Porosity evolution of high-quality reservoirs in deep Palaeogene lacustrine carbonate rocks in the central Bohai Sea. Issue 5 (September 2018) - Qing, Yuanhua; Lü, Zhengxiang; Wang, Xiandong; Song, Xiuzhang; Zhang, Shunli; Meng, Hailong
The oil and gas in the Palaeogene lacustrine carbonate rock reservoirs in the Bohai Sea accumulated during several periods. The reservoir porosity formed during each period affected the degree of accumulation that occurred. In this paper, the percentages of particles, authigenic minerals and pores in the reservoir bed were calculated with the statistical method of microstructure analysis. The formation time was determined with an isotopic analysis of the authigenic carbonate minerals and the homogenization temperature of the gas–liquid inclusions. The percentages of the primary intergranular pores that formed during the different stages were recovered based on the compaction features both before and after the formation of the major authigenic minerals. The evolution of porosity was thus described quantitatively and chronologically, employing the percentages of the residual primary intergranular pores, visceral cavity pores and dissolved pores at the different burial depths. The results indicate that in the initial sediments of the reservoir rock, the primary intergranular porosity was 32.4%. During the early burial stage, the total reservoir porosity increased by up to 46.9%, due to the addition of another type of primary pore, namely visceral cavity pores, which were generated from the decomposition of bioclasts. During the late, deep burial stage, the compaction reduced only 8.2% of the porosity, due to the support of the pore-lining dolomite precipitating during the early stage. Authigenic minerals occupied 12.6% of the porosity, and the dissolution created the secondary porosity by 3.8%. Good preservation of the visceral cavity pores and the growth of the pore-lining dolomites during the early stages are the major factors leading to the high reservoir porosity. The quantitative and chronological characteristics of the reservoir porosity evolution could be described accurately. The prediction of reservoir beds can be better guided than in previously reported methods by applying high resolution microscopic quantitative analysis technology and authigenic mineral timing analysis technology.