• Energy Research

Hydraulic fracturing is a widely used technique for oil and gas extraction from ultra-low porosity and permeability shale reservoirs. During the hydraulic fracturing process, large amounts of water along with specific chemical additives are injected into the shale reservoirs, causing a series of reactions the influence the fluid composition and shale characteristics. This paper is focused on the investigation of the geochemical reactions between shale and fracturing fluid by conducting comparative experiments on different samples at different time scales. By tracking the temporal changes of fluid composition and shale characteristics, we identify the key geochemical reactions during the experiments. The preliminary results show that the dissolution of the relatively unstable minerals in shale, including feldspar, pyrite and carbonate minerals, occurred quickly. During the process of mineral dissolution, a large number of metal elements, such as U, Pb, Ba, Sr, etc., are released, which makes the fluid highly polluted. The fluid–rock reactions also generate many pores, which are mainly caused by dissolution of feldspar and calcite, and potentially can enhance the extraction of shale gas. However, precipitation of secondary minerals like Fe-(oxy) hydroxides and CaSO4 were also observed in our experiments, which on the one hand can restrict the migration of metal elements by adsorption or co-precipitation and on the other hand can occlude the pores, therefore influencing the recovery of hydrocarbon. The different results between the experiments of different samples revealed that mineralogical texture and composition strongly affect the fluid-rock reactions. Therefore, the identification of the shale mineralogical characteristics is essential to formulate fracturing fluid with the lowest chemical reactivity to avoid the contamination released by flowback waters.

Abstract Organic rich shales in coal-bearing strata deposited from marine to lacustrine environments are well developed in China. The Paleozoic coal-bearing shales have been significantly altered by a series of tectonic movements. Based on XRD, SEM, MICP, and a nitrogen adsorption experiment and in combination with other parameters in this paper, the mineral composition and pore structure characterization and deformation mechanism of coal-bearing shales were surveyed. The coal-bearing shales in eastern China undergo various types of deformation, including brittle, ductile, and brittle-ductile deformation. In eastern China, the macro pore size of shales grew with increasing quartz content under different types of structural deformation, while the specific surface area decreases as the quartz content increases in different types of structural deformation; With the increasing of clay mineral content, the average pore size and the specific surface area of BET became larger in the various types deformation shale, while the pore volume decreased in the brittle and brittle -ductile deformation shale and increased in the ductile deformation shale. The ductile and brittle-ductile deformation increase the specific surface area, the total pore volume of nano-pores, and the adsorption capacity of liquid nitrogen, and decrease the nano pore diameter. The micropores in the brittle-ductile and ductile shearing of clay minerals may the main factors affecting pore volume and total specific surface area. And it is the mesoporous structure that undergoes evolution in brittle-ductile-deformed shales, leading them to have the maximum pore volume and pore-specific surface area for pore-fracture systems. Brittle shear results in micro-fractures or large pores and thus has an impact on the desorption and percolation capability of shale gas, Ductile deformation increases the specific surface area of shales and enhances their shale adsorption capacity.

Abstract The exploration practices of marine and lacustrine shale gas in the Upper Yangtze Platform, South China show that there is a huge difference in gas content, which is mainly related to the difference of pore structure. This study is focused on marine Longmaxi and lacustrine Da'anzhai shales in the Upper Yangtze Platform, and their pore structure characteristics were compared and the mechanism of shale gas occurrence were discussed. First, the pore structures of marine and lacustrine shales were characterized and the effects of organic matter abundance, maturity and inorganic minerals on porosity were investigated. Then the contributions of different components to porosity were evaluated and the occurrence mode of methane in the pores of marine and lacustrine shales was established. The results show that (1) Three pore types can be observed in both marine and lacustrine shales: organic matter-hosted pores (OM pores), framework minerals-associated pores (FM pores), and clay minerals-associated pores (CM pores). OM pores are more developed in marine shale and CM pores are more developed in lacustrine shale. (2) Low pressure gas adsorption (LPGA) results show that the micropores of marine shale are dominated by pores of 0.4–0.7 nm and the micropores of lacustrine shale are dominated by pores of 0.5–0.9 nm, while the mesopores of marine shale are dominated by pores of 2–10 nm and the mesopores of lacustrine shale are dominated by pores of 3–30 nm, which are consistent with MIP results. (3) Organic matter has an impact on porosity of marine and continental shales but is not the most important controlling factor. And the contribution of organic matter to porosity in marine shale is greater than the contribution of organic matter to porosity in lacustrine shale. Shale porosity increases first and then decreases with the increase of maturity, which may be related to the carbonization of organic matter. (4) OM pores and CM pores tend to be preserved due to the presence of rigid grains that form rigid frameworks preventing these pores from collapsing. FM pores are mainly related to the dissolution of framework minerals by organic acids, and these dissolution pores can greatly improve the porosity and permeability of shale. (5) Quantification of porosity as related to mineralogy shows that OM pores contribute approximately 37% to total porosity of marine shale and 24% to total porosity of lacustrine shale and CM pores contribute approximately 53% to total porosity of marine shale and 67% to total porosity of lacustrine shale. (6) Shale gas occurrence is mainly controlled by the distribution mode of pore systems which are composed of OM pores, FM pores and CM pores. It is due to higher percentage on OM pores and lower percentage on CM pores that gas content of marine shale is generally higher than that of lacustrine shale.

