Ultra-low permeability high-pour-point reservoirs are characterized by high pour points, high viscosity, and high wax content. These "three-high" properties severely hinder fluid flow, result in low oil recovery efficiency, and lead to complex and heterogeneous residual oil distributions, posing significant challenges to enhancing recovery. To investigate the microscopic flow behavior of different displacement agents and their influence on residual oil distribution and occurrence patterns, this study employs a self-developed high-resolution microfluidic visualization system to conduct comparative experiments using three typical injectants: water, oxygen-reduced air, and CO2. By combining high-magnification metallographic microscopy with depth-of-field reconstruction techniques, multi-scale quasi-3D residual oil distribution images were obtained under various displacement conditions, enabling direct characterization of oil phase migration pathways, interfacial evolution processes, and residual oil occurrence states. Experimental results show that CO2 injection demonstrates the most favorable microscopic displacement performance. Its strong dissolution and swelling capacity, effective viscosity reduction, and ability to improve rock wettability significantly enhance oil desorption and mobilization. Oxygen-reduced air ranks second in effectiveness; its displacement efficiency is improved through a combined mechanism of gas expansion and low-temperature oxidation, which activates oil–rock interfaces and promotes oil phase movement. In contrast, waterflooding shows the lowest efficiency, with the displacement front constrained and residual oil primarily trapped in micropores and non-dominant flow channels, where it is discretely distributed and difficult to mobilize. Subsequent core-scale displacement experiments were conducted to verify the macroscopic cumulative effect of the observed microscopic mechanisms, confirming the intrinsic correlation between micro-scale displacement behavior and field-scale recovery performance. The study reveals the distinct displacement mechanisms of different injectants, clarifies the occurrence patterns of residual oil, and identifies key factors that control its distribution and mobilization. These findings provide experimental support and theoretical guidance for the selection of optimal displacement strategies and the design of injection parameters for the efficient development of high-pour-point reservoirs.

The Shunbei No. 4 fault zone in the Tarim Basin is the largest fault-controlled, strip-shaped, vertical, and ultra-thick fracture-cavity condensate gas reservoir in China. This gas reservoir is characterized by ultra-deep burial, ultra-high temperature and pressure, complex fracture-cavity structures, and intricate phase behavior of reservoir fluids, posing significant challenges to the selection and adjustment of scientific development strategies. To clarify the impact of reservoir architecture and supercritical complex fluid phase characteristics on the development technical policies of this gas reservoir, methods including fine geological characterization of fracture-cavity reservoirs and non-equilibrium phase behavior study of supercritical condensate gas were employed, combined with the production dynamics during gas reservoir exploitation, to analyze the controlling effect of reservoir-fluid coupling on development technical policies, clarify the pore-fracture-cavity development characteristics in fault-controlled reservoirs both in depth and along the long axis direction, and reveal the controlling effect of complex reservoir geological characteristics on the distribution of condensate oil and gas in accumulation and development units. The study indicated that under ultra-high temperature and pressure conditions, during the depletion production stage from initial pressure to dew point pressure, the recovery degree of condensate oil and gas could simultaneously reach 30%. By measuring the non-equilibrium gravitational settling relaxation phenomenon during the depletion stage from dew point pressure to maximum retrograde condensation pressure, it could be deduced that the relaxation time within the fault-controlled reservoir could reach 3 months. Additionally, the controlling effect of gravity segregation and phase evolution stratification of the gas-gas two-phase system during the gas injection process was explored, and the non-equilibrium diffusion time for gas injection was determined to exceed one year. It further clarified the different influencing mechanisms of fluid distribution differences in the northern, central, and southern sections of the gas reservoir on development strategies, as well as the effect of gas injection location selection on the effectiveness of gas injection displacement. Based on the above research findings, a three-stage development approach tailored to this type of gas reservoir is proposed, providing technical support for the formulation of development strategies for the Shunbei ultra-deep fault-controlled condensate gas reservoir, as well as serving as a reference for the efficient development of similar ultra-deep fault-controlled fracture-cavity condensate gas reservoirs.

