Abstract Tight reservoirs are characterized by low porosity, low permeability and complex pore structures, resulting in poor waterflood recovery efficiency. Existing microscale two-phase flow studies are mostly based on two-dimensional geometric models, and the physical mechanism of fluid-solid coupling effect on flow behavior remains insufficiently understood. In this study, a three-dimensional digital core model of real tight sandstone was constructed using CT scanning and digital image processing techniques, and a phase-field mathematical model of oil-water two-phase flow considering bidirectional fluid-solid coupling was established, with its accuracy verified by classical capillary imbibition experiments (maximum relative error < 3.5%). The results show that the pore radius and throat radius of tight sandstone both follow lognormal distribution, with an average coordination number of 5.13, a fractal dimension of 2.37, and 76% of throats distributed in the 0-9 μm range. Under fluid-solid coupling, the relative permeability at the isosmotic point of the small-throat pore-type model decreases by 32.4%, significantly higher than the 18.7% decrease of the large-throat pore-fracture model. Water phase preferentially displaces oil along pore throats with low flow resistance, large pore size and spatial orientation parallel to the seepage direction. This study innovatively combines three-dimensional real digital core with bidirectional fluid-solid coupling phase-field method, quantitatively reveals the stress sensitivity difference mechanism between different pore structures, and elucidates the capillary-viscous force competition mechanism of fingering formation in tight reservoirs.

A tight reservoir is characterized by low porosity and permeability as well as a complex pore structure, resulting in low oil recovery efficiency. Understanding the micro-scale distribution of residual oil is of great significance for improving oil production and water flooding recovery rates. In this study, a 3D pore structure model of tight sandstone was established using CT scanning to characterize the residual oil distribution after water flooding. The effects of displacement methods and wettability on residual oil distribution at the micro-scale were then studied and discussed. Moreover, increasing the displacement rate has little effect on the distribution area and dominant seepage channels. Microscopic residual oil is classified into five discontinuous phases according to the oil–water–pore–throat contact relationship. The microscopic residual oil exhibits characteristics of being dispersed overall but locally concentrated. Under water-wet conditions, the injected water tends to strip the oil phase along the pore walls. Under oil-wet conditions, the pore walls have an improved adsorption capacity for the oil phase, resulting in a large amount of porous and membranous residual oil retained in the pores, which leads to a decrease in the overall recovery rate.

Abstract This study conducts a comprehensive investigation into theformation mechanisms of unconventional oil reservoirs within the Carboniferous strata of the Hudson Oilfield in the Tarim Basin. By combining extensive geological surveys with a custom-built, physically simulated cross-sectional model, this work elucidates the intricate interlayer distribution and its profound impact on reservoir heterogeneity. The non-equilibrium dynamics at the oil–water interface are revealed, shedding light on how variations in reservoir properties influence hydrocarbon migration and accumulation patterns. Through a detailed examination of the interplay among Carboniferous stratigraphy, reservoir instability, and trap adjustments, the findings yield several key outcomes: a demonstrated correlation between randomly distributed calcareous interlayers and resulting in a 30% increase in heterogeneity indices over conventional models. Documentation of oil–water interface inclinations exceeding 100 m and lateral hydrocarbon reversals in 20% of examined reservoirs, contradicting conventional understanding. Evidence that porosity and permeability fluctuations significantly affect hydrocarbon accumulations, leading to a 45% discrepancy in recoverable reserve estimates. And the application of advanced simulations, enhancing unconventional reservoir prediction accuracy by 25% compared to standard geological techniques. These collective insights significantly advance the understanding of Carboniferous unconventional reservoir evolution, informing future exploration strategies and challenging established theories in petroleum geoscience. This highlights the necessity of accounting for reservoir instability and interlayer intricacy in deciphering unconventional hydrocarbon systems.

