ABSTRACT: The tight sandstone reservoirs present a viable option for geological CO2 storage. The stability and safety of the reservoir rock are fundamental for long-term CO2 storage. However, the injection may lead to interactions between H2O, CO2, and rock, potentially impacting the mineral composition and physical properties of the reservoir. This ultimately leads to a decrease in the mechanical properties of the rock and disrupts the stability of the reservoir in high-pressure environments. In this study, rock mechanics experiments, nuclear magnetic resonance (NMR) experiments, and scanning electron microscopy (SEM) experiments were carried out to investigate the changes in mechanical properties, pore size, and microstructure of cores with different mineral compositions treated with aqueous carbonate solution under different confining pressures, in order to analyze the effects of the dynamic CO2 storage process on reservoir stability. The results show that the presence of CO2 under confining pressure leads to a decrease in rock strength. Carbonic acid solution can effectively dissolve feldspars and clay minerals in the rock composition, causing changes in pore structure and leading to a decrease in rock strength. The study aims to provide insights and recommendations for developing oil and gas extraction and carbon sequestration. 1. INTRODUCTION Carbon dioxide geological storage technology is one of the effective ways to mitigate the global warming trend, and its basic principle is to inject captured carbon dioxide into deep underground rock pores for long-term isolation and fixation (Chen et al., 2023; Farquhar et al., 2015). Among the many potential storage media, tight sandstone reservoirs have received great attention from scientists and industry for their complex pore structure and high storage capacity (Bachu et al., 1994; Michael et al., 2009). However, CO2 injection affects the porosity, permeability, and mechanical properties of reservoirs, which may cause reservoir damage and reduced storage efficiency (Yu et al., 2012). For example, CO2 reacts chemically with minerals in the rock, which may lead to dissolution or precipitation of minerals, and thus change the physical structure of the rock (Fischer et al., 2010). The physical structure of the rock may be altered. Therefore, the mechanical response of rocks during CO2 injection must be thoroughly studied to ensure the safety and efficiency of the storage process. In recent years, in the field of CO2 geological storage research, scholars have carried out a large number of experimental and simulation studies, aiming to explore the mechanism of CO2 interaction with reservoir rocks and trying to predict and optimize the reservoir performance (Vafaie et al., 2023). The CO2 has different dissolution capacities for different minerals, leading to changes in the microstructure and mechanical properties of mineral surfaces, which indirectly leads to the decline of rock mechanical properties, thus affecting the production of unconventional oil and gas and reservoir stability (Vogt et al., 2014; Zhang et al., 2020; Zhang et al., 2022). Among various minerals, carbonate minerals (e.g., calcite and dolomite) have the highest solubility and the fastest reaction rate, while silicate minerals such as feldspar and quartz have lower solubility and slower reaction rate (Memon et al., 2022; Ranjith et al., 2019; Xing et al., 2019). Under the combined effect of CO2, the compressive strength and modulus of elasticity of the rock are significantly reduced (Huang et al., 2020; Rathnaweera et al., 2015; Zhou et al., 2024). The geological sequestration of carbon dioxide is a dynamic process, with the continuous injection of fluids, the formation pressure gradually increases. In fractured and low-permeability formations, the physical properties of rocks are affected by the increase in pore pressure, and their physical properties change significantly, which affects reservoir capacity (Dávila et al., 2017; Pavan & Govindarajan, 2023; Vialle & Vanorio, 2011). Zhao et al. carried out CO2 in brine solution saturated dense sandstone reservoir core samples for oil repulsion and explained the increase in porosity and permeability due to the increase in pore pressure (Zhao et al., 2021). Liteanu et al. investigated the effect of supercritical CO2 on rock mechanics, where carbonic acid solution led to stress corrosion fracturing and strength reduction of rocks (Liteanu et al., 2013).

