Tight Sandstone Reservoir Formation Mechanism of Upper Paleozoic Buried Hills in the Huanghua Depression, Bohai Bay Basin, Eastern China

Carboniferous-Permian petroleum resources in the Huanghua Depression of the Bohai Bay Basin, a super petroleum basin, are important exploration successor targets. The reservoir sedimentary environment of coal measures in the Upper Paleozoic buried hills is variable, and the structural evolution process is complicated, which restricts the optimization of targeting sections. Using the analysis and testing results of logging, thin section, porosity, mercury injection, hydrochemistry, and basin simulation, this study revealed the formation mechanism differences of tight sandstones in the Upper Paleozoic period in different buried hills. The results show that the sandstones are mainly feldspathic sandstone, lithic arkose, feldspathic lithic sandstone, and feldspathic lithic quartz sandstone. The quartz content varies between 25% and 70%, averaging 41%. Feldspar and debris are generally high, averaging 31% and 28%, respectively. Secondary dissolution pores are the main reservoir spaces, with 45% of the tested samples showing porosity of 5–10%, and 15% being lower than 5%. The pore radium is generally lower than 100 nm, and the sandstones are determined as small pore with fine throat and medium pore with fine throat sandstones by mercury saturation results. Frequent changing sedimentary environments and complex diagenetic transformation processes both contribute to the reservoir property differences. The former determines the original pore space, and the latter determines whether they can be used as effective reservoirs by controlling the diagenetic sequences. Combining tectonic movement background and different fluid history, the different formation mechanisms of high-porosity reservoirs are recognized, which are atmospheric leaching dominated (Koucun buried hills), atmospheric water and organic acid co-controlled (Wangguantun and Wumaying buried hills), and organic acid dominated (Nandagang buried hills) influences. The results can be beneficial for tight gas exploration and development in coal measures inside clastic buried hills in the Bohai Bay Basin.

The influences of sedimentary environments on organic matter enrichment in fine-grained rocks of the Paleogene Shahejie formation in Nanpu Sag, Huanghua Depression, Bohai Bay Basin

The fine-grained rocks in the Paleogene Shahejie Formation in Nanpu Sag, Huanghua Depression, Bohai Bay Basin, are extremely important source rocks. These Paleogene rocks are mainly subdivided into organic-rich black shale and gray mudstone. The average total organic carbon contents of the shale and mudstone are 11.5 wt.% and 8.4 wt.%, respectively. The average hydrocarbon (HC)-generating potentials (which is equal to the sum of free hydrocarbons (S1) and potential hydrocarbons (S2)) of the shale and mudstone are 39.3 mg HC/g rock and 28.5 mg HC/g rock, respectively, with mean vitrinite reflectance values of 0.82% and 0.81%, respectively. The higher abundance of organic matter in the shale than in the mudstone is due mainly to paleoenvironmental differences. The chemical index of alteration values and Na/Al ratios reveal a warm and humid climate during shale deposition and a cold and dry climate during mudstone deposition. The biologically derived Ba and Ba/Al ratios indicate high productivity in both the shale and mudstone, with relatively low productivity in the shale. The shale formed in fresh to brackish water, whereas the mudstone was deposited in fresh water, with the former having a higher salinity. Compared with the shale, the mudstone underwent higher detrital input, exhibiting higher Si/Al and Ti/Al ratios. Shale deposition was more dysoxic than mudstone deposition. The organic matter enrichment of the shale sediments was controlled mainly by reducing conditions followed by moderate-to-high productivity, which was promoted by a warm and humid climate and salinity stratification. The organic matter enrichment of the mudstone was less than that of the shale and was controlled by relatively oxic conditions.

Structures and Kinematics of the Huanghua Depression in Bohai Bay Basin, East China: Implications for the Formation Mechanism of a Transtensional Basin

The Bohai Bay Basin in East Asia is a rift basin created by Cenozoic subduction of the oceanic Pacific plate beneath the Asia continent. Many prior studies suggest that the basin was initially formed in the Paleocene with the development of several NNE-trending extensional grabens, but subsequently impacted by right-lateral shear along these existing NNE-trending structures in the middle Eocene, transforming the Bohai Bay Basin into a transtensional basin and producing EW-trending grabens in the Bozhong and the northeastern Huanghua depressions. However, how this transformation occurred remains to be fully understood. Based on seismic and drilling data, we herein investigated the fault structures, basin architecture, and evolutionary stages of the Huanghua Depression in the central-west Bohai Bay Basin to examine the strain partitioning and evolution mechanism during the Paleogene syn-rifting stage. The results reveal that the Huanghua Depression is composed of three structurally distinctive zones, namely, a dextral transtensional, a NW-SE extensional, and a N-S extensional zones from southwest to northeast, which are separated from each other by two transfer zones. The NW-SE extensional zone is interpreted as a horsetail structure on the northern termination of the dextral transtensional zone. This dextral transtensional zone and the Tan-Lu Fault zone to the east served as strike-slip boundaries within which EW-trending depressions such as the northeastern Huanghua and Bozhong depressions formed in the middle Eocene.

Hydrocarbon generation from Carboniferous-Permian coaly source rocks in the Huanghua depression under different geological processes

Natural gas and condensate derived from Carboniferous-Permian (C-P) coaly source rocks discovered in the Dagang Oilfield in the Bohai Bay Basin (east China) have important implications for the potential exploration of C-P coaly source rocks. This study analyzed the secondary, tertiary, and dynamic characteristics of hydrocarbon generation in order to predict the hydrocarbon potentials of different exploration areas in the Dagang Oilfield. The results indicated that C-P oil and gas were generated from coaly source rocks by secondary or tertiary hydrocarbon generation and characterized by notably different hydrocarbon products and generation dynamics. Secondary hydrocarbon generation was completed when the maturity reached vitrinite reflectance (Ro) of 0.7%–0.9% before uplift prior to the Eocene. Tertiary hydrocarbon generation from the source rocks was limited in deep buried sags in the Oligocene, where the products consisted of light oil and gas. The activation energies for secondary and tertiary hydrocarbon generation were 260–280 kJ/mol and 300–330 kJ/mol, respectively, indicating that each instance of hydrocarbon generation required higher temperature or deeper burial than the previous instance. Locations with secondary or tertiary hydrocarbon generation from C-P coaly source rocks were interpreted as potential oil and gas exploration regions.