In the Dabei oil and gas field, addressing wax deposition in condensate gas reservoirs is crucial. By analysing field-obtained samples with varied wax contents (7%, 12%, 19%, 28%) using the HPVT-150 PVT instrument, we observed minimal changes in flash steam composition but notable enrichment in flash oil components and increased condensate oil densities. Higher wax content led to an increased flash gas-to-oil ratio, dew point pressure, and reverse condensate saturation, impacting heavy hydrocarbons. Recovery efficiency of condensate oil decreases with higher wax content and abandonment pressure at 10MPa. These findings are pivotal for developing high-wax condensate reservoirs.

Marine deep Ordovician reservoirs are significantly controlled by strike-slip fault zones, which govern reservoir fluid evolution during various activity periods. Such fluid evolution elucidates the process underpinning ultra-deep oil and gas accumulation and delineates the pivotal role of strike-slip fault zones in hydrocarbon aggregation. This method can improve the understanding of the mechanism of hydrocarbon accumulation in deep to ultradeep carbonate rocks. The findings indicate that the Ordovician reservoirs in the northern thrust fault zone of the Fuman Oilfield predominantly exhibit two stages of calcite vein formation. The distribution patterns of rare earth elements and Sr isotope characteristics suggest that both stages of vein formation were sourced from Middle to Lower Ordovician marine strata, with no evidence of oxidizing fluid infiltration. This indicates that late-stage oil and gas charging in deep-ultradeep formations has good sealing properties. In these calcite veins, early-, middle-, and late-stage fluid inclusions were primarily entrapped. By examining the development of primary oil inclusions and combining the U‒Pb isotope data of host minerals, this study confirms the occurrence of three stages of oil and gas charging in the deep Ordovician strata of the northern thrust fault zone in the Fuman Oilfield. These stages correspond to approximately 459 ± 7.2 Ma (mid-Caledonian), 348 ± 18 Ma (early Permian), and 268 Ma (late Permian). The key accumulation period of oil and gas reservoirs in the study area is the middle and late Caledonian, and there is a good correspondence between oil and gas charging and fault activity.

The Lunnan oilfield in the Tarim Basin, one of China’s major onshore oilfields with substantial geological reserves, faces particular challenges due to the complexity of its reservoir environment and the dispersion of remaining oil. Carbon dioxide, a greenhouse gas, presents an opportunity for enhanced oil recovery (EOR) and geological storage. In this context, the use of carbon dioxide for EOR can simultaneously address environmental concerns and improve oil recovery rates. This study focuses on the TI reservoir in the No. 2 well area of the Lunnan oilfield, employing advanced techniques to analyze the micro- and macro-characteristics of carbon dioxide flooding. Results: From the microscopic point of view, carbon dioxide flooding is mainly miscible with crude oil, which has a strong component exchange effect and can be displaced in the form of full pores, and the microscopic displacement efficiency is close to 100%. Macroscopically, under the combined injection and production of different injected hydrocarbon pore volume multiples (HCPVs), it is injected at the upper and lower layers of the interlayer and produced far away from the lower layer of the interlayer, with a total recovery rate of 52.83%. With the increase in the HCPV, the recovery increased rapidly at first and then slowly, and the HCPV at the demarcation point was 0.5, while the oil production rate increased in a wave-like manner and then decreased rapidly, and the HCPV at the breakthrough point of TI gas was 0.5. However, when the upper and lower layers far away from the interlayer are injected at the same time, the upper and lower layers of the interlayer are produced at the same time, and the total recovery rate can reach 83.02%. With the increase in the HCPV, the recovery rate increases rapidly at first and then slowly, and the HCPV at the turning point is 6.52. The oil production rate increases in a wave-like manner, then decreases rapidly, rises rapidly, and then decreases slowly in a wave-like manner. The HCPV at the breakthrough point of TI gas is 0.63, and the HCPV at the injection–production transition point is 0.63. The total recovery rate of carbon dioxide miscible displacement can reach 88.68% under the condition of separate injection and combined production with different injected hydrocarbon pore volume multiples. With the increase in the HCPV, the recovery increased rapidly at first and then slowly. The HCPV at the demarcation point was 6.5, the oil production rate increased in a wave-like manner, then decreased rapidly, increased rapidly, and then decreased slowly in a wave-like manner. The HCPV at the breakthrough point of TI gas was 0.63, and the HCPV at the injection–production transition point was 6.5. The research results provide data support for the physical reality of the microscopic and macroscopic sweep characteristics of carbon dioxide flooding in the Lunnan oilfield, Tarim Basin.