Tight sandstone reservoirs have huge potential for geological sequestration of CO2. In the process of CO2 injection, the stability and safety of the reservoir pore structure and physical properties are the basis for CO2 sequestration. However, due to the interaction between CO2-water-rocks, the mineral composition and physical properties of the reservoir can be affected, leading to changes in the pore structure of the rocks and destabilizing the reservoir under high-pressure environments. The changes in pore distribution, rock surface microstructure, and rock mechanical properties of cores with different mineral compositions treated with carbonated water under different confining pressures were investigated through nuclear magnetic resonance (NMR), scanning electron microscopy (SEM), and rock mechanics experiments. The effects of the dynamic CO2 sequestration process on the pore structure of the tight reservoir and the physical properties of the rocks were analyzed. The results demonstrate that following CO2 injection, the pore volume of the rock decreased due to the generation of debris by chemical dissolution and the plastic deformation of the pore structure was more significant under high pressure, resulting in pore closure and a reduction in pore space. Concurrently, the dissolution of gap-fillers, such as chlorite and kaolinite, between mineral grains in the pore space occurred, and the formation of microfractures. The formation of microfractures decreased the overall stability of the rock. Additionally, feldspar is easily dissolved chemically under CO2-water conditions, and this process is more pronounced in rocks with a higher feldspar content. The compressive strength and elastic modulus of these rocks are significantly reduced. Consequently, in the context of CO2 geological sequestration, it is recommended that rocks with a high quartz content, a low feldspar content, a moderate porosity, and stable physicochemical properties be selected as injection targets. Furthermore, a phased injection strategy should be employed to accommodate the structural changes in the rocks due to pressure and to enhance the injection efficiency, thereby optimizing the long-term geological sequestration of CO2 and its safety.

Currently, research surrounding low-salinity water flooding predominantly focuses on medium- to high-permeability sandstone reservoirs. Nevertheless, further investigation is necessary to implement this technique with regard to tight sandstone reservoirs. The present study comprises a series of experiments conducted on the crude oil and core of the Ordos Chang 6 reservoir to investigate the influence of ionic composition on low-salinity water flooding in tight oil reservoirs. The change in wettability on the rock surface was analyzed by using the contact angle experiment. The change in recovery rate was analyzed using a core displacement experiment. The reaction between rock fluids was analyzed using an ion chromatography experiment. Additionally, a nuclear magnetic resonance (NMR) experiment was used to analyze the mobilization law of crude oil and the change in wettability on the scale of the rock core. This led to a comprehensive discussion of the law and mechanism of enhancing the recovery rate via low-salinity water flooding from various perspectives. Experiments show that low-salinity water flooding is an effective technique for enhancing recovery in tight sandstone reservoirs. Altering the ionic composition of injected water can improve the water wettability of the rock surface and enhance recovery. Decreasing the mass concentration of Ca2+ or increasing the mass concentration of SO4 (2- )can prompt the ion-exchange reaction on the rock surface and detachment of polar components from the surface. Consequently, the wettability of the rock surface strengthens, augmenting the recovery process. Nuclear magnetic resonance experiments evidence that low-salinity water injection, with ion adjustment, significantly alters the interactions between the rock and fluid in tight sandstone reservoirs. As a result, the T(2 )signal amplitude decreases significantly, residual oil saturation reduces considerably, and the hydrophilic nature of the rock surface increases.

A new fully coupled numerical model is presented to analyze artificial fracture morphology and artificial fracture propagation during synchronous fracturing. The interaction mechanism between natural and artificial fractures is also considered in this new model. The new numerical solution, based on the boundary element method (BEM) and the finite difference method, is used to solve the problem of coupled rock deformation, fluid interference, stress interference, interface slipping, and opening and to investigate the effect of natural fractures and interference between fractures on fracture morphology during synchronous fracturing. An analysis of factors of influence showed that synchronous fracturing can be used to control the fracture trajectory and construct an effective enhanced geothermal system (EGS). Artificial fractures of two adjacent wells attract each other during synchronous fracturing, and eventually, the two fractures become connected, and the two wells become connected. The choice of well location also has an important influence on the successful establishment of an EGS. To establish an effective EGS successfully, the fracture spacing should preferably be no more than 20 m, and the well spacing should preferably be greater than 400 m. An EGS is easier to construct in a hot dry rock reservoir with a high natural fracture density and small natural fracture angles (preferably less than 30o).

