Integrated Petrophysical and Petrographical Studies for Reservoir Characterization: A Case Study of the Khmer Basin in Cambodian Water, Gulf of Thailand

The Khmer Basin is one of the sedimentary basins in the Gulf of Thailand (GoT). This basin is located in the central east of the gulf, about 180 km from the Cambodian coastal baseline and an average of 80 m water depth in offshore Cambodia. It is an elongated N-S trending rift basin that extends 150 km in length and 60 km in width. Even though a high potential hydrocarbon accumulation reservoir was discovered in the late nineteenth century, the Apsara oil field in the northeast of the basin just started producing the first oil for Cambodia in late 2020 by KrisEnergy. However, there are a small number of publications about the Khmer Basin compared to the Pattani Basin to the west and the Malay Basin to the south. This study aims to identify the textures of the sedimentary grain, mineralogy, and diagenesis process of sandstone reservoirs which correspond to the quality of porosity and permeability in the confined layers from the Oligocene to Middle Miocene age. The core samples of the exploration well, Apsara-1 (1993), were provided by the General Department of Petroleum (GDP), Ministry of Mines and Energy (MME) for the purposes of academics. Thin section and SEM microscopic image analysis are applied to assist this petrographic study to observe the rock components and the relationship of grains and matrix, cementation and the diagenetic processes. X-ray diffractometer (XRD) is used to determine the mineral compositions and clay minerals. X-ray Fluorescence (XRF) is used to evaluate major oxide concentrations in reservoir intervals. The stratigraphy in a section, ranging from 2776 m to 2781 m consists of sandstones interbedding with shales and coals. Mudstones which are composed of silt shale and coal appear in dark-grey to black thin layers in the study section. The porosity of the sample determines the diverse pore spaces in the reservoir sand, ranging under 12%. The data analysis, the clastic, pore geometry, buried compaction, diageneses and fractures impact relatively on reservoir quality. The porosity reduction is directly influenced by mechanical compaction, quartz overgrowth, the pore fillings by detrital clays and mineral replacement.