Fracture-cavity carbonate reservoirs exhibit significant heterogeneity with diverse flow modes, including porous media seepage and free flow, within fractures and cavities. This complexity is further compounded by tectonic stress. Traditional oil reservoir seepage theories often struggle to depict these fluid flow characteristics accurately. This study employs a hydraulic-mechanical-damage coupling model to conduct numerical simulations of multi-mode fluid flow within fracture-cavity reservoirs. This approach elucidates fluid flow mechanisms influenced by multi-field coupling and predicts areas favorable for oil accumulation based on actual geological models. The results show that (1) while the secondary fractures developed in the penetrating-type fracture-cavity body result in the highest oil migration efficiency and initial production, the production from this body type decreases rapidly in the later stage. Secondary fractures in the sandwich-type and side-type cavity bodies primarily offer storage, resulting in lower initial production but a slower production decline. (2) In the S1 stress state, secondary fractures primarily connect fracture-cavity bodies, whereas, in the S2 stress state, they mainly contribute to oil accumulation. (3) Secondary fractures function as efficient conduits for oil migration, and their distribution is influenced by the presence of fault zones and cavities. Consequently, the intersection of cavities and fault zones with secondary fractures leads to the formation of favorable oil accumulation areas.

The clastic reservoir in Tarim Oilfield has entered the middle-to-late stage of development, and consequently, enhanced oil recovery (EOR) is becoming highly challenging. Gas flooding is the practical method for EOR from this type of reservoirs. In this study, taking Tazhong 402 CIII reservoir as an example, the micro-mechanism of EOR by gas injection is investigated by conducting slim-tube, long-core displacement, and micro-visual displacement experiments. A gas injection development plan is formulated based on reservoir characteristics, laboratory experiments, and numerical simulations. The results show that miscible flooding cannot be achieved by injecting natural gas under the current formation conditions; however, natural gas flooding after light hydrocarbon flooding can significantly improve oil recovery. The studied reservoir is divided into two series of development layers: CIII1-3 layers, for which light hydrocarbon alternating natural gas flooding is adopted, and CIII4-8 layers, for which light hydrocarbon combined with natural gas gravity-assisted composite flooding is employed. The findings of this study have guiding significance for gas injection development in deep clastic reservoir in Tarim Basin.

Strike-slip fault identification is an important work in the oil and gas exploration. When it associates many karst caves, the accuracy of traditional methods such as coherence, curvature will be greatly affected. Although the deep learning method can identify some complex faults their structures are relative regularly, but it cannot overcome this question their fault intervals are too wide. Therefore, this paper proposes an improved technology for strike-slip identification based on deep learning cascade ant tracking. Firstly, the U-Net++ network is employed for predicting main faults. However, it is noted that the fault width appears excessively large. Then, utilizing advantages of ant tracking, fault skeletonization also called as fault thinning is operated. Model test and real data application show: (1) the main strike-slip faults identified by the deep learning method are skeletonized and their precisions are improved; (2) many small and micro faults controlled by main strike-slip faults are detected for cascading ant tracking technology.

