In hydrogeochemistry and industrial processes, the low solubility characteristics of sulfate scale minerals pose a high risk of scaling, making solubility prediction crucial for scaling prevention. Traditional empirical solubility prediction models rely on extensive fitting of experimental solubility data, exhibit inconsistent forms of expression, and require multiple adjustable parameters. In this study, we develop a novel thermodynamic general prediction model for sulfate scale mineral solubility that depends on only five physically meaningful characteristic parameters of the substance. The model accurately predicts solubility data from the existing literature at the temperature range of 0–250 °C and the pressure range of 1–1000 bar. The average absolute deviation between the predicted values of the proposed model and experimental data ranges from 3.40 % to 9.79 %, while the empirical model exhibits a deviation range of 8.91 % to 19.31 %, demonstrating that the proposed model is more accurate and reliable. Additionally, a critical phase transition line expression for calcium sulfate hydrates under high temperature and high pressure is introduced that can be used to accurately predict the temperature and pressure ranges where stable phases of calcium sulfate dihydrate and calcium sulfate anhydrite exist. This study lays the groundwork for developing solubility prediction models in mixed electrolyte solutions and provides important guidance for designing effective treatment processes, optimizing production workflows, and reducing operational costs.

Accurately describing the behavior of a gas-water two-phase flow in shale gas reservoirs is crucial for analyzing production dynamics in the field. Current research generally lacks consideration of the differences in physical properties and adsorption characteristics between the oleophilic organic matrix and the hydrophilic inorganic matrix. This study considers the organic matrix system as a single-phase gas flow, while the inorganic matrix and fracture systems involve a gas-water two-phase flow. Taking into account the impact of the adsorbed water layer on permeability at the surface of nanoscale pores in an inorganic matrix, the model comprehensively incorporates multiple mechanisms such as adsorption-desorption, the slippage effect, and Knudsen diffusion in the organic matrix and clay minerals. A multiscale gas-water two-phase comprehensive flow model for shale gas reservoirs has been established, and the results of the numerical model were validated against commercial software and actual field data. Simulation results over 1000 days indicate that early production from gas wells is primarily supplied by fractures, whereas free gas or desorbed gas from inorganic and organic matrices gradually contributes to the flow during the middle and later stages of production. As the Langmuir pressure and volume in the organic matrix and clay minerals increase, so does the corresponding gas production. The adsorbed water layer on the surface of inorganic nanopores reduces permeability, leading to a decrease in single-well cumulative gas production by 8.41%. The impact of the adsorbed water layer on gas production cannot be overlooked. The simulation method proposed in this study provides theoretical support for analyzing the gas-water two-phase flow behavior in shale gas reservoirs.

Large-scale karst caves are the principal storage spaces for hydrocarbon resources in fracture–cavity carbonate reservoirs. Drilling directly into these caves is considered the ideal mode of development, but many wells do not effectively penetrate karst caves. Therefore, acid fracturing is employed to generate artificial fractures that can connect with these caves. However, there are no appropriate well test methods for fracturing wells in fracture–cavity reservoirs. This study establishes a novel pressure transient analysis model for such wells. A new mathematical model is proposed that couples linear flow in acid fracturing cracks with radial flow in the oil drainage area. The Laplace transform and Stehfest numerical inversion provided analytical solutions for the bottomhole pressure. Typical log–log well testing curves were plotted to analyze oil flow, which occurs in ten stages. During the flow stage in fracturing cracks, the pressure and pressure derivative curves are parallel lines with a slope of 0.5. In the stage of karst cave storage, the pressure derivative curve is a straight line with a slope of 1. A comparison with previous models confirmed the validity of the proposed model. The influence of key parameters on the behavior of typical curves is analyzed. A field case study of the proposed model was carried out. Parameters related to fracturing cracks and karst caves, such as the crack length and cave radius, were successfully estimated. The proposed model has great potential for determining formation parameters of fracture–cavity reservoirs.

The study of adsorption-diffusion kinetics in shale gas reservoirs is crucial for predicting reserves and assessing production. Although some scholars have proposed adsorption-diffusion kinetics models, there are few models and interpretation methods that systematically consider Arrhenius's thermodynamics parameters and actual adsorption gas concentration. In this study, we propose a novel model for analyzing the kinetics processes of adsorbed gas and free gas in shale. The analysis of adsorbed gas kinetics experimental data indicates a negative correlation between temperature and the adsorption-diffusion equilibrium time. Sensitivity analysis of the parameters reveals that three parameters (the diffusion activation energy, adsorption activation energy, and desorption pre-exponential factor) are positively correlated with adsorption-diffusion equilibrium time, whereas the other three parameters (the diffusion pre-exponential factor, adsorption pre-exponential factor, and desorption activation energy) are negatively correlated. Furthermore, we find that higher temperatures lead to lower concentrations of free gas at equilibrium state. Larger radius positions in spherical particles tend to reach adsorption-diffusion equilibrium earlier. Compared to the traditional diffusion kinetics model, the proposed novel model exhibits a significant lag effect in the calculated equilibrium time and more accurately describes the gas adsorption-diffusion kinetics equilibrium process.

