternatively borehole images when NMR data is not available. After image to core calibration, rock fabric analysis using borehole images identified different bioturbation intensities with variable burrow sizes and varying burrow infill textures. Permeability enhancement can develop when burrowing architectures are well developed and filled with more permeable sediment, but diagenesis can also alter the porosity and permeability. The evaluation of electrical properties yielded insights into more effective rock property parameters, indicating that water saturation in these microporous networks may be lower than previously calculated. Pore network modeling showed that the microporosity fraction influences Archie's saturation exponent (ЉnЉ). By including a variable ЉnЉ value, weighted by the fraction of microporosity, water saturation computations can be reduced by 20%, therefore increasing volumetric and original oil in place.This workflow provides an innovative technique to characterize different porosity classes in heterogeneous carbonate reservoirs and quantify its impact on reservoir properties. It also provides a novel technique to calculate water saturation after correcting the effects of the microporosity presence in the different reservoir facies. This technique can be used...

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