To study the differences in self-supporting conductivity among fractures obtained by hydraulic fracturing, CO2 fracturing, and Sc-CO2 (Supercritical carbon dioxide) fracturing, laboratory large-scale fracturing experiments and conductivity tests were carried out. To simulate the reservoir conditions as realistically as possible, the rock slabs used in the conductivity tests were all cut from the samples after fracturing experiments. Before a conductivity test, the fracture surfaces of each rock slab were digitized by laser scanning and 3D reconstruction technology. The JRC of each rock slab is calculated by using the point cloud data. Then, the self-supporting conductivity of each rock slab was tested under different conditions, and a relationship between the JRC, closure stress and sliding displacement and the self-supporting conductivity of fractures obtained by different fracturing techniques was analyzed. The experimental results show that: The JRC of the fractures obtained by Sc-CO2 fracturing is higher than that of CO2 fracturing. Moreover, the JRC of fractures in hydraulic fracturing is the lowest among the three fracturing technologies. The self-supporting conductivity of the fractures has a positive correlation with their JRC value. Compared to hydraulic fracturing and CO2 fracturing, the fractures obtained by Sc-CO2 fracturing have significant advantages in self-supporting conductivity regardless of slip displacement and closure stress.

Supercritical carbon dioxide fracturing can effectively relieve the environmental pressure caused by in-situ production of oil shale. In order to study the process of fracture propagation during supercritical carbon dioxide fracturing, a fracture propagation model of supercritical carbon dioxide fracturing is established in this paper, and an unsteady temperature field model is introduced. Based on the discrete fracture model, the fluid temperature field in one-dimensional fracture is coupled with the temperature field of two-dimensional reservoir rock. The new model also takes into account the real-time variation of carbon dioxide physical parameters, which are calculated by Span-Wagner and Vesovic equations. Based on this model, the influencing factors of fracture propagation in supercritical carbon dioxide fracturing are analyzed. The results show that the leak-off coefficient has an obvious effect on fracture propagation, so an additive needs to be developed to reduce the leak-off. Since carbon dioxide is a compressible fluid, the reservoir temperature and the original in-situ stress also have a significant impact on the fracture propagation. The temperature of carbon dioxide at the bottom of the well has no significant effect on fracture propagation, because carbon dioxide will quickly reach reservoir temperature when it enters the formation. Comprehensive considering the fracture length, width, filtration, and potential effect on proppant transport during supercritical carbon dioxide fracturing, the injection rate should be as high as possible.

中国煤层气勘探开发面临资源探明率低、单井平均产气量低等挑战,建立与中国煤层气地质特点相适应的勘探开发技术体系,是解决这些问题的必由之路,其中储层改造技术是该技术体系的关键.为此,在系统梳理中国煤层气地面井开采储层改造技术现状的基础上,剖析了煤层气开发面临的科学问题与技术挑战,并对储层改造技术的发展方向进行了展望.研究结果表明:①国内煤层气产量规模尚未达到国家需要,在能源安全与低碳发展背景下,突破当前储层改造技术瓶颈是促进煤层气大规模增产的关键;②目前,中国煤层气地面井开采储层改造技术的代表性技术为水力压裂、电脉冲增透、微波加热3大类,下一步需持续攻关液压致裂、电脉冲致裂、微波致裂等不同破岩方式下的煤岩裂缝扩展规律;③需攻关压裂液、酸液、微生物、CO2、N2等不同外来介质对煤岩的作用机理,以及储层改造后煤层气传质与产出机理等科学问题.结论认为,单一技术进步基础上的融合发展是煤层气地面开采储层改造技术的发展趋势,其中研发适合不同煤层特点的储层改造技术"组合拳"是实现煤层气开发的关键.

基于伊拉克Missan油田Mishrif组孔隙型碳酸盐岩油藏开展长岩心驱替试验、润湿角测定和界面张力测定试验,研究碳酸盐岩油藏智能水驱作用规律与机制.结果表明:碳酸盐岩油藏智能水驱中岩石表面润湿性改善与油水相互作用改变协同作用提高采收率,其中润湿性改善影响较大.关键离子类型及质量浓度对润湿性及界面张力影响明显.其中Mg2+和Ca2+促进润湿性和界面张力的改变,随着其质量浓度增加,润湿角和界面张力均先减小后增大,存在最优质量浓度使得润湿角和界面张力最小;Mg2+作用效果强于Ca2+.SO42-促进关键阳离子对润湿性的影响,抑制其对界面张力的影响,质量浓度越高作用效果越明显.碳酸盐岩油藏智能水驱中SO42-优先吸附于方解石表面,促进关键阳离子发生多离子交换反应,造成润湿性的转变;随着溶液中离子类型及质量浓度的改变,吸附于油水界面的极性原油分子发生盐溶和盐析作用,影响油水相互作用.

