Unconventional Resources最新文献

The dynamic characteristics of shale gas flow directly affect the high-efficiency exploitation of shale gas, which has attracted widespread attention. In this study, the flow rate and permeability of gas (methane and helium) under variable confining stress and gas pressure conditions were carried out based on six shale samples from the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation in the southeastern Sichuan basin. By performing the seepage experiments of non-adsorbed gas (helium) and adsorbed gas (methane) under the same test conditions, the controls of gas slippage, matrix shrinkage and effective stress on the methane permeability change during the flow process were quantitatively decoupled. It is concluded that the methane permeability change is the result of the superposition of three major geological effects including gas slippage, matrix shrinkage and effective stress. During the gas pressure depletion, the effective stress effect is the main factor leading to the permeability decrease, while the gas slippage is the main factor causing the permeability increase. The permeability change caused by matrix shrinkage is more complex, and is closely related to the shale composition. Based on the control mechanism of permeability change, a prediction model of the methane permeability change in Chinese marine shales is proposed and has a good match with experimental data. The model is suitable for the process of gas pressure reduction under a constant confining stress condition. This research is helpful to understand the characteristic and mechanism of dynamic flow process of shale gas.

The time at which the difference between the waterflooding development effect and the elastic development effect equals 1% of the elastic development effect refers to the waterflooding response time, which is an important index for evaluating the effect of waterflooding in low-permeability reservoirs. Taking the five-point well pattern as an example, the response time–determining method was first designed using numerical simulation technology. Subsequently, the effects of different reservoir properties and development parameters on the response time of waterflooding were analyzed. Finally, the degree of influence of each factor on the waterflooding response time was determined using the orthogonal design method. The results showed that the higher the permeability and injection-production pressure difference is, the lower the response time is. The greater the oil viscosity and well spacing are, the longer the response time is. Thus, permeability exerted the most substantial effect on response time.

Alternate-temperature loading can cause cyclic thermal stress; therefore complex artificial fracture networks are formed in hot dry rock owing to thermal expansion and contraction under alternating thermal loading. In this study, the heat recovery potential of hot dry rock with a complex fracture network under alternating temperature loading was simulated numerically based on the hydrothermal coupling algorithm and compared with that of hot dry rock with a single fracture. The results show that the complex fractures formed under alternate thermal loading have better heat recovery performance than a single fracture, and the heat recovery performance of a complex fracture network is closely related to the intersection angle of fractures in the network. The temperature at the fracture outlet increases with an increase in the intersection angle between the branch fractures and the main fracture. At the angle of 30° between the branch fractures and main fracture, the average temperatures at the fracture outlet were 0.031% and 0.025% higher than those at the angles of 90° and 60°, respectively. Simultaneously with the water-injection, the temperature in the branch fractures gradually increased with an increase in the angle of the crossing fractures. When the angle between the branch and main fractures was 90°, the temperature fields on the two sides of the branch fracture were symmetrical. When the angle was 60° or 30°, the temperature fields on the two sides of the branch fracture were asymmetrical. The results of this study provide theoretical and technical support for the extraction of deep geothermal energy.

The primary production from unconventional reservoirs remains almost low, so applying enhanced oil recovery (EOR) methods is inevitable. Due to the different structures of these reservoirs from conventional resources, implementing of various EOR methods will be complicated. Waterflooding (as the type of low salinity water (LSW) or smart water flooding) has been comprehensively investigated in the literature for sandstone and carbonate formations. Water injection in the context of conventional formations generally is not practical due to the low injectivity of unconventional resources, and few studies have examined the potential of these methods for these types of reservoirs. In this review, I try to summarize the studies conducted in this field.

The identification of shale lithofacies is the basic work of shale gas exploration and development. Accurate quantitative characterization of different mineral components in fine-grained mixed shale is of great significance for the identification and classification of lithofacies types, the enrichment conditions of shale oil and gas (hydrocarbon generation, reservoir, occurrence and preservation), and the evaluation of shale oil potential (reservoir, oil bearing, fracturability and oil mobility). When organic-rich argillaceous laminae are moderately mixed with brittle laminae, the laminated shale is not only the favorable interval of shale oil and gas enrichment for hydrocarbon generation (organic-rich argillaceous laminae) and storage (brittle laminae), but also the excellent “sweet spots” for continental shale oil and gas optimization. Different shale lithofacies have distinct rock texture, fabric and composition, leading to different brittleness and rock physical properties. For the identification of shale lithofacies containing various components, the overlaps of different wire-line logging responses and the vague boundaries between various logging data cause the large deviation in the logging prediction of lithofacies by traditional methods. In this study, shale samples from the lower part of the third member of Shahejie Formation in Bozhong Sag of the Bohai Bay Basin are selected to carry out the reservoir characterization and then the data mining of logging information by a Back Propagation (BP) neural network coupled with Atomic Search Optimization (ASO) algorithm. The BP algorithm based on the identified shale lithofacies (expected output) and logging data index (input) is used to train the neural network. The complex and unrecognized nonlinear relationship between shale lithofacies and logging data is mapped onto the high-dimensional identifiable nonlinear quantitative relationship to establish the prediction model of the relative content of clay minerals, silicate minerals and carbonate minerals. This study reveals the main lithologic characteristics of lacustrine shale lithofacies from Shahejie Formation in Bozhong Sag, and the main controlling factors for shale lithofacies prediction based on logging data. Our results show that the main mineral composition of shale lithofacies associations can be effectively predicted through the whole rock X-ray diffraction data, wire-line log data and neural network analysis, which provides the basis for lithofacies identification shale interval in well locations lacking core and test data.

