Pore evolution modeling in natural lacustrine shale influenced by mineral composition: Implications for shale oil exploration and CO2 storage

The interaction between CO₂ and rock during the process of CO₂ capture and storage was investigated via reactions of CO₂, formation water, and synthetic sandstone cores in a stainless-steel reactor under high pressure and temperature. Numerical modelling was also undertaken, with results consistent with experimental outcomes. Both methods indicate that carbonates such as calcite and dolomite readily dissolve, whereas silicates such as quartz, K-feldspar, and albite do not. Core porosity did not change significantly after CO₂ injection. No new minerals associated with CO₂ injection were observed experimentally, although some quartz and kaolinite precipitated in the numerical modelling. Mineral dissolution is the dominant reaction at the beginning of CO₂ injection. Results of experiments have verified the numerical outcomes, with experimentally derived kinetic parameters making the numerical modelling more reliable. The combination of experimental simulations and numerical modelling provides new insights into CO₂ dissolution mechanisms in high-pressure/temperature reservoirs and improves understanding of geochemical reactions in CO₂-brine-rock systems, with particular relevance to CO₂ entry of the reservoir.

As an important part of carbon dioxide capture, utilization and storage (CCUS), the progress of injecting CO₂ into oil reservoirs could increase the recovery rate and achieve large-scale carbon storage. It has become one of the most important carbon storage methods around the world. This paper selected the tight sandstone of the fourth member of the Quantou Formation in the southern Songliao Basin to carry out a CO₂ storage physical simulation experiment. Representative samples were collected at 24 h, 72 h, 192 h and 432 h to study the CO₂ water-rock interaction and to analyze the mineral composition, pore structure and the evolutionary characteristics of physical reservoir properties over time. Physical property analysis, Ion analysis, X-ray diffraction mineral analysis, QEMSCAN mineral analysis, scanning electron microscopy and high-resolution CT scanning techniques were adopted. The main points of understanding were: (i) It shows a differential evolution of different minerals following the storage time of CO₂, and carbonate minerals are mainly dissolved with ankerite as a typical representation; a small amount of calcite is formed in 24 h, and dissolved in the later period; feldspar and quartz were partially dissolved; clay mineral precipitation blocked the pores and gaps; (ii) The evolution in mineral variation leads to the complexity of pore structure evolution, following a trend of “small pores decreasing and large pores increasing” with extending storage time. The final porosity and permeability ratios gradually increase from 4.07% to 21.31% and from 2.97% to 70.06% respectively; (iii) There is a negative correlation between the increasing ratio and the original physical properties of the tight stones due to the dissolution of ankerite. Relevant research could provide scientific guidance and technical support for the geological storage of CO₂ in lacustrine tight continental sandstones and the development of CCUS technology.

A capillary high-pressure optical cell (HPOC) combined with a confocal Raman system was used in this study of high-pressure methane/brine contact angles on a quartz surface. The contact angle was determined from the shape of the methane/brine/quartz interface; it increased with fluid pressure from 41° to 49° over a pressure range of 5.7–69.4 MPa. A linear relationship between the contact angle and the Raman shift was also observed. The experimentally measured contact angle was more accurately applied in calculations of capillary resistance than the empirically estimated 0°, and it provides an important parameter in the study of gas migration and production processes. For a natural gas reservoir, pore-throat capillary resistance was 33% lower than the traditionally accepted value, and low capillary resistance is conducive to deeply buried tight gas reservoirs becoming more gas saturated. As burial depth increases, capillary resistance initially decreases and passes through a maximum before decreasing again, rather than increasing linearly with depth. Our results provide critical parameters for gas reservoir production, modeling, and resource assessment. This non-destructive method may be useful for predicting contact angles through measurement of the Raman shift of the HPOC and fluid inclusions in the reservoir.

Various lines of evidence, including the occurrence of bitumen and fluid inclusions, show that oil charge once took place in the Kela-2 gas field, Kuqa foreland basin, Northwest China. However, the scale of the ancient oil reservoir remains unclear, as does the process by which the reservoir evolved into the present dry gas field. Here, using data from analyses of fluid inclusions, petrography, laser Raman spectroscopy, and quantitative fluorescence, the hydrocarbon accumulation history of the Kela-2 gas field is reconstructed. The results show that the gas field underwent three periods of hydrocarbon charging and one period of adjustment. The first oil charging occurred at about 12 Ma, as recorded by the first group of oil inclusions containing 0–8 vol.% gas with yellowish-brown fluorescence. The second charging involved mature oil charging at about 4 Ma, recorded by the second group of oil inclusions containing 15–25 vol.% gas with blue-white fluorescence. According to quantitative grain fluorescence (QGF) and rock pyrolysis analysis, an ancient oil reservoir existed with an oil-column height of about 350 m, and the paleo oil–water contact was lower than the present gas–water contact. Under intense thrusting from 3 Ma, the ancient oil reservoir was destroyed, with oil escaping through the Kashangtuokai thrust fault, which broke the salt layer, as this layer at that time lay in the brittle deformation domain. The inferred destruction of the ancient oil reservoir is supported by the numerous oil and gas shows at the surface and in shallow layers near the Kashangtuokai fault, as well as the anomalous development of authigenic kaolinite in the gas reservoir, which was enhanced by an open or semiopen system caused by the fault breaking through the salt layer. Subsequently, with increasing burial depth to more than 3000 m, the fault that had cut through the salt layer annealed because the salt layer then lay within the ductile deformation domain. The higher overpressure that occurred during the third gas charging at about 2 Ma reflected the annealing of the fault in the salt layer, favoring late gas accumulation and preservation. The evolution of the Kela-2 gas field provides an important case study for understanding the role of the salt layer crossing the brittle–plastic transition and the dynamic evolution of the salt caprock in salt-containing foreland basins.