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Bohai Bay Basin is an important petroliferous basin in China. Petroleum potential in Liaodongwan Depression of offshore Bohai Bay Basin has been proved by previous exploration and production, and overpressures were encountered. Summarized by the DST measurements and mud weight data of over 60 wells in Liaodongwan Depression, the abnormally high pressures preserved in Paleocene Dongying (Ed) Formation distribute over the entire depression and could reach as high as 64.2 MPa around the depth of 3420 m. Through the well logs analysis, typical corresponding characteristics to disequilibrium compaction can be found: higher in acoustic transit time and lower in density than normal compaction trend. Based on these corresponding features the pore pressure prediction was carried out for all the wells in the area. Sonic velocity-effective stress relationship and sonic velocity-density cross plots were employed to investigate the origin of overpressure in Ed Formation. Sedimentation rates and geothermal features were studied as well. Combining all the analysis, the overpressure of Ed Formation in northwest Liaodongwan Depression was dominantly generated by disequilibrium compaction. With this widely distributed overpressure, thick layers of mudstone of Ed Formation serve as a regional overpressured caprock. [ABSTRACT FROM AUTHOR]

The Permian shale reservoir in the Lower Yangtze area of South China is regarded as a target with a high potential for shale gas exploration. To investigate the pore structure characteristics and evaluate reservoir quality, 32 shale samples from the Upper Permian Longtan Formation and Dalong Formation in the Lower Yangtze area were studied using a suite of techniques including total organic carbon (TOC) content, X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), nitrogen (N 2) and carbon dioxide (CO 2) gas physisorption, mercury injection capillary pressure (MICP), petrographic observations, and fluid inclusion analysis. Petrographic observations reveal that the Longtan Formation is rich in vitrinite and inertinite, while the Dalong Formation contains a large amount of solid bitumen. Primary organic pores (POPs) are the original cellular pores that develop in inertinite. Vitrinite particles did not show visible pores. Solid bitumen infills fractures and occupies the interparticle (interp) space between the mineral grains in the Dalong Formation. A small number of speckled secondary organic pores (SOPs) were observed in the solid bitumen with diameters less than 10 nm. Both the TOC and quartz contents exhibit negative relationships with the pore volumes (PVs) for the Longtan and Dalong Formations, owing to the poor development of pores in the organic matter (OM) and occlusion of most mineral pores by migrated bitumen. There is a positive relationship between clay minerals and PVs owing to the sheet-like meso-pores and macro-pores in the clay minerals. The evolution of organic porosity is related to the differences in maceral composition and thermal maturity. Thermal cracking of residual oil and bitumen and the expulsion of gaseous hydrocarbons contributed to the formation of SOPs in marine shales. In contrast, vitrinite and inertinite in gas-prone shales do not display noticeable morphological changes across the entire thermal evolution process, owing to their low hydrocarbon generation potential. • The Longtan and Dalong Formations are comparatively analyzed for pore structure characteristics. • The Longtan Formation is rich in vitrinite and inertinite, while the Dalong Formation is dominated by solid bitumen. • Solid bitumen has a negative effect on the pore system owing to infilling pore space. • Type III kerogen has a relatively minor contribution to the pore system. • A pore evolution model is proposed for oil- and gas-prone shales. [ABSTRACT FROM AUTHOR]