Clarifying the fluid transport mechanism in nanoporous shale media for shale gas extraction is crucial. In this study, the microscopic mechanism of gas and water migration and diffusion in the nanopores of shale clay minerals is obtained through molecular dynamics simulation. Because of the different compositions and structures of different clay minerals in shale, the adsorption heats of different clay mineral surfaces with CH4 and H2O molecules are different. As the pressure increases, the adsorption heat of the clay mineral surfaces with CH4 and H2O molecules increases. At the same temperature and pressure, the adsorption heat of the clay mineral surfaces with H2O molecules is greater than that with CH4 molecules, and the high-energy adsorption sites on the surface of clay minerals are mainly occupied by H2O molecules, leading to H2O molecules significantly aggregating on the shale clay mineral surfaces, while CH4 molecules are dispersed in an disordered manner in shale clay minerals. The higher the pressure or the lower the temperature is in shale formations, the higher is the degree of aggregation of H2O molecules on the surface of clay minerals. The migration speed and fluidity of gas and water increase with the increase in temperature and decrease with the increase in pressure. At the same temperature and pressure, the migration speed of CH4 molecules is greater than that of H2O molecules. This is because H2O molecules are polar and have stronger intermolecular forces compared to CH4 molecules, resulting in weaker mobility of H2O molecules. The diffusion coefficient of CH4 molecules in kaolinite is the highest, followed by that in illite, and that in montmorillonite is the lowest. When the diffusion coefficient of H2O molecules in shale clay minerals is lower, the corresponding diffusion coefficient of CH4 molecules is higher.

Summary To address the significant scaling challenges within the near-wellbore formation of ultradeep natural gas reservoirs characterized by high temperature and high salinity, we developed a dynamic scaling prediction model. This model is specifically designed for the prediction of scaling in gas-water two-phase seepage within fractured-matrix dual-porosity reservoirs. It accounts for the concentration effects resulting from the evaporation of water on formation water ions. Our scaling model is discretely solved using the finite volume method. We also conducted on-site dynamic scaling simulations for gas wells, allowing us to precisely predict the distribution of ion concentrations in the reservoir, as well as changes in porosity and permeability properties, and the scaling law dynamics. The simulation results reveal a significant drop in formation pressure, decreasing from 105 MPa to 76.7 MPa after 7.5 years of production. The near-wellbore formation is particularly affected by severe scaling, mainly attributed to the radial pressure drop funneling effect, leading to a reduction in scaling ion concentrations in the vicinity of the wellbore. Calcium carbonate is identified as the predominant scaling component within the reservoir, while calcium sulfate serves as a secondary contributor, together accounting for roughly 85.2% of the total scaling deposits. In contrast, the scaling impact on the matrix system within the reservoir remains minimal. However, the central fracture system exhibits notable damage, with reductions of 71.2% in porosity and 59.8% in permeability. The fracture system within a 5-m radius around the wellbore is recognized as the primary area of scaling damage in the reservoir. The use of the simulation approach proposed in this study can offer valuable support for analyzing the dynamic scaling patterns in gasfield reservoirs and optimizing scaling mitigation processes.

The core pore structure is mainly described by fractal theory. Conventional single fractal models cannot express the multi-peak distribution characteristics of coal rock, shale, carbonate rock, and other cores. A multifractal model has numerous dimensions and discontinuous functions, making the model parameter selection difficult. Based on the capillary bundle theory and the truncated Gaussian distribution model, a model for characterizing the multi-peak distribution structure of cores is developed in this study. The model's accuracy is verified using the tested NMR experimental data of shale bimodal distribution and the cited coal trimodal distribution. This study further analyzes the influence of tortuosity and tortuosity fractal dimensions on this model. The results show that tortuosity and tortuosity fractal dimensions are conducive to improving the accuracy of the multi-peak pore structure model. The structure model, which can characterize the multi-scale and multi-peak distribution characteristics of shale pore diameter, provides a new concept for describing the pore structure of porous media.