Deep condensate gas reservoirs exhibit highly complex and variable phase behaviors, making it crucial to understand the relationship between fluid phase states and flow patterns. This study conducts a comprehensive analysis of the actual production process of the deep condensate gas well A1 in a certain oilfield in China. Combining phase behavior analysis and CMG software simulations, the study systematically investigates phase transitions, viscosity, and density changes in the gas and liquid phases under different pressure conditions, with a reservoir temperature of 165°C. The research covers three crucial depletion stages of the reservoir: single-phase flow, two-phase transition, and two-phase flow. The findings indicate that retrograde condensation occurs when the pressure falls below the dew point pressure, reaching maximum condensate liquid production at around 25 MPa. As pressure decreases, gas phase density and viscosity gradually decrease, while liquid phase density and viscosity show an increasing trend. In the initial single-phase flow stage, maintaining a consistent gas-oil ratio is observed when both bottom-hole and reservoir pressures are higher than the dew point pressure. However, a sudden drop in bottom-hole pressure below the dew point triggers the production of condensate oil, significantly reducing subsequent gas and oil production. In the transitional two-phase flow stage, as the bottom-hole pressure further decreases, the reservoir exhibits a complex flow regime with coexisting areas of gas and liquid. In the subsequent two-phase flow stage, when both bottom-hole and reservoir pressures are below the dew point pressure, a significant increase in the gas-oil ratio is observed. The reservoir manifests a two-phase flow regime, devoid of single-phase gas flow areas. For low-pressure conditions in deep condensate gas reservoirs, considerations include gas injection, gas lift, and cyclic gas injection and production in surrounding wells. Additionally, techniques such as hot nitrogen or CO2 injection can be employed to mitigate retrograde condensation damage. The implications of this study are crucial for developing targeted development strategies and enhancing the overall development of deep condensate gas reservoirs.

The reservoirs of ultra-deep and low-permeability sandstones typically exhibit characteristics of lithological tightness and poor physical properties. Fractures control the oil and gas content as well as the productivity of such reservoirs. However, the distribution of fractures is complex, exhibiting strong heterogeneity. Therefore, a systematic study on reservoir fracture modeling can provide geological foundations for the development of such reservoirs. Due to the considerable burial depth of these reservoirs, conventional methods relying solely on seismic information have limited reliability, and the established discrete network models of fractures are often less dependable. In this paper, taking the X gas reservoir in a basin in western China as an example, we discuss a fracture modeling method based on the integration of geological information to enhance the efficiency and accuracy of fracture modeling. The modeling method primarily involves the use of deterministic methods to obtain large-scale fractures, while random simulation is employed for small and medium-scale fractures. The fracture development control factors and seismic attribute information are integrated using permanence of ratios (PR) model to establish a fracture development probability field model. Subsequently, the geometric parameters of fractures and the fracture density model are used as input parameters to generate a discrete network model of small and medium-scale fractures using a object-based modeling method. Finally, based on the fracture equivalent property model and verified through geological understanding, analysis of production dynamics, and numerical simulation of the gas reservoir, it is demonstrated that the fracture model established using the proposed method aligns with geological understanding and exhibits high reliability.

The Donghe 6 block in Tarim oilfield has the problems of ultra-deep, high temperature, high pressure, high salinity, low permeability, strong water sensitivity, low oil production, low water cut and low recovery rate of recoverable reserves relying on natural energy depletion. Based on the brief introduction of the geological characteristics of the block, the basic situation of the single well and the review of the old wells in the Donghe 6 well group were analyzed, with the emphasis on the nitrogen injection test. Combined with the actual situation of Donghe 6 well group, the feasibility of CO2 flooding in ultra-deep, high temperature, high pressure and high salt reservoir group was demonstrated by continuously injecting supercritical carbon dioxide into the high part of the structure to give full play to the gravity assisted flooding effect of injected gas. The demonstration results show that the Donghe 6 well group adopts the continuous gas drive mode of one injection and two production of pure carbon dioxide, with a cumulative injection of 16000 tons of liquid carbon dioxide, and a predicted cumulative oil production of 26800 tons in five years, with a stage increase of 4.9

At present, research studies on the description of fracture characterization elements in fault solution reservoirs are relatively limited, and further research is needed on contour recognition and characterization methods. In this paper, first, the regional fault system is investigated and the faults are finely identified and characterized. Second, the volume of contour-sensitive attributes of the fault solver is optimized using tensor attributes, amplitude variation, discontinuity detection, and other attributes. Finally, a comprehensive evaluation of the fault solution reservoir is carried out by combining the dynamic production characteristics. Results show that (a) the interior details of fractured reservoirs can be mainly divided into two categories: cave-type reservoirs and fracture-pore-type reservoirs. (b) Fractured and porous reservoirs mainly utilize discontinuous properties and combine well data to calibrate and determine threshold values, ultimately achieving the characterization of interior details of fractured solution bodies. (c) After anisotropic diffusion filtering and fault enhancement, the seismic data was subjected to amplitude gradient disorder detection attribute calculation for multiscale fractures.

