Yandy Scientific Press
Not a member yet
641 research outputs found
Sort by
Geology-engineering integration to improve drilling speed and safety in ultra-deep clastic reservoirs of the Qiulitage structural belt
Get PDFThe Qiulitage structural belt in Tarim Basin has a large reservoir burial depth and complex geological conditions. Challenges such as ultra-depth, high temperature, high pressure and high stress lead to significant problems related to well control safety and project efficiency. To solve these key technical issues that set barriers to the process of exploration and development, a drilling technology process via the integration of geology and engineering was established with geomechanics as the bridge. An integrated key drilling engineering technology was formed for improving the drilling speed and safety of ultra-deep wells, including well location optimization, well trajectory optimization, formation pressure prediction before drilling, stratum drillability evaluation, and bit and speed-up tool design and optimization. Combined with the seismic data, logging data, structural characteristics, and lithology distribution characteristics, a rock mechanics data volume related to the three-dimensional drilling resistance characteristics of the block was established for the first time. The longitudinal and lateral heterogeneities were quantitatively characterized, providing a basis for bit design, improvement and optimization. During the drilling process, the geomechanical model was corrected in time according to the actual drilling information, and the drilling “three pressures” data were updated in real time to support the dynamic adjustment of drilling parameters. Through field practice, the average drilling complexity rate was reduced from 18% to 4.6%, and the drilling cycle at 8,500 m depth was reduced from 326 days to 257 days, which comprised significant improvements compared to the vertical wells deployed in the early stage without considering geology-engineering integration.Cited as: Chen, C., Ji, G., Wang, H., Huang, H., Baud, P., Wu, Q. Geology-engineering integration to improve drilling speed and safety in ultra-deep clastic reservoirs of the Qiulitage structural belt. Advances in Geo-Energy Research, 2022, 6(4): 347-356. https://doi.org/10.46690/ager.2022.04.0
An advanced general dominant eigenvalue method of accelerating successive substitution during flash calculation for compositional reservoir model
Get PDFThe efficiency and accuracy of phase equilibrium calculations are essential in compositional reservoir models. Usually, a significant part of the computational effort in compositional reservoir simulations is spent on phase equilibrium calculations. The nonlinear nature of phase equilibrium calculations requires an iterative solution procedure. Although the successive substitution method (SSM) is robust and simple to implement, it suffers from slow convergence, especially near the critical point of the mixture. The general dominant eigenvalue method (GDEM) has been widely used to accelerate SSM, but its stability and efficiency deteriorate as the temperature and pressure approach the critical point. This paper proposes a modified form of GDEM to improve its performance in the near-critical region. The modifications have two aspects. First, the liquid phase fraction in the mixture is added as a variable when performing GDEM acceleration, improving both stability and efficiency. The second modification is a post-calibration step imposed to replace the conventional criterion, which is applied before triggering GDEM. With the help of the post-calibration step, the stability of the modified GDEM is ensured, and more importantly, the calculation efficiency can be improved. Numerical tests of three hydrocarbon mixtures, including different numbers of components, show that the stability of the modified GDEM is almost the same as SSM and that its calculation efficiency is much higher than SSM and the conventional GDEM.Cited as: Wang, X., Wei, D., Wang, X., Zhao, X., Li, J., Noetinger, B. An advanced general dominant eigenvalue method of accelerating successive substitution during flash calculation for compositional reservoir model. Advances in Geo-Energy Research, 2022, 6(3): 241-251. https://doi.org/10.46690/ager.2022.03.0
Application of underbalanced tubing conveyed perforation in horizontal wells: A case study of perforation optimization in a giant oil field in Southwest Iran