Due to the fracture caverns in fractured-vuggy reservoirs, channeling frequently occurs during water injection or gas injection. The stability of the oil–water/oil–gas interface during water injection or gas injection in fractured-vuggy reservoirs significantly affects the displacement efficiency. However, there is a lack of in-depth understanding of the stability of the gas–water interface migration during water injection or gas injection in such reservoirs. In order to deal with this problem, this study combines indoor 3D visualization physical simulation experiment and fracture-cavity reservoir flow simulation. The law of interface transport and oil recovery in the process of injection of gas/water considering the degree of filling of fracture holes was studied and the influence of formation on crude oil viscosity, gas injection speed, inclination angle and other factors on the stability of the interface was compared. Results show that, under the influence of gravity differentiation, the oil–water interface of high-viscosity crude oil fluctuates obviously after water breakthrough, and the oil–water interface tends to be unstable, forming uneven oil cones. By reducing the gas drive speed, water invasion can be effectively inhibited to achieve a stable interface which accordingly improves the oil recovery.

CO2-enhanced gas recovery (EGR) has emerged as a promising method for improving hydrocarbon production and achieving carbon sequestration in offshore gas reservoirs. This study investigates the performance and influencing factors of CO2-based gas displacement using long core displacement experiments. Consolidated synthetic cores were prepared to replicate reservoir conditions, and experiments were conducted at formation pressure and temperature to evaluate the effects of permeability, injection pressure, CO2 concentration, and core length on gas recovery efficiency. The results reveal that (1) for a homogeneous porous medium, permeability and injection pressure have minimal correlation with recovery efficiency when sufficient gas is injected; (2) direct gas displacement after reservoir depletion outperforms pressure-boosting displacement methods; (3) higher CO2 concentrations delay gas breakthrough, enhance piston-like displacement behavior, and improve recovery efficiency; and (4) core length significantly affects recovery, with longer cores resulting in slower breakthroughs and more stable displacement. Cores of at least 1 m in length are essential for accurately simulating field conditions. For a CO2 injection with a pressure of 7 MPa and a temperature of 81 °C, when 0.87 PV of CO2 is injected, the current recovery can reach 87%, after which the displacement efficiency decreases sharply. The ultimate EGR can be as high as 50%. These findings provide valuable insights into optimizing CO2 injection strategies for enhanced gas recovery in offshore reservoirs, offering guidance for both experimental designs and practical applications in the field.

Deep and high-pressure carbonate gas condensate reservoirs develop a large number of cracks and holes, with strong interlayer heterogeneity and complex mechanisms. To clarify the fundamental reasons that affect the development efficiency of such condensate gas reservoirs, we take the typical fractured and vuggy carbonate rock reservoirs in China's S condensate gas field as the object of study, and conduct experiments such as X- ray computed tomography (X-CT) scanning, high- temperature and high- pressure stress- sensitivity testing, and long-core depletion development experiments. From multiple parameters and perspectives, we describe the microscopic changes in the storage and seepage spaces of fractures and vuggy cores, as well as the changing patterns of the underground condensate oil and gas production. According to the research results, the increase in effective stress leads to the contraction and closure of the fractured and vuggy spaces in the core, resulting in a decrease in their size. Under deep, high- pressure conditions, carbonate reservoirs exhibit strong stress sensitivity, and the permeability of the core drops significantly with the increase in the formation's effective stress. The coupling effect of stress sensitivity and retrograde condensation has different impacts on the development effect of different types of cores at different pressure stages. The vuggy cores experience greater changes in storage and seepage spaces, the overall permeability damage is strong, and the condensate oil recovery rate is ultimately lower than that of fractured cores. Therefore, it is of great significance to study the impact of stress sensitivity and retrograde condensation characteristics on the gas reservoir recovery rate. The research results can provide theoretical support for the efficient development of deep, fractured- vuggy carbonate condensate gas reservoirs.