随着我国煤炭资源的不断开采和石油天然气管道设施的大规模兴建,油气管道穿越煤矿采空区的情况愈发难以避免,开发了一种快速估算方法用以评估煤矿采空区上覆油气管道的风险状态以及管道规划阶段难以避让采空区时的路由方案比选.主要介绍了该快速评估方法的简要开发过程,包括开发该方法的意义,开发路线和实现过程.在典型工况分析结果的基础上,总结了不同管径、不同空间相对关系、不同开采厚度等因素对穿越采空区管道应变状态的影响规律,有利于从宏观上把握和利用采空区上覆管道的受力规律.最后为了便于读者理解,提供了一个快速评估的算例.

Due to its abundance, biomass is widely used in many engineering applications such as gasification process. Using biomass as a raw material for H-2-rich syngas production can not only reduce greenhouse gas emissions but also promote renewable energy utilization. In this study, a multi-stage model for H-2 rich syngas production from biomass gasification was developed and studied using Aspen Plus simulator. The model is divided into four sub-models including drying sub-model, devolatilization sub-model, tar cracking sub model and gasification sub model. Performance of biomass gasifier was evaluated by predicting the gas yield, lower heating value of produced syngas, carbon conversion efficiency and cold gas efficiency. The maximum H-2 content of 14.9 vol% was achived when S/B and reaction temperature were 1.0 and 1123 K, respectively. The highest CCE of 67.8 % and CGE of 37.9 % were also achieved at 1123 K. An increase in S/B from 0 to 0.5 led to a lower tar yield, which was from 133.557 g/Nm(3) to 127.193 g/Nm(3), and then leveled off as loading increased further from 0.5 to 1.0. The results also showed that during high S/B conditions, the gas-phase chemistry is dominated by water-gas shift (WGS) and Boudouard reactions. (C) 2021 Elsevier Ltd. All rights reserved.

Liquid loading has always been a production problem in the middle and late production of gas wells. Severe loading will even lead to the shutdown of gas wells. In actual production, critical liquid-carrying velocity is often used to judge the loading of gas wells. Most conventional calculation models are modified vertical pipe models for the critical liquid-carrying gas velocity of an inclined pipe. They are established based on liquid film inversion without considering the characteristics of liquid film delamination slippage. In this study, the elliptical distribution model of the liquid film of the inclined pipe is first established. Then the cross-sectional velocity distribution model is coupled to solve the cross-sectional flow rate integrally. When the cross-sectional liquid flow rate is 0, the gas velocity is the critical liquid carrying velocity. Model calculations reveal that the critical liquid-carrying velocity is the largest when the inclination angle is 50°, consistent with experimental data. Using the data of production wells in the Changning block, Sichuan, China, to analyze well loading, the accuracy between the prediction results of loading in this study and field production judgment reached 93.75%, which is 25% higher than that of the Belfroid model. The model in this study accounts for the delamination slippage of the liquid film for the first time, and the calculated critical liquid carrying velocity can better reflect the flow state of gas-liquid two-phase flow in inclined pipe, which is beneficial for researchers to accurately evaluate and understand the production status of gas wells.

Air and air-steam co-gasification of switchgrass (SG) and municipal solid waste (MSW) was simulated using Aspen Plus software. The proposed model is composed of four main parts, i.e. dryer, pyrolyzer, tar combustor and char gasifier. To validate the model, the simulated results were compared with the experimental data in terms of gas composition. The effect of co-gasification ratio (CGR) and steam/feed ratio (S/F) on gas composition, the product yield and gasification performance was studied. Results showed that maximum lower heating values (LHV) of 5.11 MJ/Nm(3), H-2 content of 13.66 vol%, dry gas yield of 1.39 Nm(3)/kg, carbon conversion efficiency (CCE) of 48.9%, and cold gas efficiency (CGE) of 39.92% were obtained for air-steam gasification of MSW and SG at the temperature of 800 degrees C, CGR of 40% and S/F of 1.2. When S/F increased from 0.8 to 1.2, the tar yield slightly decreased from 16.08 to 15.41 g/Nm(3). With increasing CGR from 0% to 40%, CGE initially increased from 28.81% to 29.25% and then decreased to 27.11%. Unlike CGE, CCE and dry gas yield continuously decreased from 42.97% to 39.28% and 1.22 Nm(3)/kg to 1.16 Nm(3)/kg with increasing CGR from 0% to 40%, respectively. (c) 2020 Elsevier Ltd. All rights reserved.

We propose and analyze two locking-free three-field virtual element methods for Biot’s consolidation model in poroelasticity. One is a high-order scheme, and the other is a low-order scheme. For time discretization, we use the backward Euler scheme. The proposed methods are well-posed, and optimal error estimates of all the unknowns are obtained for fully discrete solutions. The generic constants in the estimates are uniformly bounded as the Lamé coefficient λ tends to infinity, and as the constrained specific storage coefficient is arbitrarily small. Therefore the methods are free of both Poisson locking and pressure oscillations. Numerical results illustrate the good performance of the methods and confirm our theoretical predictions.

