Jiguang Tang’s research while affiliated with Yangtze University and other places

The in-situ stress and formation pressure are important parameters in shale gas development. They directly affect the well wall stability, the direction of horizontal well drilling, and the fracturing effect during the shale gas development process. There are abundant shale gas resources in the southeastern Chongqing-Sichuan area, but the structure in the area is complex, and it is difficult to predict the in-situ stress and formation pressure. Therefore, in this paper, a finite element simulation model was established based on a large number of seismic, logging, and experimental rock mechanics data and the prediction accuracy of the stress field simulation was effectively improved. The construction of the stress field was based on the combined spring model, as well as the data related to the measured in-situ stress and the formation pressure obtained during drilling. The coupling relationship between the in-situ stress, the formation strain, and the formation pressure were derived to carry out the prediction of the distributions of the formation pressure and the formation pressure coefficient. The prediction results showed that the present-day maximum principal stress direction in the study area was about NE65°–110°, and the present-day maximum principal stress was 56.12–93.79 MPa. The present-day minimum principal stress direction was about NE335°–20°, and the present-day minimum principal stress was 48.06–71.67 MPa. The formation pressure was 2.8–88.25 MPa, and the formation pressure coefficient was 0.74–1.55. The formation pressure distribution was greatly affected by fault, tectonic location, in-situ stress and rock petrophysical properties, and the overpressure areas of the formation were distributed in the synclines and the deeply buried areas. This study shows that the finite element based formation pressure prediction method is effective.

Shale is a low-porosity and low-permeability reservoir, and structural fractures are the main controlling factor for the migration and accumulation of shale gas. Moreover, tectonic fractures are controlled by the paleo-tectonic stress field. In this paper, taking the Longmaxi Formation of the Lintanchang area as an example, the finite element numerical simulation technology is used to analyze the distribution law of the paleo-tectonic stress field, and further, the fracture development areas under the superposition of two periods of tectonic stress are predicted using seismic, rock mechanics, and field data. The results show that the tectonic fractures developed in the Lintanchang area are mainly EW- and NNW-striking conjugate shear fractures formed in the Mid-Yanshanian period, followed by the NWW- and SWW-striking conjugate shear fractures formed in the late Yanshanian period. The distribution of tectonic fractures is affected by faults, folds, rock physical parameters and tectonic stresses. It is found that the comprehensive fracture coefficients of the anticline core and fault areas are both greater than 1.1, which are the areas with the most developed structural fractures, and these areas have poor shale gas preservation conditions. However, the comprehensive fracture coefficients of the western flanks of the anticline and the eastern and western dipping ends are between 1.0 and 1.1, which are areas with better shale gas preservation conditions. In addition, the development degree of tectonic fractures in the east and northwest areas of the Lintanchang anticline is lower than that in other areas. The comprehensive fracture coefficients of shale in these areas are between 0.9 and 1.0. The shale is in a state of “breaking without cracking”, and shale gas can be well preserved.

The main types of diagenesis, diagenetic minerals and their formation time sequence in the Ordovician ultradeep (>7000 m total depth) carbonate reservoir represented by the Yingshan and Penglaiba Formations (well Tashen-6, Tahe Oilfied, Tarim Basin), are determined by applying microscopic observations, microscopic fluorescence detection, and cathodic luminescence analysis in petrographic thin sections. The distinct periods of reservoir diagenesis and hydrocarbon-related events are determined by analyzing the development characteristics of hydrocarbon inclusions and their relationship with the host minerals. The charging periods of hydrocarbon inclusions are identified by constraining the homogenization temperatures of inclusions. The obtained results indicate that the Ordovician Yingshan and Penglaiba formations have experienced at least three periods of hydrocarbon charging and one period of structural transformation. Their relative time sequence relationship with diagenesis processes is as follows: The limestone dissolution of the Yingshan Formation developed initially, and the first period of hydrocarbon charging occurred (during the late Caledonian). The second period of hydrocarbon charging occurred due to the continuous modification influence of dissolution (late Hercynian-early Yanshanian). The limestones of the Penglaiba Formation were exposed to strong tectonism during the second period of hydrocarbon charging in the Yingshan Formation; thus, intralayer microfractures were formed. Additionally, the first period of hydrocarbon charging in the Penglaiba Formation occurred together with the dolomite reservoir (late Hercynian-early Yanshanian). During the subsequent period, dissolution occurred again due to the continuous increase in burial depth. The third period of hydrocarbon charging developed concurrently with the early fractures (late Himalayan). Finally, the unceasing deepening of the strata accompanied by tectonic activity led to the early intergranular dissolution pores to be cut by late microfractures, which caused the crude oil to convert into bitumen through secondary modifications.