In the middle and late stages of offshore carbon-rich gas reservoir development, insufficient reservoir energy poses significant challenges and difficulty in improving gas recovery. Injecting CO2 back into the reservoir is a promising development approach that can address both carbon emissions and enhanced gas recovery (EGR). During the CO2 injection process, the CO2–CH4 dispersion significantly impacts the recovery of CH4. To understand the mass transfer and dispersion laws of CO2 and high-carbon natural gas under current in situ reservoir conditions, this study conducted 1-m-long core experiments to investigate the effects of different gas compositions and permeabilities on gas recovery and diffusion laws in offshore reservoirs, taking into account the evolution of permeability in the porous medium. The experimental results indicate that the higher carbon concentration helps reduce mixing with formation gas, which consists of 70% methane, 25% nitrogen, and 5% carbon dioxide, resulting in a smaller diffusion coefficient. Under the conditions of an injection rate of 0.4 mL/min, a temperature of 81 °C, and a pressure of 7 MPa, the diffusion coefficient decreases by 27.5% as the carbon dioxide concentration increases from 70% to 90%, resulting in a 1.5% increase in recovery efficiency. As the permeability decreases, the viscous resistance of the fluid increases, leading to longer breakthrough times, and the reservoir fluid becomes more akin to piston displacement, reducing the degree of dispersion. The findings of this study provide guidance for optimizing gas injection strategies by reducing CO2 dispersion and further enhancing natural gas recovery.

在分析CO2驱最小混相压力影响因素及36组细管实验数据的基础上,运用灰色关联法计算了各因素对原油CO2驱最小混相压力影响的关联度,并利用MATLAB(矩阵实验室)软件回归拟合了关于油藏温度、C5+相对分子质量、挥发烃组分(N2+CH4)摩尔分数和中间烃组分(CO2+H2S+C2—C4)摩尔分数的原油CO2驱最小混相压力预测模型,拟合的相关系数达0.9009.并选用某油田3口井油样最小混相压力细管实验测试的数据进行检验,建立的新预测模型计算误差平均值为3.57％,能够用于指导油藏现场开发.

Based on the analysis of the factors influencing the minimum miscibility pressure in CO2 flooding and 36 groups of tubule experimental data, the correlation degree of each factor influencing the minimum miscibility pressure in CO2 flooding of crude oil is calculated by the grey correlation method. The prediction model of minimum miscible pressure in CO2 flooding for crude oil is fitted by the MATLAB （Matrix Laboratory） software, which is related to the reservoir temperature, relative molecular weight of C5+, volatile hydrocarbon component （N2+CH4） content and intermediate hydrocarbon component （CO2+H2S+C2—C4） content. The fitting correlation coefficient reaches 0.900 9. The data of the minimum miscible pressure test of three wells in an oilfield are used to verify the new prediction model. The average error of calculation is 3.57 %, which can be used to guide the field development of the reservoirs.

The main source of production in the middle and late stages of shale gas extraction is the adsorbed gas in shale, and the adsorbed gas in shale mainly comes from organic matter casein and clay minerals in shale; therefore, this paper uses sodium-based montmorillonite to characterize the clay minerals in shale and study the CH4 adsorption law in clay minerals, and this study has certain guiding significance for shale gas extraction. In addition, this paper also conducts a study on the competitive adsorption law of CH4 and CO2, and at the same time, predicts the theoretical sequestration of CO2 in shale clay minerals, which is a reference value for the study of CO2 burial in shale and is beneficial to the early realization of carbon neutral. In this paper, the slit model of sodium-based montmorillonite and the fluid model of CH4 and CO2 were constructed using Materials Studio software, and the following two aspects were studied based on the Monte Carlo method: Firstly, the microscopic adsorption behavior of CH4 in sodium-based montmorillonite was studied, and the simulations showed that the adsorption capacity of montmorillonite decreases with increasing temperature, increases and then decreases with increasing pressure, and decreases with increasing pore size. CH4 has two states of adsorption and free state in the slit. The adsorption type of CH4 in montmorillonite is physical adsorption. Secondly, the competitive adsorption of CH4 and CO2 in sodium-based montmorillonite was studied, and the simulations showed that the CO2 repulsion efficiency increased with increasing CO2 injection pressure, and the CO2/CH4 competitive adsorption ratio decreased with increasing pressure. The amount of CO2 storage decreased with increasing temperature and increased with increasing CO2 injection pressure.