Get PDFUnderbalanced perforation can substantially reduce formation damage and improve the efficiency of production operation. The field in question is a giant oil field in Southwest Iran, with over 350,000 bbl/day production rates. Reservoir X is the main reservoir of the field and includes 139 horizontal wells out of the total of 185 production wells drilled in the field. Despite its technical difficulties, under-balance perforation has been proven to result in high productivity ratios and has been shown to reduce workover costs if appropriately conducted. Therefore, this study investigated a customized underbalanced tubing conveyed perforation to enhance oil production. First, post-drilling formation damage was estimated using Perforating Completion Solution Kits. Next, high-density guns (types 73 and 127) with high melting explosives were selected based on the reservoir and well specifications. angles of 60◦ and 90◦ , shot densities of 16 and 20 shots per meter, perforation diameters of By conducting a sensitivity analysis using schlumberger perforating analyzer program, shot 8 and 10 mm, and helix hole distribution were selected as optimized perforation parameters and resulted in productivity ratios up to 1.18. The current study provides a case study of applying a combination of two previously proven technologies, tubing convoyed and underbalanced perforation, in Iran’s giant oilfield. The method used and the outcome could be used to analyze the efficiency of applying the technology in other green or mature fields.Cited as: Mohammadian, E., Dastgerdi, M. E., Manshad, A. K., Mohammadi, A. H., Liu, B., Iglauer, S., Keshavarz, A. Application of underbalanced tubing conveyed perforation in horizontal wells: A case study of perforation optimization in a giant oil field in Southwest Iran. Advances in Geo-Energy Research, 2022, 6(4): 296-305. https://doi.org/10.46690/ager.2022.04.0
Molecular modeling on Gulong shale oil and wettability of reservoir matrix
Get PDFUnderstanding molecular interactions between oil and reservoir matrix is crucial to develop a productive strategy for enhanced oil recovery. Molecular dynamics simulation has become an important method for analyzing microscopic mechanisms of some static properties and dynamic processes. However, molecular modeling of shale oil and reservoir matrix is still challenging, due to their complex features. Wettability, which is the measurement of oil-matrix interactions, requires in-depth understanding from the microscopic perspective. In this study, the density, interfacial tension and viscosity of eleven common components in shale oil are calculated using molecular dynamics simulations. Then a molecular model of Gulong shale oil is built, based on the reported experimental results and simulations. Compared with the variation in hydrocarbon content, the change in polar component content leads to more significant variations in the physical properties of shale oil. This molecular model is also employed to investigate the wettability of shale-oil nanodroplets on minerals and organic matter, with or without the surrounding aqueous phase. This work suggests fresh ideas for studying the oil-matrix interactions on the nanoscale and provides theoretical guidance for shale oil exploitation.Cited as: Cui, F., Jin, X., Liu, H., Wu, H., Wang, F. Molecular modeling on Gulong shale oil and wettability of reservoir matrix. Capillarity, 2022, 5(4): 65-74. https://doi.org/10.46690/capi.2022.04.0
Effects of pore connectivity and water saturation on matrix permeability of deep gas shale
Get PDFShale matrix permeability is an important indicator for evaluating gas transport and production. However, the effects of pore connectivity and water saturation on the matrix permeability in deep gas shales have not been adequately studied. In this study, the permeability of deep shales in the Yichang area of the Middle Yangtze was characterized using three methods. These included the determination of apparent permeability in different directions via pulse-decay, also matrix permeability obtained via the Gas Research Institute method, and the connected pore network permeability via the mercury injection capillary pressure technique. The results revealed a significant difference between the horizontal and vertical permeability of deep shales. The smaller the size of the multiple connected pore network, the larger was the effective tortuosity and the lower the permeability. Comparison of the three permeabilities and combined microscopic observations revealed that microfractures and laminae were the dominant gas transport channels. Importantly, the matrix permeability decreased exponentially