This study evaluates the pore network systems in the Neoproterozoic Sinian Doushantuo (Z 1 d) shale from the Yichang area in the Middle Yangtze region. All samples were classified based on their lithologies and examined by geochemical and petrographic analysis, assisted with carbon dioxide/nitrogen (CO 2 /N 2) adsorption, mercury injection capillary pressure (MICP) and focused ion beam-scanning electron microscopy (FIB-SEM) to fully characterize the nanoscale porosity of the different shale lithofacies. The calcareous shale lithofacies group (I-C), mixed shale lithofacies group (II-M) and siliceous shale lithofacies group (III-S) were identified via ternary mineralogy diagrams. Clearly, different lithofacies had different porosities, pore volume, surface area and pore-size distribution (ranging from 0.3 nm to 36 μm). The mixed shale lithofacies group (II-M) had the highest total pore volumes, followed by the calcareous shale lithofacies group (I-C) and the siliceous shale lithofacies group (III-S). Peak values (2–20 nm, 20–50 nm, 50–60 nm and 90–200 nm) obtained from N 2 adsorption were identified as organic matter (OM) pores, dissolution intraparticle (intraP) pores and intercrystalline pores (using SEM images analysis). Porosity shows a non-monotonic trend with TOC content and a maximum at 4.5–5.5 wt% TOC, similar relationships between TOC and mesopore/macropore volumes, due to pore collapse and compaction. The FIB-SEM images revealed solid bitumen and two types of kerogen in the examined shale samples; these different organic matter types had clearly distinct pore characteristics. While the smaller OM particles mobilized and converted into solid bitumen in which OM pores were larger and more abundant, the large-scale OM particles were most likely non-porous inert maceral and sponge-like porous amorphous kerogen. Overall TOC content and organic types are the key controlling factors to the nanoscale porosity development in the Doushantuo Shale, and the Sinian Doushantuo shale (in the Yichang area) has great potential for shale gas exploration and exploitation in South China. • Sinian Doushantuo Shale reservoir was analyzed for lithofacies classification and porosity characteristics. • Multiple methods (CO 2 and N 2 sorption, FIB-SEM and MICP) indicate the existence of μm-nm pore size spectrum. • TOC content, mineral support and organic types are ascribed as crucial parameters to reveal porosity development of shales. • Doushantuo Shale in Yichang area is a brand new shale gas formation and base in South China. [ABSTRACT FROM AUTHOR]

Bohai Bay Basin is a Meso-Cenozoic terrestrial sedimentary basin in eastern China. Its offshore regions, including Bozhong and Liaodongwan Depressions, are favourable exploration targets which provide near a half of the petroleum reserves in the basin. Eocene Shahejie (Es) Formation and Oligocene Dongying (Ed) Formations are two important exploration targets in Bozhong Depression, and overpressure is commonly seen in Es and Ed Formations in this area. Our research examined the distribution characteristics of overpressure in the formations and suggest the main mechanism of overpressure is compaction disequilibrium due to the rapid sedimentation rates (~500 m/Ma) of fine-grained sediments in this area. Also, oil and gas generation within the thick mudstones of the two formations has added the magnitude of overpressure. We investigated the reservoir quality especially primary porosity in Es and Ed formations, and their relationship with overpressure. The positive effect of overpressure on reservoir porosity preservation was validated through microscopic observations and vertical effective stress (VES) analysis. We established a quantitative model for evaluating the relationship of overpressure, pore structures, porosity, and VES. The result suggests the overpressure in the targeted formations were primarily originated from undercompaction. The overpressure kept VES from increasing and helped preserve the primary intergranular porosity. The porosity preserved by overpressure can be significantly higher than normally compacted porosity under the same condition of depth and temperature. • Abnormally high porosity in deep reservoir. • Microscopic porosity information. • Porosity preservation through relatively lower vertical effective stress. [ABSTRACT FROM AUTHOR]

The North Fuling area is located in the Eastern Sichuan Basin, China. Natural gas and condensates are commonly found in the Jurassic shales (including Lianggaoshan, Da'anzhai, and Dongyuemiao shales) in this area. Multiple geochemical approaches and tests including methane concentration, C 2+ concentration, and stable isotopes were employed to determine the geochemical characteristics and the origin of the gas samples from the Jurassic shales. The analyses reveal that: (1) natural gas in the Jurassic shales is predominantly wet gas with the methane concentration of 36.89% ∼ 94.27%; (2) δ 13 C values range between −49.4 ∼ −44.2‰/VPDB in methane, −33.0 ∼ −30.0‰/VPDB in ethane, and −28.7 ∼ −26.5‰/VPDB in propane; the crossplot of isotope data indicates the gas samples are oil-associated gas which probably originated from the cracking of crude oil; (3) thermal maturity in terms of vitrinite reflectance equivalence of the gas samples ranges from 0.8% to 1.2%; and (4) gas-source correlation suggests the gas in Jurassic shales is generated from Da'anzhai shale, of which organic matter is primarily Type II and R o ranges from 1.06% to 1.28%. [ABSTRACT FROM AUTHOR]