Low salinity waterflooding of carbonate reservoirs has attracted wide attention and many mechanisms have been proposed. However, the dynamic behaviors and mechanisms of the fluid-fluid interaction in low salinity waterflooding have not yet been thoroughly classified. Regarding this, core flooding, contact angle & zeta potential, interfacial tension & interfacial dilatational rheology, total organic carbon, and cryogenic-scanning electron microscopy (cryo-SEM) experiments were combined in this study to investigate the role of the fluid-fluid interaction in low salinity waterflooding and reveal its in-depth mechanism. Core flooding & contact angle & zeta potential experiments results showed that the rock-fluid and fluid-fluid interactions act synergistically to enhance oil recovery. Thereof, as ionic strength decreases, the contribution of the fluid-fluid interaction for additional recovery first increases to the maximum 67.04 % in 20-times diluted formation waterflooding and then decreases to 29.99 % in 40-times diluted formation waterflooding. Moreover, Mg2+ and SO42- as the potential determining ions both showed positive effects on the fluid-fluid interaction in low salinity waterflooding. As Mg2+ concentration increases, the contribution of the fluid-fluid interaction for additional recovery increases to 82.63 % and then decreases. As SO42- concentration increases, the contribution of the fluid-fluid interaction continuously increases and reaches 84.56 %. Interfacial tension and interfacial dilatational rheology results illustrated that the interfacial viscoelasticity enhancement is the important mechanism of the fluid-fluid interaction in low salinity waterflooding which could suppress the snap-off and stabilize the crude oil. Moreover, the total organic carbon and cryo-SEM results showed the oil-in-water emulsions with strong interfacial viscoelasticity are stably dispersed in low saline water, which could block the pores and throats and increase the sweep efficiency. In conclusion, the enhancement of interfacial viscoelasticity and the formation and existence of oil-in-water emulsion are the two important mechanisms of the fluid-fluid interaction in low salinity waterflooding. Herein, these two mechanisms both first enhance and then weaken as ionic strength decreases; enhance and then weaken as Mg2+ concentration increases, continuously enhance as SO42- concentration increases.

为加强对超临界CO2压裂裂缝特征的认识,指导超临界CO2压裂技术的发展,总结了前人对超临界CO2起裂、扩展和导流能力特征的研究.结果表明:超临界CO2压裂裂缝起裂压力比液态和清水压裂低,其主导原因是超临界CO2的低黏度和高扩散性使孔隙压力增大起裂压力降低;超临界CO2压裂裂缝扩展影响因素复杂,主要受CO2相变、岩石弱面结构等因素主导,但具体机理尚不明确,还需研发实验装置和建立裂缝扩展三维模型进行更微观细致的研究;超临界CO2压裂裂缝比清水压裂裂缝的粗糙度和迂曲度更大、裂缝缝长更长,但缝宽小,裂缝的有效性不足;超临界CO2压裂可使天然裂缝和人工裂缝剪切错位,也可进入微裂缝孔隙,破坏岩石矿物胶结,导致岩石矿物脱落形成自支撑,自支撑裂缝提供了导流能力,但形成机理及维持方式还需进一步研究.该研究可为超临界CO2压裂裂缝特征研究提供参考.

目前低盐度水驱研究主要集中于中高渗透、高黏土质量浓度的砂岩油藏,是否适用于致密砂岩油藏有待于深入研究.基于这种情况,以鄂尔多斯盆地致密油藏岩心和原油为研究对象,利用岩心驱替实验、润湿角测定实验、界面张力以及界面扩张流变测定实验开展致密砂岩油藏低盐度水驱作用规律研究.实验结果表明:低盐度水驱适用于致密砂岩油藏,调整注入水离子组成改变岩石表面润湿性以及油水相互作用,即可实现采收率的提高;其中,降低Ca2+质量浓度或增加SO42-质量浓度可促进极性原油组分脱离岩石表面,增强岩石表面水湿性;与此同时,降低Ca2+质量浓度或增加SO42-质量浓度可促进极性原油组分在油水界面的吸附,降低界面张力并增强界面黏弹性;降低Ca2+质量浓度或增加SO42-质量浓度对提高采收率有较好效果.研究成果为低盐度水驱在致密砂岩油藏中的应用提供了理论参考.