with increasing water saturation, with water vapor adsorption experiments revealing that water occupation of pores and pore-throat spaces smaller than 10 nm in diameter was the main reason for this decrease in matrix permeability. Collectively, proposed method of evaluating effective permeability with an index for shale gas reservoirs is significant for sweet spot selection and production prediction of shale gas reservoirs around the globe.Cited as: Zhao, J., Sun, M., Pan, Z., Liu, B., Ostadhassan, M., Hu, Q. Effects of pore connectivity and water saturation on matrix permeability of deep gas shale. Advances in Geo-Energy Research, 2022, 6(1): 54-68. https://doi.org/10.46690/ager.2022.01.0
Mechanism and influence factor of hydrocarbon gas diffusion in porous media with shale oil
Get PDFDue to the compactness of shale reservoir matrix and the high conductivity of fractures, the hydrocarbon gas injection huff and puff method or displacement is the most realistic technology to improve shale oil recovery. The diffusion mechanism plays an important role in shale oil development; therefore, it is crucial to figure out the factors influencing diffusion, which could enhance shale oil recovery. In this paper, a physical simulation experiment is designed to evaluate the diffusion ability of hydrocarbon gas. Diffusion experiments are conducted to simulate diffusion in the bulk fluid and in the porous media, to learn about how the pressure, permeability and fracture affect the diffusion behavior. The diffusion coefficients between the bulk diffusion and core sample diffusion are compared. The experimental results show that the diffusion coefficient and mass transfer capacity are positively correlated with permeability and pressure: increasing these parameters can promote the diffusion process. The diffusion coefficient of hydrocarbon gas in a saturated oil core is significantly less than that in crude oil, which indicates that the porous media seriously affects the process of gas diffusion in crude oil. Fractures have little impact on the diffusion behavior. Combined with numerical simulation, the influencing factor of diffusion on the development effect of hydrocarbon gas injection is clarified. The recovery enhances and then decreases with the increasing diffusion coefficient.Document Type: Original articleCited as: Wanyan, Z., Liu, Y., Li, Z., Zhang, C., Liu, Y., Xue, T. Mechanism and influence factor of hydrocarbon gas diffusion in porous media with shale oil. Advances in Geo-Energy Research, 2023, 7(1): 39-48. https://doi.org/10.46690/ager.2023.01.0
Understanding gas transport mechanisms in shale gas reservoir: Pore network modelling approach
Get PDFThis report summarizes the recent findings on gas transport mechanisms in shale gas reservoir by pore network modelling. Multi-scale pore network model was developed to accurately characterize the shale pore structure. The pore network single component gas transport model was established considering the gas slippage and real gas property. The gas transport mechanisms in shale pore systems were elaborated on this basis. A multicomponent hydrocarbon pore network transport model was further proposed considering the influences of capillary pressure and fluid occurrence on fugacity balance. The hydrocarbon composition and pore structure influences on condensate gas transport were analyzed. These results provide valuable insights on gas transport mechanisms in shale gas reservoir.Document Type: Research highlightCited as: Song, W., Yao, J., Zhang, K., Yang, Y., Sun, H. Understanding gas transport mechanisms in shale gas reservoir: Pore network modelling approach. Advances in Geo-Energy Research, 2022, 6(4): 359-360. https://doi.org/10.46690/ager.2022.04.1
A method for assigning pre-exponential factors for kerogen kinetics, calibrated with Easy%RoDL, and comparison with EASY%Ro
Get PDFModeling hydrocarbon-generation processes requires reliable kinetic models for the thermal decomposition of kerogens. To improve confidence and accuracy in modeling of generation, this study employs data from both natural and laboratory maturation to quantify thermal stress and strain for kerogens in 11 source-rock data sets. The method yields kinetic parameters (pre-exponential factor and Ea) for hydrocarbon generation that are constrained to make accurate predictions about thermal stress (quantified here as Ro-equivalent) and thermal strain (quantified as Hydrogen Index) under both laboratory and natural conditions. Methods for converting Tmax values to Ro-equivalents were examined