Natural gas resources in marine carbonate rocks comprise the most significant remaining oil and gas resources in China. Preservation conditions assessment and destruction mechanisms of high-quality carbonate reservoirs play an important role in petroleum resource evaluation in carbonate reservoirs. In the Silurian Shiniulan carbonate gas reservoirs of southeast Sichuan Basin, mineral sequences in fracture-cavity veins, calcite-precipitating fluid sources, and paleo-pressure evolution histories were investigated by Raman quantitative analysis, element characteristics and isotope compositions. The process of reservoir decompression indicated by inclusion analysis and the enrichment of trace elements are all due to the response of reservoir reconstruction. Petrographic observations show two stages of calcite vein occur commonly in fracture-cavity. Stage-1 calcite veins mineralized in a reduction environment as results of hydrothermal activity. Gas accumulation was accompanied by the crystallization and precipitation of the stage-1 calcite veins. Stage-2 calcite vein precipitated during Himalayan tectonics and derived from intensive invaded penetrating fluid, which might be affected by atmospheric freshwater. The density, pressure, and temperature for CH 4 -bearing fluid inclusions in the stage-1 calcite veins filling was determined by quantitative Raman spectroscopy. Thermodynamic simulations were conducted to constrain pore pressure evolution histories with the establishment of trapping condition of the geo-fluids. Our results suggest that gas generation and charging comprise the main mechanisms for paleo-overpressure development. Identification of fluid sources and understanding pore pressure evolution are keys to study the oil and gas migration and accumulation. • Diagenetic sequence in Silurian under destructive preserved condition. • Fluid genesis-discriminating the paleogenic environment of calcite vein. • Raman quantitative analysis determines paleo-pressure evolution. • Fluid geochemical properties indicate the gas reservoir-forming mechanism. [ABSTRACT FROM AUTHOR]

The prediction of pore pressure in subsurface formations is important for the estimation of hydrocarbon accumulation and for safe drilling activities. Typically, pore pressure is estimated from either well logs (e.g., P-wave velocity, resistivity) or seismic data (seismic velocities, acoustic impedance) using empirical relations based on compaction laws. Due to the high density and extremely heterogeneous physical properties, it's not feasible to calculated pore pressure in carbonate rocks with these empirical methods. The result of ultrasonic velocity measurements in carbonate rocks shows that velocity is affected by multiple factors, e.g., stress condition, porosity, rock composition, fluid composition, and other rock properties. It's practicable to predict pore pressure with velocity when other factors are kept constant or evaluated quantitatively. In this paper, a quantitative model to compute the elastic attributes as a function of pressure and petrophysical properties is proposed. The model as a rock physical model is based on the poroelasticity theory and describes the effect on the elastic property of stress conditions. The model is validated using laboratory measurements. A case study for this model application from the northeastern Sichuan Basin, including a set of well logs and borehole measurements is also presented. The pore pressure gradient in carbonate reservoirs is ranging from 0.99 to 2.13 MPa/100 m. The predicted result shows the relative error between model predictions and observations measured while drilling is from 0.60% to 10.22%. The method proposed in this study is effective for pore pressure prediction in carbonate formation. • Pore pressure in carbonate rocks is estimated by a new rock physical model. • The model is validated by laboratory measurements and tested using well-logging data. • The model can be considered as a new tool to predict overpressure in carbonate rocks. [ABSTRACT FROM AUTHOR]

Water is ubiquitously present within organic-rich shale and can exert an important effect on the gas-in-place and gas adsorption capacity of shale reservoirs. Thus, understanding the water adsorption characteristics of gas shale reservoir is critical for optimizing shale-gas productivity. In this work, the water vapor adsorption characteristics of organic-rich Wufeng and Longmaxi Shales in the Sichuan Basin were studied over a wide range of relative humidities (RHs, 5–95%) utilizing a gravimetric method. All the water vapor adsorption isotherms are categorized as type II, suggesting similar water adsorption behaviors between samples. Being pronounced at approximately 70–80% RH, hysteresis loops from water adsorption curves are characterized by calculating areal hysteresis index (AHI) values. The Wufeng Shales have higher AHI values than those of Longmaxi Shales, which are mainly related to the variation of TOC content and pore structure characteristics. Pore size distribution obtained from water vapor adsorption show unimodal distribution of pore sizes, which are generally comparable to that derived from nitrogen physisorption. The mineral content (e.g., quartz and clay contents) and pore structure characteristics (e.g., pore type, porosity and surface area) have great effects on the water vapor uptake in the Wufeng and Longmaxi Shales. Compared to the shales with low surface area and porosity, Wufeng and Longmaxi Shale samples with higher surface area and porosity exhibit much higher water vapor uptake, suggesting that moisture sorption is mainly controlled by the amount of adsorption sites and volumes. When RH increases from low to high values, methane capacity of partially moisture-equilibrated shale could have experienced rapid decline, moderate decrease and slow decrease stages, finally reaching the minimum adsorption capacity for full moisture-equilibrated shale. • Water vapor adsorption characteristics of overmature Wufeng and Longmaxi Shales are investigated. • The hysteresis loop obtained from water adsorption test is quantitatively characterized using the areal hysteresis index method. • The formation mechanisms for hysteresis loops are discussed, which provides insight into the various methane adsorption capacity of partially moisture-equilibrated shale. • Pore structure analyses via water vapor adsorption are performed and compared to those via nitrogen physisorption. • The water vapor adsorption capacity is collectively affected by the TOC content, mineral composition and pore structure. [ABSTRACT FROM AUTHOR]

