--> Unconventional Shale Reservoir Characterization Through Integration Between Geophysics And Geomechanics – A Case Study In The Chumsaeng Formation, Phitsanulok Basin

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Unconventional Shale Reservoir Characterization Through Integration Between Geophysics And Geomechanics – A Case Study In The Chumsaeng Formation, Phitsanulok Basin


The Phitsanulok basin is the largest onshore basin in Thailand. Located within the basin is the biggest oil field in Thailand, the Sirikit field. As the conventional oil production has surpassed the plateau, unconventional play has emerged as a promising alternative to prolong the production and add up the resource. Source rock in the basin is the Oligocene lacustrine claystone or the Chum Saeng formation (CS). The formation is mostly matured and widely extend throughout the basin. Recent study by USGS suggests that the Chum Saeng formation has a potential to be a new unconventional shale gas/oil reservoir with an estimated undiscovered resource of about 50 MMbbl of oil and 310 bcf of gas. This study aims to quantify and characterize shale gas/oil reservoir potential in the Chum Saeng formation using rock physics analysis, seismic inversion, and reservoir characterization techniques. The study started with rock physics analysis to determine the relationship between geophysical, lithological, and geomechanical properties of rocks, with an objective of transforming geophysical information into key shale gas/oil resource properties. Total Organic Carbon (TOC) values from rock sample analysis were compared to resistivity, sonic log (Delta-logR) and acoustic impedance (AI) log data to verify whether a relationship between AI and TOC could be determined. Results of geomechanical tests on core samples were used to calibrate calculated dynamic elastic moduli to static elastic moduli. Simultaneous seismic inversion was later performed using three seismic angle stacks as input. The seismic inversion results provided spatial variation of geophysical properties, i.e. P-impedance, S-impedance, and density. With results from rock physics analysis and from seismic inversion, the reservoir was characterized by applying analyses from wells to the inverted seismic data. A 3D lithofacies cube was generated based on the relationship between Vp/Vs and AI using the Bayesian classification method. TOC was calculated from inverted P-impedance. Elastic moduli, e.g. Young’s modulus and Poisson’s ratio, were calculated from inverted impedances. A seismic derived brittleness cube was later calculated from Poisson’s ratio and Young’s modulus cubes. Finally, all the derived properties were interpreted and analyzed. The final result from reservoir characterization provided a spatial variation in rock facies and shale reservoir properties, including TOC, rock proximate brittleness or fracability, and elastic moduli. From the analysis, the most suitable location for shale gas/oil pilot exploration and development was identified. The southern area of the survey, with an approximate depth of 650-850 m, showed the best potential for shale to be an unconventional reservoir in this area. The shale formation is thick, with intermediate brittleness and high TOC. The structure within the area is not complex, and considering the promising properties make it a potential sweet spot for future exploration of this shale reservoir. This study has demonstrated how seismic data can be implemented to characterize an unconventional reservoir, both with respect to lithology and geomechanical properties. The study also shows a practical shale reservoir analysis methodology that can be applied during exploration or initial stages of development. However, there are still unknown factors that has not been accounted for in this work, and additional geochemical and basin modeling studies are required to support these results, especially related to the maturation and depositional setting of this unconventional resource.