and are discussed briefly. Vitrinite reflectance values were calculated at geological heating rates using the Easy%RoDL kinetic formulation, and were then compared with previous results obtained using EASY%Ro. The large differences observed between the EASY%Ro and Easy%RoDL evaluations are attributed to the differences in the pre-exponential factors in those two Ro-kinetic formulations. Understanding this relationship gives us a way to choose kinetic parameters for hydrocarbon generation that will work well for modeling under geological conditions. The single best A factor for hydrocarbon-generation when using EASY%Ro is 1e13 s−1 , while that for Easy%RoDL is 2e14 s−1 . The minor variation in A factors observed within each of the data sets may or may not be real. Using these results and concepts, more reliable hydrocarbon-generation windows in terms of either Ro-equivalent or Transformation Ratio can be achieved and cross-correlated. These results thus have the potential to increase both the accuracy of hydrocarbon-generation modeling, and the confidence in its results.Document Type: PerspectiveCited as: Waples, D. W., Yang, S. A method for assigning pre-exponential factors for kerogen kinetics, calibrated with Easy%RoDL, and comparison with EASY%Ro. Advances in Geo-Energy Research, 2023, 7(1): 1-6. https://doi.org/10.46690/ager.2023.01.0
Mechanisms in CO2-enhanced coalbed methane recovery process
Get PDFInjection of CO2 and subsequent desorption of CH4 is considered to be the most efficient enhanced coalbed methane (ECBM) recovery technique to date. Meanwhile, CO2-ECBM is an excellent option for CO2 geo-sequestration for an extended period. Despite ongoing research efforts and several field applications of this technology, the mechanisms of the process have yet to be fully understood. The coalbed heterogeneity, the fluid interactions with coal, the CO2 induced swelling, and the continuous pressure and composition changes require outright insights for optimal application of the technique. Furthermore, intermolecular interactions of CO2 and CH4, their competitive adsorption on the dry/wet coal surface, and the dispersion and advection processes play an important role in defining the CO2-ECBM recovery process. An attempt has been made here to understand the key mechanisms of CO2-ECBM recovery in coalfields, particularly the adsorption of CO2 in the supercritical state at the recommended sequestration depth.Cited as: Asif, M., Wang, L., Wang, R., Wang, H., Hazlett, R. D. Mechanisms in CO2-enhanced coalbed methane recovery process. Advances in Geo-Energy Research, 2022, 6(6): 531-534. https://doi.org/10.46690/ager.2022.06.0
Predicting adsorbed gas capacity of deep shales under high temperature and pressure: Experiments and modeling
Get PDFTemperature and pressure conditions of deep shale are beyond experiment range, and the amount of adsorbed gas is difficult to determine. To predict the adsorbed gas content of deep shales under formation conditions, isothermal adsorption experiments and model building were conducted on shale samples from Longmaxi Formation in China. A temperature-dependent adsorption model based on the Langmuir equation is proposed, which can be well-fitted by observed isotherms with a high correlation coefficient. Based on the fitted parameters at 303.15 K, the isothermal adsorption curves at 333.15 K, 363.15 K, and 393.15 K are predicted, showing a good agreement with experimental curves available. Compared with previous prediction methods, the biggest advantage of the proposed method is that it can be carried out only based on one-time isothermal adsorption experiment. Based on the predictions, the downward trend of the excess adsorption curves will slow down under high temperature and pressure conditions, and when the pressure reaches a certain level (> 80 MPa), the temperature has little effect on the excess adsorption capacity. While for absolute adsorption, the gas adsorption reaches saturation much slowly at high temperature, it can also reach saturation under formation pressure. Under the burial depth of marine shale, temperature plays a major role in controlling the adsorbed gas, resulting in the decrease of adsorbed gas content in deep shale, and its ratio will further decrease as the depth increases.Cited as: Zhou, S., Wang, H., Li, B., Li, S., Sepehrnoori, K., Cai, J. Predicting adsorbed gas capacity of deep shales under high temperature and pressure: Experiments and modeling. Advances in Geo-Energy Research, 2022, 6(6): 482-491. https://doi.org/10.46690/ager.2022.06.0