Geofluids

Various diseases and failures inevitably appear on expressway roadways in water-rich strata under the long-term erosion of water. It is very difficult to support the surrounding rock of a water-rich roadway because water will corrode the anchorage bond and weaken the surrounding rock mass. In the process of supporting, damage and fracture of anchor bolt often appear in water-rich roadway. In order to study the stability analysis of a support anchor bolt in the process of surrounding rock fracture evolution and the relationship between the prestressed value and the length of the anchor bolt, this paper studied the fracture evolution law of surrounding rock and the progressive debonding law of the bolt are studied by RFPA3D numerical simulation and used MATLAB software to calculate and draw several graphs to reveal the mechanism by analytical method. The following main conclusions were drawn: (1) the change and attenuation of the surrounding rock stress have a certain influence on the stability of the supporting bolt. The existence of confining pressure (horizontal stress) has a significant impact on the ultimate pullout force of anchor bolts. (2) With the gradual destruction of the surrounding rock, the shear stress, horizontal stress, and vertical stress in the surrounding rock are gradually reduced to zero, and the change speed of the surrounding rock is fast at the shallow surface and slow at the deep. (3) The interface shear stress tends to a low stable value after debonding, which means the value of friction resistance is relatively stable in different positions. (4) The frictional resistance after interface debonding is an important condition to maintain the balance of higher anchorage force. If there is no friction resistance, when the axial force of the anchor bolt reaches the initial critical value, the interface debunking process will develop catastrophically and cannot be stabilized until complete failure, even if the axial force no longer increases.

With the great breakthrough in natural gas exploration of Paleozoic Taiyuan formation in Longdong exploratory area in the southwestern part of Ordos Basin, it is urgent to solve the petrological nomenclature of sedimentary bauxite, so as to further study the pore formation mechanism, distribution law, and controlling factors of bauxite reservoirs. In this paper, X-ray diffraction, polarizing microscope, scanning electron microscope, and other methods are used to analyze the mineral composition and structure of bauxite rocks in the study area and give appropriate names. The results show that the sedimentary sequence of bauxite in the study area can be divided into five sections: A, B, C, D, and E. The main mineral components are diaspore (C section content can be more than 90%), illite, kaolinite, and chlorite; accessory mineral include anatase and pyrite; trace components include quartz, feldspar, rutile, hematite, and rock salt; and some of the pores are filled with calcite, siderite, and (iron) dolomite. The rock structure is mainly bedding and massive structure, and some of them have geopetal structure. The texture mainly consists of granular texture, grain (powder crystal) texture, gel texture, and algal bonding texture. Considering the special lithology of section A~C and the lack of existing nomenclature method, based on mineral composition and sedimentary fabric, a triangulation classification nomenclature method is established, which adopts structure+texture as secondary name and the main mineral components diaspore-mud-pyrite of the three end-member mineral components as primary name. It can not only highlight the mineral assemblage characteristics of sedimentary sequence of bauxite but also reflect the lithologic characteristics of reservoir development section and the influencing factors of reservoir formation, effectively reflecting the petrological characteristics of bauxite reservoir. Among them, the diaspore rocks with granular, bean-oolitic, and grain texture are the main lithologies forming the natural gas reservoir space of Taiyuan formation in Longdong area. The naming method is feasible and reliable for sedimentary bauxite rocks, which lays a good foundation for the study of natural gas reservoir, pore formation mechanism, and distribution law in Longdong area, southwest of the basin.

For horizontal well in low-permeability gas reservoir, the effects of threshold pressure gradient, stress sensitivity, and gas slippage have significant impacts on the well productivity. At present, there are few productivity formulas for horizontal gas well considering all these factors. In this paper, based on the flow analysis of horizontal well in low-permeability gas reservoir, the whole flow field was divided into two parts, namely, far wellbore region and near wellbore region, among which the far wellbore region is composed of plane linear flow region and plane radial flow region and the near wellbore region is composed of vertical plane radial flow region and spherical plane central flow region. Then, a new productivity formula is established based on the steady-state seepage theory and the equivalent seepage resistance method, with the consideration of threshold pressure gradient, stress sensitivity, and gas slippage effect. The accuracy of the formula in this paper is verified through comparing with other classical models, and the influence of various factors on the well productivity is analyzed. The analysis results show that stress sensitivity has the most significant effect on horizontal gas well production, followed by threshold pressure gradient, and the gas slippage has the least effect. With the consideration of all influencing factors, the higher the formation pressure and reservoir thickness, the higher the productivity, and the increase of productivity increases with the increase of flow pressure difference. The increasing trend of gas productivity index per meter with the increase of reservoir permeability is first fast and then slow. When the reservoir permeability is greater than 1.2 mD, the increment of gas productivity index per meter (MGPI) decreases. When the length of horizontal well is greater than 1400 m, the increment of gas productivity index per meter decreases with the increase of gas reservoir thickness. Therefore, it is recommended to control the horizontal well length within 1400 m in low-permeability gas reservoir. In addition, the absolute open flow charts corresponding to reservoir thickness and horizontal well length under different reservoir permeability conditions were also given, which can provide theoretical guidance for the selection of horizontal well length during the development of low-permeability gas reservoirs.