Abstract To gain a better understanding of the gas-bearing property of Lower Cambrian Niutitang Formation shale and its influencing factors, the shale gas-bearing conditions, gas content, and composition in the Cengong block were investigated in this work based on wells CY1, TX1, and TM1. The Niutitang shale reservoir is characterized by large thickness, abundant organic matter with an average total organic carbon content of 4.74%, and high quartz content averaging 53.9%; therefore, it has good shale gas-bearing potential. The results of water immersion and ignition tests intuitively revealed the existence of shale gas based on the occurrence of continuous dense clusters of bubbles and long flames of 1–2 m. The Langmuir volumes of shale samples from well TM1, which ranged from 1.70 to 5.53 m3/t, were positively associated with TOC content and Brunauer–Emmett–Teller surface area, indicating a strong adsorption capacity and significant adsorbed gas potential. However, large differences were observed among the three wells with regard to gas-bearing properties; wells CY1 and TX1 had average total gas contents of 1.25 and 0.33 m3/t, respectively; the gas composition of well TM1 was dominated by nitrogen (N2), with contents generally exceeding 95%. Furthermore, the gas from well TX1 was mainly composed of methane with an average content exceeding 80%. Burial depth and TOC and quartz contents had significant control on the vertical distribution of gas content, and local tectonic preservation conditions resulted in differences of gas-bearing properties among various wells. The measured, lost, and total gas contents all presented positive correlations with TOC, quartz contents, and porosity, and were negatively related to clay content. The shale formed in deep-water shelf environments had better gas-bearing properties than that formed in shallow-water shelf environments. The broad axis of the box syncline in the Cengong block is a favorable location for shale gas accumulation, and fault development affects the shale gas plane distribution. Because of the influence of faults, the shale of well TM1 had low hydrocarbon content. Furthermore, based on the combined patterns of folds and faults as well as other special specific factors, a classification scheme of shale gas accumulation patterns in South China was developed.

We have investigated the geologic features of the lower Cambrian-aged Niutitang Shale in the northwestern Hunan province of South China. Our results indicate that the Niutitang Shale has abundant and highly mature algal kerogen with total organic carbon (TOC) content ranging from 0.6% to 18.2%. The equivalent vitrinite reflectance (equal-Ro) value is between 2.5% and 4.3%. Mineral constituents are dominated by quartz and clay. The average quartz content (62.8%) is much higher than that of clay minerals (26.1%), and this suggests a high brittleness index. Organic-matter pores, interparticle pores, intraparticle pores, interlaminated fractures, and structural fractures are all well developed. The porosity ranges from 0.6% to 8.8%, with an average of 4.8%, whereas the permeability varies from 0.0018 to [Formula: see text] (microdarcy) (averaging [Formula: see text]). The porosity of TOC- and clay-rich shale samples is generally higher than that of quartz-rich shale samples. The gas adsorption capacity of the Niutitang Shale varies from 2.26 to [Formula: see text], with a mean value of [Formula: see text]. The TOC content appears to significantly influence gas adsorption capacity. In general, TOC-rich samples exhibit a much higher adsorption capacity than TOC-poor samples.