Heat extraction from medium-deep thermal energy has become an important research direction in the current geothermal development. In this study, a comprehensive performance evaluation model of a coaxial heat exchanger for the development of medium-deep geothermal resources was established, which combined the formation, wellbore, and heat-carrier fluid flows, as well as the heat transfer and physical property changes. This model was then used to compare and analyze the performances of different heat-carrier fluids and the effects of different well depths and geothermal gradients. Different heat-carrier fluids had significant effects on the performance of the coaxial heat exchanger. Among these, carbon dioxide was the best heat-carrier fluid, with the largest heat output and coefficient of performance. When carbon dioxide was used as the heat-carrier fluid and the well depth structure was determined, there was an injection parameter that produced the optimal performance in the heat exchanger. When coaxial heat exchangers are used to develop medium-deep geothermal energy, the influences of friction and the Joule–Thomson effect cannot be ignored. In formations with large geothermal gradients or wells with large depths, larger tubing and casings should be selected to reduce the negative effects of friction and the Joule–Thomson effect.

针对当前水驱中的油水相互作用的研究较少且已有结论存在争议,主要体现在关键离子对油水相互作用影响规律尚未统一.将岩心驱替实验和界面张力测定实验相结合来研究智能水驱中油水作用规律与机理.实验结果表明:油水相互作用在智能水驱中发挥着重要作用,调整注入水的离子组成可以有效影响采收率.Mg2+和Ca2+能够有效提高岩心驱替效率,Mg2+作用效果强于Ca2+,二者存在最优浓度.SO42-对提高采收率无积极作用.界面张力测定实验结果:溶液中不同离子对油水界面特征的影响存在较大差异,作用强度依次为Mg2+>Ca2+>Na+.随着溶液中Na+,Ca2+和Mg2+质量浓度的增加,油水界面张力先减小后增大、界面弛豫时间先缩短后延长,存在促进界面张力最低、界面弛豫时间最短的最优浓度;SO42-能有效抑制Na+,Mg2+和Ca2+对油水界面特征的影响,提高油水界面张力达到最低的最优离子浓度、延长油水界面体系达到平衡的时间.

为探讨地层水中常见电解质类型对原油乳状液稳定性的影响,多角度分析了不同电解质(Mg2+、Ca2+、Na+)作用下乳状液的变化规律与机理.基于多重光散射实验研究乳状液的光谱变化特征和失稳规律,通过浓度和粒径实验分析乳状液失稳过程中液滴的迁移和生长变化特征,并以Zeta电位实验分析了乳状液液滴之间聚结的原因,最后结合DLVO理论探讨了乳状液失稳机理.研究发现:电解质促进乳状液由W/O/W型转相为O/W型乳状液而失稳.添加电解质后原油乳状液浓度下降加快,粒径增加,油滴之间絮凝和聚结作用增强.Mg2+、Ca2+、Na+对乳状液的稳定性影响强度依次减弱,表现为对浓度、粒径和Zeta电位的作用效果依次降低.阳离子在原油液滴的表面吸附使液滴表面电荷密度和水化层厚度降低,液滴之间的范德华力增加,静电斥力减小,导致液滴相互碰撞和聚结的几率增加,乳状液失稳.