Wax deposition in gas wells of condensate reservoir is the main factor affecting the development of condensate reservoir.This paper takes Bozi high wax condensate gas well in Tarim Basin as the research object,uses high temperature and high pressure equipment and laser test to carry out wax deposition test in condensate gas reservoir under high temperature and high pressure,uses Differential Scanning Calorimeter test, chromatographic analysis to separate the characteristics of wax deposition,and uses self-developed thin tube dynamic wax deposition equipment to analyze the effects of different flow rates,gas-oil ratio and particles on wax deposition in high temperature and high pressure condensate gas well,and uses multiphase flow wellbore deposition dynamic model to predict the wax deposition law under different daily output.The results show that the highest wax deposition point of Bozi condensate gas is 33.71℃, and its wax content is also the highest.At -20℃,the wax accumulation of condensate oil is lower than that of condensate oil, and the wax content and density of well 102-2 are the highest. With the increase of flow rate, the wax deposition rate decreases.With the increase of gas-oil ratio,the wax formation rate of condensate gas decreases.The dynamic prediction model of multiphase flow wellbore deposition is used to analyze the wax deposition in the wellbore, and it is concluded that there is no wax deposition in the wellbore when the daily output exceeds 3.4×105m3.The research results provide theoretical data support for wax deposition law in ultra-deep condensate gas reservoirs.

塔里木油田公司是我国第三大油气田和西气东输主力气源地,也是新疆最大的油气田企业和中国石油最具发展潜力的地区公司,主要在塔里木盆地从事油气勘探、开发、销售以及新能源等业务.公司总部位于新疆库尔勒市,作业区域遍及南疆五地州.

For secondary and tertiary oil recovery processes, the interfacial interactions between injected gas and crude oil contributes significantly at the pore-scale. We experimentally examine the effect of temperatures, pressures and surfactants on interfacial interaction, contact angle and oil displacement efficiency of CO2 flooding at the pore-scale using microfluidics. Two types of flow channel designs are utilized in this study, blind end of direct channels and curved channels with different diameters. The results indicate that increasing pressure and adding surfactants can promote the contact between oil and gas and reduce the interfacial tension, which has a certain impact on oil displacement efficiency. In the process of gas flooding, CO2 dissolution, expansion and miscibility are the key oil-gas interactions. The results of experiments in curved and direct channels show that the curved channels increase the resistance of fluid flow and limit the contact between CO2 and oil. And with the decrease of the porous medium radius, the capillary action in the pores increases, and the higher the viscous force needed for displacing the oil, which will affect the interaction between oil and gas and the oil recovery in micro pores. Then, two non-ionic alkoxylated surfactants (i.e. ethylene glycol butyl ether and Span 80) were selected to enhance the interaction between CO2 and crude oil. The presence of surfactants increases the solubility of CO2 in crude oil, which reduces the interfacial tension of the system and results in higher oil recovery.