Abstract Studies on the mechanisms of shale gas adsorption are of great significance for shale gas accumulation and reserves evaluation. In order to investigate the mechanisms of shale gas adsorption from the perspective of methane adsorption thermodynamics and kinetics, high-pressure methane adsorption and adsorption kinetics experiments were measured at 40.6 °C, 60.6 °C, 75.6 °C and 95.6 °C at pressures up to 52 MPa for the Lower Silurian Longmaxi shale sample collected from the Southern Sichuan Basin, China. The adsorption isotherms and kinetics curves of methane were obtained and a detailed analysis was performed. The results indicate that (1) Under the condition of 0–52 MPa, the absolute adsorption isotherm of methane on shale has the characteristics of type I adsorption isotherm. Temperature has an important effect on the maximum excess and absolute adsorption of methane. At the same temperature, the absolute adsorption amount of methane on shale increases slower at a higher pressure, which suggests that the methane adsorption rate decreases at a higher pressure. (2) The average isosteric heat of adsorption of methane on shale is 21.06 kJ/mol, indicating that the dominant adsorption process of methane on shale may be physical adsorption. The isosteric heat of adsorption increases with increasing absolute methane adsorption amount, indicating that the adsorption heat is mainly affected by the interaction between the adsorbed methane molecules. (3) Bangham kinetic model can be used to describe the dynamic adsorption process of methane on shale. Higher temperature and pressure lead to a lower Bangham adsorption rate constant, which makes it more difficult to adsorb methane molecules for shale. This is consistent with the conclusion drawn from the thermodynamics study of absolute adsorption isotherms of methane on shale.

Abstract The joint development of coal-bed methane (CBM) and shale gas at the Huainan coalfield in East China has drawn the attention of industrial and academic communities. In CBM and shale gas systems, a large amount of gas might be stored as adsorbed gas, which is closely related to the pore structure. In this paper, we report on the fractal characteristics of pores of non-marine organic shales from the Huainan coalfield. Measurements of X-ray diffraction, total organic carbon, vitrinite reflectance, and nitrogen adsorption were conducted on 13 shale samples to characterize the fractal dimensions and pore properties. Results indicated that pore morphology is dominated by cylindrical and slit shaped types. A small number of wedge shaped pores can be identified, but bottle neck pores are rare. The average pore diameter is between 4.44 and 22.80 nm, and pores with a diameters less than 50 nm are dominant. The pore surface fractal dimension (D 1 ) and pore structure fractal dimension (D 2 ) can be used to indicate overall fractal characteristics. The D 1 values are primarily affected by shale constituents. In terms of immature and low total organic carbon samples, the thermal maturity of theses shales is a cardinal factor governing pore structures, especially for surface area. D 2 values are obviously controlled by the type and connectivity of pores, and they are significant in analyzing pore structures, especially in assessing average pore diameter. Similarly to coals, shales with high D 1 values are favorable for methane adsorption, while high D 2 values go against adsorption capacity.

Abstract Lower Cambrian shale in the Upper Yangtze Platform (UYP), South China, is an important source rock of many conventional petroleum fields and was recently recognized as a promising unconventional shale reservoir. In this paper, hydrocarbon generation kinetics and petroleum physical properties were investigated using the PhaseKinetics approach ( di Primio and Horsfield, 2006 ) and a Cambrian shale sample from the Georgina Basin, North Territory Australia (NTA), as similar paleogeological and sedimentary environments in Cambrian are found for the UYP and NTA. The source rock comprises type II kerogen and belongs to an organofacies generating Paraffinic–Naphthenic–Aromatic low wax oil. Bulk petroleum generation can be described by a single frequency factor A = 8.43E + 14 (1/s) and a dominant activation energy at 56 kcal/mol, which is characteristic for sulphur-poor organic matter deposited in an anoxic marine environment. Onset (transformation ratio TR = 10%) and end (TR = 90%) of bulk hydrocarbon generation was calculated to take place at 120 °C and 165 °C respectively for an assumed average geological heating rate of 1.5°C/Ma. Based on the thermal history of a local “model”-well, onset temperature was not reached until the Middle Triassic (241 ma) when sediments were buried more than 2000 m and basalt eruptions caused enhanced heat flows. The main generation stage of primary petroleum took place during the Middle–Late Triassic and ended in the Early Jurassic (187 ma) for burial depths exceeding 4000 m (TR 90%; 165 °C). Temperatures increased to more than 200 °C in the Middle–Late Jurassic leading to secondary cracking of primary products. Hydrocarbons formed at the onset (TR = 10%) of petroleum generation can be characterized by a gas-oil-ratio (GOR) of 63 Sm3/Sm3, a saturation pressure (Psat) of 101 bar, and a formation volume factor (Bo) of 1.2 m3/Sm3. Those parameters stay low during primary petroleum generation before 203 ma, at temperatures > 10,000 Sm3/Sm3, Psat > 250 bar and Bo > 2.0 m3/Sm3) during secondary cracking starting roughly at 200 ma, 152 °C and 3500 m burial. Assuming zero expulsion, the shale reservoir position within the sedimentary basin indicates that bubble point pressure was always below reservoir pressure, and fluids in the shale reservoir occurred only as a single, undersaturated phase throughout maturation history. Black oil and volatile oil phases dominated during the primary cracking period, whereas wet gas and dry gas phases dominated during the secondary cracking period.