裂缝型潜山油藏储集层非均质性强,油藏开发过程中驱替流体指进和窜流频发,封堵裂缝、大孔道等高渗流通道是提高原油采收率的有效措施.通过岩心流动实验,评价了微球对B1潜山油藏储集层岩心裂缝及大孔道的封堵效果,探究了采用微球-天然气驱提高剩余油动用的有效性.结果表明,单一水驱或天然气驱的驱油效率不显著,采用微球驱,微球进入岩心后的膨胀和封堵作用使得阻力系数、注入压力等显著增大;微球粒径直接影响封堵性能,若粒径太小,达不到封堵的效果,若粒径太大,不易注入;微球注入岩心后的膨胀、封堵、解堵、变形后再封堵及天然气溶解的协同作用,对裂缝型潜山油藏开发过程中的驱替流体指进及窜流有明显抑制作用,微球-天然气驱可大幅提高剩余油采出程度.

半贫砜胺液泵是净化厂尾气处理单元关键设备,透平驱动泵在长停后进行了驱动透平单试.但在联泵投用过程中,始终存在透平驱动端振动高导致联锁跳停问题.通过利用专业的振动监测仪现场采集数据,配套的振动分析软件进行数据分析,找到了引起透平驱动端振动联锁的根本原因,采取相应措施进行处理,解决了设备故障,保证装置的稳定运行.

In order to effectively solve the problems of difficult gas injection in S358 high pour-point reservoir and low oil displacement efficiency caused by gas channeling due to high mobility ratio of gas flooding after fracturing, laboratory experiments of gas injection phase and long core displacement mechanism have been carried out. Through the PVT phase state experiment of the high pour-point oil injected by CO2, dry gas, flue gas, and oxygen-reduced air（N2 90 %+O2 10 %）under the formation conditions, the characteristic mechanisms of the above four injection gas such as the solubilization expansion, viscosity reduction and tension reduction have been analyzed. CO2 is preferred as the injection gas. Through five groups of high temperature and high pressure long core flooding experiments with different combination methods, the effect of CO2 combination flooding on channeling prevention and extraction is evaluated. The experimental results show that the displacement effects of both CO2+weak gel and CO2+foam are the best two, and the final displacement efficiency is 70.101 % and 68.212 % respectively. The research results show that the injection of CO2 combined flooding slug increases the displacement resistance and reduces the fracture conductivity, which plays a key role in improving the microscopic sweep volume. Among them, both the CO2+weak gel and CO2+foam displacement methods have the best extraction effects. The research results can provide an experimental basis for the efficient development of high pour point oil in this block.

The cyclic gas injection technique is widely used in the development of condensate gas reservoirs. However, the override of injected gas induces severe gravity segregation in formations, thereby substantially limiting the application of this technique. At present, few literatures have been found to illustrate the override phenomenon taking place between gases. In this study, experiments were performed, and nonequilibrium thermodynamic theory was used, to examine the phase behavior of injected dry gas and condensate gas in place during the gas injection process. It is observed that in the equilibrium state, the injected gas can potentially reduce the condensate content by about 80%, yet the equilibrium is hard to achieve and the accompanied gas override weakens the effect of injected gas. After gas injection, the visual cell in the pressure-volume-temperature test exhibits a combination of dry gas-condensate gas-condensate oil for the case in which the testing pressure fluctuates around the dew point pressure and a combination of dry gas-condensate gas for the case in which the testing pressure exceeds the dew point pressure. Displacement experiments that were performed on a two-dimensional sandpack helped to determine the dynamic evolution of gas override, and until the end of the tests, the overburden degree increases 13% and 28% for the symmetrical injection mode and the top injection mode, respectively. Further theoretical analysis indicates that after gas injection, the system is prone to becoming trapped in a nonequilibrium steady state in which the fully mixed scenario is unlikely to occur. The results of this study enrich the understanding of the nonequilibrium override phenomenon, especially for that occurs between gas phases, and are crucial to early prediction and intervention of gas override.