Tight oil reservoir plays an increasingly important role in the world energy system, but its recovery is always so low. Hence, a more effective enhanced oil recovery (EOR) technology is urgently needed. Meanwhile, greenhouse effect is more and more serious, a more effective carbon capture and sequestration (CCS) method is also badly needed. Direct current voltage assisted carbonated water-flooding is a new technology that combines direct current voltage with carbonated water-flooding to enhance oil recovery and CO2 sequestration efficiency, simultaneously. Experimental studies were conducted from macroscopic-scale to microscopic-scale to study the performance and mechanism of direct current voltage assisted carbonated water-flooding. Firstly, core flood experiments were implemented to study the effect of direct current voltage assisted carbonated water on oil recovery and CO2 sequestration efficiency. Secondly, contact angle and interfacial tension/dilatational rheology were measured to analyze the effect of direct current voltage assisted carbonated water on crude oil-water-rock interaction. Thirdly, total organic carbon (TOC), gas chromatography (GC), and electrospray ionization-fourier transform ion cyclotron resonance-mass spectrometry (ESI FT ICR-MS) were used to investigate the organic composition change of produced effluents and crude oil in direct current voltage assisted carbonated water treatment. Through direct current voltage assisted carbonated water-flooding experiments, the following results can be obtained. Firstly, direct current voltage assisted carbonated waterflooding showed greater EOR capacity and CO2 sequestration efficiency than individual carbonated water and direct current voltage treatment. With the increase of direct current voltage, oil recovery increases to 38.67% at 1.6V/cm which much higher than 29.07% of carbonated water-flooding and then decreases, meanwhile, CO2 output decreases to only 35.5% at 1.6V/cm which much lower than 45.6% of carbonated water-flooding and then increases. Secondly, in direct current voltage assisted carbonated water-flooding, the wettability alteration is mainly caused by carbonated water and the effect of direct current can be neglected. While both carbonated water and direct current have evident influence on interfacial properties. Herein, with direct current voltage increasing, the interfacial tension firstly decreases and then increases, the interfacial viscoelasticity initially strengthens and then weakens. Thirdly, GC results indicated that crude oil cracking into lighter components occurs during direct current voltage assisted carbonated water-flooding, with the short-chain organic components increasing and the long-chain components decreasing. Meanwhile, TOC and ESI FT ICR-MS results illustrated that CO2 electroreduction do occur in direct current voltage assisted carbonated water-flooding with the dissolved organic molecules increases and the emergence of formic acid. Conclusively, the synergy of CO2 electrochemical reduction into formic acid in aqueous solution and the long-chain molecules electrostimulation pyrolysis into short ones in crude oil mutually resulted in the enhancement of crude oil-carbonated water interaction. This paper proposed a new EOR & CCS technology-direct current voltage assisted carbonated water-flooding. It showed great research and application potential on tight oil development and greenhouse gas control. More work needs to be done to further explore its mechanism. This paper constructs a multiscale & interdisciplinary research system to study the multidisciplinary (EOR&CCS) problem. Specifically, a series connected physical (Core displacement, Contact angle, and Interfacial tension/rheology measurements) and chemistry (TOC, GS, and ESI FT ICR-MS) experiments are combined to explore its regularity and several physics (Atomic physics) and chemistry (Electrochemistry/Inorganic Chemistry) theories are applied to explain its mechanisms.

水驱过程中油水岩反应不断改变导致产出原油的组分不断变化,深入探究其规律及机理有助于实现油藏的精准高效开发.本文将实验与分子动力学模拟相结合研究水驱过程中原油组分的变化规律及背后的油—水—岩作用机理.首先,长岩心驱替实验与族组分分析、傅里叶变换红外线光谱实验相结合系统地研究水驱过程中原油组分的变化规律.而后,分子动力学模拟从分子尺度探究油—水—岩作用机理.实验发现:无水采收期,产出原油组分含量变化较小.见水之后,饱和烃含量下降与—CH3和—CH2—吸收峰明显降低相验证,芳香烃含量上升与—CH—离平面振动和苯环对称伸缩振动增强相统一,胶质和沥青质含量小幅度上升对应于含氧/氮官能团吸收峰微弱增加.模拟发现:原油组分在方解石表面形成饱和烃—芳香烃—胶质—沥青质的吸附序列;水驱过程中水分子先后与饱和烃、芳香烃以及游离态胶质、沥青质接触并将其先后驱离方解石表面.最终,吸附态胶质、沥青质稳定存在,一端锚定在方解石表面,一端牵引着少量未被驱离的芳香烃和饱和烃.原油组分极性越强与方解石表面相互作用越强,静电力贡献越大、范德华力影响越小.原油组分极性越相近,分子间相互作用越强,含芳香族化合物之间发育π键相互作用,饱和烃通过范德华力与其他组分相互作用.原油组分之间相互作用使得原油组分在方解石表面表现为整体性的运动特征,同时造成非极性原油组分的滞留.本研究将实验与分子动力学研究相结合从分子尺度解释水驱过程中原油组分变化规律及背后的油—水—岩作用机理,为靶向提高采收率技术的应用提供理论支撑.