The Upper Cretaceous Qingshankou (K2n) and Nenjiang (K2q) shale oil from the Changling Sag (CLS) of the Southern Songliao Basin located in NE China was studied to determine shale reservoir properties and evaluate oil potential. Multiple methods, including optical microscope, scanning electron microscope and energy dispersive spectrum analysis (SEM-EDS), nitrogen adsorption/desorption analysis, and X-ray diffraction, were conducted to determine the shale reservoirs. The mineral analyses present in this shale consist of blende, albite, chlorite, pyrite, and calcite, whose textures are crystals, schistose, particle, or clusters. The mineral results show a significant percentage of brittle minerals (40.5–61.7%), and clay minerals are dominated by illite and montmorillonite. The mineralogical brittleness indexes of the Upper Cretaceous K2n and K2q shales are 0.15–0.67 and 0.18–0.42, respectively. The K2q shale has a relatively low brittle mineral content, which may not be favorable for shale oil seepage. Higher brittleness in K2n shales is more favorable for hydraulic fracturing with larger width and smaller initial stress. Although the reservoir has an ultra-low permeability, they have a relatively good porosity. The organic matter is residual in bioclastic pyritization, calcareous bioclastic grain pores, animal skeletal grain, and algous cystocarp. Moreover, the K2n and K2q shales contain a substantial number of pores, micro-fractures, and oil. The mineral intragranular pores, dissolution pores, organic pores, and micro-fractures are significantly developed. Hysteresis loop is acquired in open pores, which have mainly inkbottle-shaped pores and few parallel-plate pores or cylindrical pores. Our findings may fill significant gaps in understanding and predicting pore systems and mineralogical brittleness indexes, with respect to the lacustrine shale oil in China.

Organic rich Wufeng-Longmaxi shales (WLS) occur widely in the Upper Ordovician–Lower Silurian strata in southeastern Sichuan Basin, SW China. However, complex structural deformation and faulting activity in this area since the Mesozoic time has had significant impact on shale gas preservation. Thus, difference in the structural deformation strength is an important constraint for differential shale enrichment in a shale reservoir. Fracture analysis and bedding surface normal stress data obtained from the outcrop, core and fluid inclusion samples were used to determine the vertical and lateral constraints on shale gas preservation conditions. Using the finite element method, 2D mechanical models were established in the Songkan area, based on seismic inversion, rock mechanics and acoustic emission tests. Paleotectonic stress fields were estimated for the Middle Yanshanian (K1¹/K1²), Late Yanshanian (K2²/K2³) and Himalayan （E-N）times. Fracture type distribution was determined from the rock failure criterion, and the shale bedding surface normal stress calculated by dip angle and burial depth. The results indicate that optimal conditions for shale gas preservation occur where the maximum principal stress values reach the fracture development stage (around 63.96–73.8 MPa). When the value increases to over 65 MPa, shale bedding surface closure favors the shale gas preservation. Based the vertical and lateral constraints, the best preservation area occurs where fracture development coincides with the shale bedding closure.

One of the biggest challenges in evaluating the transport and storage properties of shales is understanding how the pore structure and network evolve in the same stratigraphic shale during catagenesis. Using a combination of CO2 adsorption, mercury intrusion porosimetry, as well as scanning electron microscopy, we have described the evolution and the abrupt changes (jump) of pore characteristics in lacustrine shale at oil and gas maturation. With an increase maturity, our sample set exhibited abrupt changes in porosity-related characteristics. Porosity and surface areas presented a decline and then an increase, and a jump occurred due to hydrocarbon generation, with the minimum value in late maturity (i.e. vitrinite reflectance of ~1.3%). These changes were accompanied by corresponding changes in pore-size distributions, surface area percentage, and multi-scale pores volumes. The trends in porosity variation were related to different organic matter and mineral contents in our samples, to some extent, with the degree of maturation being the dominant influence. We found that inorganic pores were the main contributor to the porosity of less mature shales, while porosity in gas-mature shales was dominated by organic matter pores. In this work, we showed that organic matter transformation was a centric component of pore evolution. Our findings may fill significant gaps in understanding and predicting pore development, with respect to the maturity of lacustrine shales.