Geological storage of CO2 is one of the most economical, feasible, and effective measures to slow down global warming. In this study, a combined long core model was designed to study the seepage characteristics of supercritical CO2 displacement. Moreover, the stability of permanent storage of cushion gas layers formed by supercritical CO2 injection has been systematically studied. The research results showed that in the supercritical temperature and pressure range of CO2, the front edge of CO2 displacement can form a relatively stable seepage zone. Supercritical CO2 displacement can achieve a high gas-storage rate and stable CO2 storage. At the same time, the recovery rate of remaining natural gas has been significantly improved. As the injection pressure increased, supercritical CO2 inhibited the reverse diffusion of natural gas molecules. Therefore, the breakthrough of the supercritical CO2 displacement front under a high pressure lagged behind. However, due to the increase in the density difference of gas molecules, the forward diffusion of supercritical CO2 has been enhanced. Temperature will not significantly affect the displacement and storage effects of supercritical CO2 in gas reservoirs. The increase in injection pressure and reasonable control of the injection rate can delay the breakthrough of supercritical CO2 displacement. These measures are conducive to the stable storage of CO2 and the improvement of remaining natural gas recovery. The implementation of CO2 geological storage is suitable for the later stage of gas reservoir depletion development. The high-density gravitational heterogeneity of supercritical CO2 enables the injected CO2 to form a stable high-density cushion gas layer in the gas reservoir, which can achieve stable CO2 storage for more than 100 years.

为有效解决S358高凝油藏注气难度大、压裂后气驱流度比过大容易气窜导致驱油效率低的问题,开展了室内注气相态及长岩心驱替机理实验.通过地层条件下高凝油注CO2、干气、烟道气、减氧空气(N290％+O210％)PVT相态实验,分析了4种注入气与高凝油接触的增溶膨胀、降黏、降低界面张力等特性机理,优选了CO2作为注入气.通过5组不同复合方式的高温高压长岩心驱替实验,评价了CO2复合驱油防窜提采效果.实验结果表明,CO2+弱凝胶、CO2+泡沫的驱替效果最好,最终驱油效率分别为70.101％、68.212％.研究结果说明,CO2复合驱段塞的注入使得驱替阻力增大,导致裂缝导流能力降低,对改善微观波及体积起到关键性作用.其中,CO2+弱凝胶、CO2+泡沫的驱替方式提采效果最佳,研究结果可为该区块高凝油的高效开发提供实验基础.

Fracture-type buried-hill reservoirs refer to dual media which have a fast breakthrough speed and a low sweep efficiency in the process of gas injection displacement. In order to overcome this problem, in this paper, a new profile control and oil displacement technology of pre-slug deep plugging by injection of different levels of nano-microspheres and natural gas was proposed. The mercury intrusion experiments were used to compare the fractal characteristics of the pore structures of the matrix and artificial fractured cores in the buried-hill reservoir. The results show that the heterogeneous characteristics of pores and fractures are the main factors leading to excessive gas breakthrough. Three nanomicrosphere systems (WJ1, WJ2, and WJ3) with good temperature resistance, salt resistance, swelling properties, and stability were prepared using the inverse emulsion method. Core plugging performance tests show that WJ3 has the best plugging effect among the three nano-microsphere systems, followed by WJ2 and WJ1. According to the scanning electron microscopy observations, it was found that the sealing mechanism of nano-microspheres includes direct sealing, bridging sealing, adhesive sealing, direct pass, deformed pass, and crushing pass. Finally, the displacement experiments with a composite fractured core showed that compared with pure natural gas injection, the breakthrough time of the combined displacement process of nano-microspheres and natural gas was greatly extended, and the final oil displacement efficiency was increased to greater than 80%.

In this paper, the DBR all-visible mercury-free high-temperature and high-pressure multifunctional formation fluid PVT analyzer developed and produced by Schlumberger company is used to conduct an experimental study on phase behavior characteristics of one offshore high CO2 condensate gas wells. The experiments include two-phase flash experiment, constant composition expansion experiment (CCE experiment), and constant volume depletion experiment (CVD experiment). Experimental results show that the higher the CO2 content in the condensate gas system, the higher the gas-oil ratio of condensate gas, the greater the density of condensate oil, the higher the dew point pressure of condensate gas, the greater the relative volume of condensate gas, the smaller the amount of retrograde condensate oil. And the higher the CO2 content in the condensate gas system, the phase diagram is shifted to the left and up, the critical point of the phase diagram is shifted to the lower left, the smaller the area of the two-phase envelope, the lighter the condensate gas system, the condensate oil recovery is higher. The above experimental results revealed that CO2 is well soluble with condensate gas, the expansion capacity of the condensate gas system was slightly enhanced, and because CO2 has a good extraction capacity, the light components of condensate gas were constantly extracted, the retrograde condensate rate of condensate oil decreases, and the maximum retrograde condensate volume also decreased. However, the condensate oil was produced along with the natural gas, and the higher the CO2 content, the stronger the extraction, the more condensate oil was produced. It is mainly because CO2 has the strong gasification and extraction capacity, on the one hand, the retrograde condensation of condensate gas was inhibited, and on the other hand, reverse evaporation of condensate oil was enhanced. The above experimental results indicate the law of the effect of CO2 on the phase behavior characteristics of condensate gas reservoirs, providing theoretical basis and guidance for the efficient development of condensate gas reservoirs at sea.