Recently, industrial gas flows have been produced from the vertical well acidification tests of Wells JS1 and YH1 in Section 1 of the Maokou Formation in the southern region of eastern Sichuan Province, China. This result proves that Section 1 contains a group of excellent source rocks and gas-bearing reservoirs. In this study, the pore structure characteristics and primary causes of the nanopore structure were explored using scanning electron microscopy, X-ray diffraction of total rocks, total organic carbon, liquid nitrogen adsorption, and other experimental methods to determine the pore development features of nodular limestone reservoirs in Section 1. The results substantiate the presence of complex pore structures in the nodular limestone reservoirs in Section 1. Nanopores are dominant and mainly comprise micropores and mesopores approximately 4 nm in diameter. The pore forms are particularly schistose clay silt pores consisting of rigid particles and flask-shaped pores. N₂ adsorption analysis showed that the specific surface area of the carbonate reservoir was 4.8842–8.1594 m²/g (mean = 6.0439 m²/g), and the pore volume was 0.008422–0.015098 cm³/g (mean = 0.043212 cm³/g). Mesopores were positively related to the total pore volume and total specific surface area, whereas macropore content had poorer correlations. Mesopores contribute more to the total pore volume and total specific surface area than macropores do. Spaces among the clay mineral layers (especially talcum gaps) predominantly contributed to the carbonate pore volume and specific surface area of the reservoir, and were positively related to the clay mineral content. The rocks have highly developed calcite pores, and their pore volumes and specific surface areas are negatively related to calcite pore content. Moreover, low organic content and low pore development degrees were observed. The organic content was weakly correlated with the pore volume and specific surface area, suggesting a low effect on reservoir performance. This assessment of the pore structure characteristics of Section 1 of the Maokou Formation yielded essential geological data that could inform the formulation of exploitation measures.

Shale oil has become an important alternative resource for conventional hydrocarbon resources. There are many areas with great exploration potential for shale oil worldwide, but the degree of exploration is relatively low. This study focuses on the shale oil reservoirs in the Tiaohu Depression of Santanghu Basin, northeast of Xinjiang Uygur Autonomous Region, China. We used pore permeability with 50 samples of saturation, thin section identification, high-pressure mercury injection, low-temperature nitrogen adsorption, and scanning electron microscopy (SEM), and according to these measurement technologies, we found that the study area is mainly composed of a set of basic-moderate volcaniclastic sediment; the shale reservoir is dense, with higher oil saturation; the fracture development zone is a movable desert area; and tuffaceous secondary pore formation is the main object of dissolution. It contains a variety of reservoir spaces, which are conducive to shale oil enrichment. The reservoir characteristics, microscopic pore structure, and origins of geological sweet spots are systematically analyzed, which provides research direction for shale oil exploration.

The Chang-7 Member of the Upper-Triassic Yanchang Formation has favorable geological conditions (e.g., extensive distribution of source rock, broad distribution of fine-grained sand bodies, stable structure, etc.) for developing a large shale oil pool. Initial assessments have estimated that the Chang-7 has shale oil resources of 3.0 × 10⁹ t approximately. The discovered Xin'anbian giant shale oil field has an estimated reserve of one billion tons. The shale oil in the Chang-7 Member has been developed by volumetric fracturing in long horizontal wells since 2011. By the end of 2021, more than 500 horizontal wells had been drilled, with average initial production of 9.6 t/d per well. Some large-scale effective development pilot zones (e.g., X233, Z183, A83, etc.) have been constructed. The source rock and reservoir in the Chang-7 Member are heterogeneous. Under an extensive distribution background of shale oil layers, there are some local 'sweet spots'. In order to reveal controlling factors for the productivity of shale oil, research involving the comparison of development effects, formation of geologic conditions, and technologies of the three typical pilot zones, has been conducted. The results showed that organic abundance in the source rock is the primary controlling factor for “sweet spot” distribution of the shale oil. The average TOC value in the black shale source rock in the Chang-7 Member is about 10% higher than that in the dark gray mudstone. The average hydrocarbon generation intensity is about 2.0 × 10³ t/km², the average hydrocarbon expulsion rate is 34.6%, and the production rate of gaseous hydrocarbons is 14.65–39.46 m³/t. In the vicinity of black shale with a high TOC value, the oil filling intensity in the shale oil reservoirs is high, with oil saturation of up to about 70%, and a gas-to-oil ratio >90 m³/t. Secondly, the 'sweet spots' with such petrophysical properties control the enrichment of reservoirs. Owing to conditions of low-porosityand low-permeability, the shale oil reservoirs in the Chang-7 Member of the Ordos Basin still developed 'sweet spots',with porosity larger than 9% and permeability larger than 0.08 × 10⁻³ μm² . These reservoir sweet spots have a pyrolysis yield of hydrocarbons >9 mg/g and the development wells have high initial and total production, a slow decline rate, and low water cut. Moreover, the dissolved gas in shale oil in the Chang-7 Member of the Ordos Basin is an oil-type gas that was generated during the primary pyrolysis stage of sapropel kerogen after entering a mature period. The gas-to-oil ratio in crude oil is controlled by several factors, such as organic abundance and maturity in source rock, thickness, petrophysical properties, and fractures in reservoirs. The overlap of black shale with high TOC, source rock thickness >10 m, thermal maturity Ro > 0.8%, and type I and II high-quality reservoi