Viscosity reducer flooding has been successfully applied in tertiary oil recovery of ordinary heavy oil reservoirs. However, lowering interfacial tension or reducing oil viscosity, which is more critical for viscosity reducer to improve oil recovery of ordinary heavy oil, has not yet formed a unified understanding, which restricts the further large-scale application of viscosity reducer flooding for ordinary heavy oil reservoir. Moreover, when the dominant water flow channel is formed in the reservoir, the sweep efficiency decreases sharply and can affect oil recovery efficiency of viscosity reducer. Therefore, in this study, the concept of branched-preformed particle gel (B-PPG) coupling viscosity reducer flooding is proposed. The oil-water interfacial tension performance, emulsification ability, and viscosity reduction performance of three different viscosity reducers were evaluated. The enhanced oil recovery ability of viscosity reducers, B-PPG, and viscosity reducer/B-PPG composite systems was investigated by performing sand pack flooding experiments. The results show that the oil-water interfacial tensions of the three viscosity reducers S1, S2, and S3 are 0.432 mN·m^-1, 0.0112 mN·m^-1, and 0.0031 mN·m^-1, respectively. S1 with the highest interfacial tension has the best emulsification and viscosity reduction performance, S2 is the second, and S3 is the worst. The lower the interfacial tension, the worse the emulsification stability. The sand pack flooding results show that the incremental oil recovery of viscosity reducer S2 flooding is the largest, 7.5%, followed by S1, 7.3%, and S3, 5.6%. The viscosity reducer S2 with moderate interfacial tension and emulsifying capacity has the best ability to improve the recovery of ordinary heavy oil. The incremental oil recovery of B-PPG is 12.7%, which is significantly higher than that of viscosity reducer flooding. Compared with viscosity reducing flooding, the viscosity reducer/B-PPG composite systems have better enhanced oil recovery capacity. The findings of this study can help for better understanding of enhancing oil recovery for ordinary heavy oil reservoir.

Reservoir sensitivity can lead to the physical or chemical reactions to block the pore throat. It is helpful for reducing the damage on tight sandstone reservoir to study the reservoir sensitivity and its controlling factors. This paper mainly focuses on the tight sandstone of the Chang 4+5 and Chang 6 reservoirs of the Yanchang Formation in the Nanniwan Oilfield, Ordos Basin. The reservoir sensitivity characteristics were evaluated through the core sensitivity experiment after the petrological and petrophysical analysis and pore structure study. The influencing factors on tight sandstone reservoir sensitivity were discussed from several aspects, such as clay mineral composition, porosity, permeability, and pore structure. The results show that the rock type of the Chang 4+5 and Chang 6 reservoirs in the N 212 well block of the Nanniwan Oilfield is mainly arkose, with the mean porosity of 11.2% and 8.45% and the mean permeability of  μm² and  μm², respectively. The clay mineral components mainly include chlorite and illite/smectite. Both the two reservoirs are characterized by moderate to weak velocity sensitivity, moderate to weak water sensitivity, moderate to strong salt sensitivity, weak acid sensitivity, and moderate to weak alkali sensitivity. In specific, the Chang 4+5 reservoir is stronger in velocity and salt sensitivities, while it is weaker in water, acid, and alkali sensitivities than those of the Chang 6. The major controlling factors on reservoir sensitivity are clay mineral component, petrophysical property, and pore structure. Among these, the velocity sensitivity displays the positive correlation with pore structure, porosity, and permeability. The water sensitivity will become strong with the increase of the volume content of illite/smectite, but weak with the getting better of pore structure. The acid sensitivity is positively correlated with the volume content of chlorite but is negatively correlated with pore structure. With the getting better of pore structure, the salt sensitivity and alkali sensitivity will become strong and weak, respectively. The research results can be as the guidance for the tight sandstone reservoir protection in the study area and the adjustment and optimization of the regional reservoir development scheme.

Digital rock twins are widely used to obtain hydraulic properties of porous media by simulating pore-scale fluid flow. Multifractal characteristics of pore geometry and flow velocity distribution have been discovered with two-dimensional (2D) images and three-dimensional (3D) models, whereas the dependency of results on the resolution is not well known. We investigated resolution-dependent multifractal properties of 3D twin models for a sandstone sample with originally 3 μm resolution images. 3D pore-scale water flow was simulated with the lattice Boltzmann method (LBM). As indicated by multifractal analyses, the generalized dimension spectra, the Hölder exponent spectra, and singularity spectra of the flow velocity are similar to that of the pore geometry but different in ranges and sensitivities to the change in the model resolution. Nonlinear dependencies of 2D/3D porosity, holistic/slice permeability, equivalent pore radius squared, and multifractal parameters on the resolution were discussed.