Crude oil-aqueous solution interactions play an important role in low-salinity waterflooding, but their effects and mechanisms have not been well clarified. Core flooding experiments were first conducted to analyze the effects of crude oil-aqueous solution interactions on enhanced oil recovery (EOR). Then, interfacial tension (IFT) and interfacial dilatational rheology (IDR), total organic carbon (TOC), and zeta-potential measurements were combined to investigate the mechanisms of crude oil-aqueous solution interactions in low-salinity waterflooding. Core flooding results showed that crude oil-aqueous solution interactions are important in low-salinity waterflooding and that adjusting the ionic composition of the aqueous solution could affect EOR. Herein, Mg2+ and Ca2+ both had positive effects on EOR, while SO42- showed no positive effect. The IFT and IDR, TOC, and.-potential results indicated that the ionic composition of aqueous solutions has a great influence on crude oil-aqueous solution interactions. Thereof, Mg2+, Ca2+, and Na+ preferentially interact with acidic polar molecules and enhance crude oil-aqueous solution interactions, and the intensity is Mg2+ > Ca2+ > Na+. SO42- interacts with cations and acidic polar molecules simultaneously, consequently reducing the effects of cations on crude oil-aqueous solution interactions in varying degrees. Therefore, the positive effects of Ca2+ and Mg2+ exceed the negative influence of SO42- in CaSO4 and MgSO4, while the negative impact of SO42- outweighs the positive effect of Na+ in Na2SO4.

Abstract Supercritical carbon dioxide fracturing is an environmentally friendly anhydrous method. To study the propagation process during supercritical carbon dioxide fracturing, a full three‐dimensional model, coupled rock deformation, fluid transport, heat conduction, dynamic changes of carbon dioxide physical parameters, to investigate the process of fracture propagation during supercritical carbon dioxide fracturing, is established by the three‐dimensional boundary element method, the finite volume method, and finite difference method. And to solve the multiple physics coupling problems, a fully implicit solution and Newton‐Raphson iteration method are used. On the basis of this model established in this paper, the influential factors of supercritical carbon dioxide fracturing are analyzed. The results show that both of the reservoir temperature and the original in situ stress are important for carbon dioxide fracturing; The higher the reservoir temperature and the lower the initial in situ stress is, the longer and wider the fracture will be. The temperature of carbon dioxide at bottom is of no significance to the fracture length, fracture width, and the bottom hole pressure. A growing injection rate will lead to the increase of the fracture length and fracture width. This study would provide a reference for the fluid phase control of supercritical carbon dioxide fracturing technology.

Supercritical carbon dioxide fracturing not only enhances fossil hydrogen production better than hydraulic fracturing, but also alleviates water consumption and storages some carbon dioxide in reservoirs. In this study, a numerical simulation model for calculating the temperature and pressure within a fracture during supercritical carbon dioxide fracturing was established based on rock mechanics, fluid mechanics, thermodynamics, and heat transfer. Moreover, the effects of impact of in-situ stress of reservoir, reservoir temperature, carbon dioxide temperature at the bottom of the well and injection rate on temperature and pressure in the fracture are analyzed based on this new model. The results show that the temperature and pressure of carbon dioxide in the fracture are constantly changing during the fracturing, due to the propagation of the fracture, which makes the temperature and pressure in the fracture unable to reach a steady state. The effect of supercritical carbon dioxide fracturing in reservoirs with higher temperature and lower in-situ stress is better, and higher injection temperatures and smaller injection rates should be chosen in order for carbon dioxide to quickly reach the supercritical state.

In this research, the thermal-hydro-mechanical-chemistry coupling process involved in acid fracturing is simulated using 2D displacement discontinuity method combined with the finite volume method. Temperature field models, acid flow models, and acid rock reaction models are also established based on material conservation and energy conservation criteria. And the new acid fracturing method is used to solve the problem of rock deformation, fluid interference, fracture opening, temperature, acid rock reaction, multiphase flow, and carbon dioxide characteristics coupling. Simulations of larger scale acid fracturing are carried out to analyze the influence of injection rate, initial acid concentration, acid viscosity and initial reservoir temperature, and acid temperature on the bottom of the well on optimizing acidizing design. The results show: the acid rock reaction and its reaction product have a significant influence on the fracture extension. And the coupled process and the influence of carbon dioxide are necessary to be considered when studying the acid fracturing process. For obtaining as long as possible effective penetration distance of the acid, a larger injection rate can be selected, a larger initials acid concentration, a lower acid viscosity and a lower acid temperature at the bottom of the well.