In this paper, we study the state estimation of compressible single phase flow in compressible porous media. The initial pressure distribution is estimated according to discrete adjoint approach based on the collected well pressure data. The first-order Tykhonov regularization method is used to obtain reasonable estimation. By analyzing the optimality condition of estimation problem, the discrete adjoint state equation and discrete adjoint gradient are derived based on the numerical scheme of the continuous equations. A quasi-Newton numerical optimization method related to adjoint gradient is proposed to solve the estimation problem. The estimation results with different regularization coefficients are compared and analyzed by numerical experiments. The deviation between the estimated pressure obtained without regularization and the real pressure is large. Estimation result with smaller deviation and higher smoothness can be obtained through appropriate regularization coefficient. When the observation error is large, the observed values generated by the estimated pressure fit well with the real pressure.

This article has been retracted. Please see the Retraction Notice for more detail: https://doi.org/10.1186/s13661-021-01502-z

This article has been retracted. Please see the Retraction Notice for more detail: https://doi.org/10.1186/s13661-021-01502-z

This work proposes a novel Hausdorff fractional NGMC(p,n) grey prediction model based on the NGMC(1,n) model. The new grey model combines the Hausdorff fractional accumulation operator and the Grunwald-Letnikov fractional derivative with more freedom and simpler in calculations; the time response function and recurrence expressions of the new model are deduced by using forward difference; the recurrence relation of the binomial in the discrete solution to avoid calculating the Gamma function and simplifies the calculation; the Grey Wolf Optimizer (GWO) is introduced to optimize parameters of the new model for improving adaptability. To verify the efficiency of the new model, nine existing grey models are used to predict the total renewable energy production, the energy conversion efficiency and the total electricity production of China. The experimental results show that the fitting accuracy and prediction accuracy of the new model are better than those of the other nine existing grey models. (C) 2021 Elsevier Inc. All rights reserved.

On the basis of momentum conservation and mass conservation theory, this paper proposes mathematical model to investigate recovered water flow and contaminant diffusion in the wellbore of shale gas horizontal wells. Two significant improvements are made to conventional models. One is that the quality and velocity flow of each cluster are considered as dynamic parameters in equation of flow, and another one is that source terms and reaction terms are considered as dynamic parameters in equation of contaminant diffusion. The validity of the model of recovered water flow and contaminants diffusion is verified by comparing the predicted results with the actual production data and the experimental data in the literature. Then main factors affecting the concentration of contaminants in horizontal wells are studied systematically. It can be shown that the concentration of contaminants at wellhead increases linearly with the linear increase of the initial concentration, boundary concentration and the source term in the whole time period. The concentration of contaminants increases nonlinearly with the linear increase of the length of horizontal wellbore and flow-back average velocity of recovered water in different time periods. The research of this paper provides guidance for the control of recovered water.

苏里格气田采用的“K344型封隔器+喷砂滑套”分层压裂技术,由于整个管柱压后不能实现全通径,影响了后续排液采气、冲砂、测试、监测产液剖面,且无法进行二次改造作业.采用可溶金属材料,设计了直井全通径分层压裂工艺管柱.介绍了直井全通径分层压裂工艺管柱及关键工具.研制了新型喷砂滑套、滑套密封器和节流底阀.室内试验和现场试验结果表明,直井全通径分层压裂工艺管柱中关键工具的溶解时间可控,初始溶解时间大于72 h,压裂后工具内的可溶部分溶解时间小于7d,不可溶部分脱离可溶部分的束缚下行掉落到井底,整个管柱全通径可达Φ57 mm,能够满足一趟管柱分7层压裂施工及后续作业的要求.为直井分层压裂实现管柱全通径提供了新的技术手段.

为了解决多因素影响下油田措施增产预测问题,通过研究分数阶理论、微分模拟理论与智能优化理论建立了参数优化的分数阶微分模拟预测模型.模型克服了措施数据的非线性性、多因素性与适用性不强的缺陷,综合考虑了不同措施对应不同因素下增产效果的预测.通过与其他方法对比表明,新模型预测效果优于其他方法.可见参数优化的分数阶微分模拟预测模型可较好地应用于油田措施增产预测.

针对苏里格气田中应用K344封隔器+滑套分层压裂技术时压后油管不能实现全通径,影响后续作业的问题,研制了新型气田压后油管全通径关键工具.关键工具包括喷砂滑套、滑套密封器和节流底阀,介绍了关键工具的结构和原理.现场应用表明,气田压后油管全通径关键工具使溶解时间可控,压后油管全通径可达57 mm,为后续排液采气、冲砂、测试、监测产液剖面和二次改造作业提供了全通径通道,具有较高的实用价值.