为了探索乌石17-2油田注气开发方式可行性以及进一步提高油田开发效果,从室内实验角度出发,对三种气体(N2、CO2、烃类气)开展了注气膨胀实验、细管实验、长岩心驱替实验,并进行对比分析及效果评价.研究结果表明:N2在地层条件下表现为非混相驱,其对原油的降黏及膨胀能力有限,后期气窜明显,注气突破时间较早,突破前采出近90％左右的原油,而突破后基本为无效注气,几无产出.室内驱油效率仅为36.3％,开发效果差.烃类气、CO2与地层原油相态配伍性要好,最小混相压力低,分别为27.52、27.13 MPa.地层条件下易形成近混相驱,气体突破要晚,气体突破以后仍能采出近30％左右的原油,驱油效率要高于非混相驱近25％,最终驱油效率分别为66.7％、69.0％,开发效果好.烃类气驱、CO2驱可作为乌石17-2油田低渗强水敏储层优选能量补充方式.

In view of the dual-media characteristics of low permeability buried hill reservoirs, the fingering and tongue-feeding phenomena are serious during the flooding development process. The flooding phase breaks through prematurely, the crude oil utilization in the matrix is low, and the final oil displacement efficiency is low. In this paper, the laboratory analysis of long lithologic displacement was conducted for the XL low permeability buried hill reservoir block to evaluate the effects of fracturing, displacement media and displacement methods on the development. The experimental results show that the oil displacement efficiency value of the continuous gas injection flooding process before fracturing is 60.98%, the oil displacement efficiency value of the continuous gas injection flooding process after fracturing is 58.93%, and the oil displacement efficiency value of the continuous water injection flooding process after fracturing is 69.94%. The water injection volume during continuous water flooding after fracturing is 1.60PV, the oil displacement efficiency during pulse gas flooding after fracturing is 64.01%, the oil flooding efficiency during pulse water flooding after fracturing is 67.63%, and the water injection volume of the pulse water flooding process after fracturing is 1.92PV. Those results show that the continuous oil flooding process after fracturing is the highest in the final oil displacement efficiency, and it requires less water injection than the pulse water flooding process after fracturing. The experimental research in this paper shows that in the process of dual-media displacement development of low permeability buried hill reservoirs, the continuous water flooding displacement development process after fracturing can communicate well with the matrix and high-permeability channels, and at the same time reduce the breakthrough time of the displacement phase to obtain better oil displacement efficiency.

Since the 1970s, CO2 flooding-EOR technology has formed multiple development modes in the concept of reservoir engineering, including continuous CO2 injection, WAG injection with constant proportion, tapered/hybrid WAG injection and SWG/SSWG injection. The reason why CO2 become the injection gas for tertiary oil recovery with great vitality benefits from its supercritical fluid characteristics and remarkable solvation capacity. Based on the analysis of the main oil displacement mechanism of CO2 and the reservoir engineering concept and development mode of typical CO2 flooding-EOR technology at home and abroad in recent years, and considering their development characteristics of different types of reservoirs, especially the successful application of horizontal well technology and low permeability reservoir volume fracturing technology, as well as the comprehensive utilization concept of CO2 CCUS-EOR combined with CCUS concept, further suggestions are put forward for the development of reservoir engineering development mode by CO2 flooding-EOR technology in China, so as to provide enlightenment for further promoting its large-scale development.