Factors influencing the methane adsorption capacity (MAC) of marine-continental transitional facies shales have been identified applying a variety of techniques (e.g., total organic carbon (TOC) content, X-ray diffraction mineralogy, low-pressure CO 2 and N 2 adsorption, and methane adsorption analyses) on samples from the Upper Permian Longtan Formation, northern Guizhou Province, Southwest China. The TOC contents of the Longtan shale samples ranged between 1.2 and 9.9 wt% (average = 3.5 wt%). The results of the bulk XRD analysis suggested that the mineralogical composition of the studied samples was different from that of typical marine shales: the samples primarily consisted of clay minerals, followed by quartz and feldspar. The Langmuir volumes (V L) of the 14 shale samples ranged from 1.02 ml/g to 5.25 ml/g (average = 2.52 ml/g); moreover, their MAC was positively correlated with the pore volume, surface area, and TOC content, suggesting that organic matter and pore structure were the most critical factors influencing the adsorption capacity of these transitional shales. Our results showed that the MAC was not positively with the clay content; additionally, the MAC tended to increase with increasing pressure, but to decrease with increasing temperature. The presence of moisture greatly reduced the MAC. Overall, the MAC of the transitional Longtan Formation shales resulted to be quite different from that of typical marine shales (e.g., the Lower Silurian Longmaxi Formation in the Sichuan Basin) in terms of mineralogical component and abundance of organic pores. The particularly high abundance of (hydrophilic) clay minerals in the Longtan Formation transitional shales resulted in a higher number of adsorption sites occupied by water molecules than in the Longmaxi Formation and a lower MAC. Finally, the abundance of organic pores in marine shales resulted in a higher MAC than that of transitional shales. • TOC content dominantly influence methane adsorption capacity in transitional Longtan shale. • Moisture greatly reduces the methane adsorption capacity in transitional Longtan shale. • Adsorption capacity of Longtan shale is lower than that of typical marine Longmaxi shale. [ABSTRACT FROM AUTHOR]

Massive micro fractures (MFs) developed in the ultra-tight formations (such as shale/tight reservoirs), which provide preferential channels for the fluids flow. Accurate characterization of such pore-fracture systems and suitable pore network models are the fundamentals of pore structure characterization and micro scale flow simulation. Conventional medial axis (MA) skeleton extraction method cannot preserve the fracture surface feature and connectivity information, which is not suitable for accurate pore scale simulation for these porous media with MFs. In this paper, a new skeleton model was proposed to distinguish MFs from pore space via extraction of surface points set of MFs. In the procedure of points set extraction, we improved the classic “MA based” shrink method to “medial surface (MS) based” method for the MFs characterization through introducing a new set of skeleton points (i.e., surface points and edge points of the micro fractures). The former describes their apertures and the latter is used for collecting connectivity information and determining the extension ranges of the MFs. Comparison of connectivity index, fracture length, Euclidean distance showed enhanced effectiveness and accuracy of the proposed method. The proposed method was applied in four ideal models and one field shale core sample. Results show that the proposed skeleton model can show more comprehensible forms of the real connected junction instead of the conventional ideal model. The extracted skeleton can also satisfy demands of the traditional skeleton extraction model and preserve the topology of the original pore-fracture space. This work proposed a more accurate method for pore-scale modeling in cores with natural MFs, and potentially applicable for pore scale flow simulations for tight/shale reservoirs. [ABSTRACT FROM AUTHOR]