Fault stability refers to the risk level of reactivation of the pre-existing fault in the stress field. Fault reactivation within the oilfield is mainly caused by the increase of fluid pressure in the fault zone. The quantitative evaluation index of the fault stability is the critical fluid pressure (that is, additional fluid pressure) required for fault reactivation under the current pore fluid pressure. When the formation pore pressure reaches the critical value, the corresponding fault part will be in the critical stress state. The sliding of the fault in the critical stress state will easily cause oil and gas leakage and casing damage at the edge of the fault. Therefore, it is of great significance to study fault stability for oilfield production. Ground stress is a key parameter for fault stability evaluation. There are many methods to calculate the geomechanics including hydraulic method, acoustic emission method, and the use of the logging data, among which the hydraulic fracturing method can be used to obtain the most accurate horizontal minimum principal stress. This paper calculates the continuous geomechanics by using the logging data. There are many methods available for evaluating fault stability, among which fault sealing analysis technology (FAST) method is most widely used. FAST can be used to not only quantitatively evaluate fault stability, but also evaluate the impact of fault cohesion on fault stability. There are many factors affecting fault stability. The relationship between the differential stress and tensile strength of the fault rock will affect the trend of the fault reactivation.The direction of the stress field also affects the fault stability greatly. The argillaceous material weakens the strength of fault rock. When a large amount of argillaceous material enters the fault zone, the fault tends to reactivate. The change of reservoir fluid pressure will also lead to the change of horizontal stress to affect the stability of the fault. In addition, the accuracy of seismic interpretation will also affect the evaluation results of fault stability. Based on the geological model framework and one-dimensional geomechanical model calibration, this paper establishes a three-dimensional geomechanical model by using the finite element simulation method to carry out four-dimensional geomechanical research to evaluate the fault stability in the development of the Donghe 1 Reservoir in Tarim basin. The research results show that the fracture sealing gradually strengthens during the development of Donghe 1 Reservoir, and the quantized critical fracture opening pressure is 67.38MPa.

针对塔北-塔中奥陶系碳酸盐岩富油气三角带断裂控储控藏欠缺系统性认识的问题,通过地震精细解释和构造力学机制分析,对塔北-塔中地区走滑断裂和油藏分布特征进行系统性研究,尤其从断层形成的力学机制、断层规模、断层分段性及断层组合样式等方面,剖析富油气三角带的发育特征及油气富集机制.研究表明:塔北-塔中地区的油气受控于2条区域级走滑断裂,其组合形成的富油气三角带内各断裂级别差异明显,且存在明显分段特征;塔中地区断裂带一般分为线性段、斜列段和羽状段,塔北地区断裂带可分为辫状堑垒段、拉分段和羽状段;断裂分段性导致同一断裂不同段油气富集特征具有明显差异,针对不同段可采用不同程度的开发方式,能有效提高储量整体动用程度.该研究可为国内外相似地质条件的碳酸盐岩油气藏勘探提供有益的借鉴.

CO2 huff-n-puff is a potential approach to improve the oil displacement efficiency in the deep reservoirs, which can achieve carbon sequestration and efficient oil production, simultaneously. However, the fundamental understanding of carbon mass transport, sequestration and leakage mechanism in deep geological reservoirs at the microscopic pore scale is still ambiguous. In this work, we innovatively designed a precise CO2 huff-n-puff microfluidic experiment under ultrahigh temperature and pressure conditions (55 MPa, 115 degrees C) to study the microscopic mechanism of CO2 utilization, storage and leakage (CUSL) in pore scale. Moreover, we proposed the quantitative analysis method for oil-CO2 interaction behavior to explicit dissolution and extraction characteristics, pressure threshold and interface stability by introducing Pseudo-Color algorithm and relevant parameters such as dynamic oil swelling factor, contact angle and gray value. Then, the pore-scale dynamics of the fluid interaction mechanism during the soak and puff process were quantitatively characterized, corresponding to the carbon sequestration efficiency of crude oil continuously exposed to scCO2 and the leakage risk with step-down production, respectively. The experimental results indicate that during the huff process, the oil-CO2 phase behavior characteristics at 115 degrees C can be divided into swelling, immiscible extraction and miscible extraction regions, which are coordinately controlled by dissolution mechanism, capillary effect and vaporization mechanism. Moreover, ultrahigh temperature oil generally requires higher pressure to start extraction and miscibility (Pext = 6.38 and 15.96 MPa, MMP = 9.71 and 23.73 MPa, T = 50 and 115 degrees C, respectively), while the asphaltene precipitation pressure Pasp is lower. At ultrahigh temperatures, the oil-CO2 interaction also enters the contact angle fluctuation region in advance, and the morphology of asphaltene particles is single, fine and uniform. When the soaking time is 36 min, the non-extractable oil component gradually evolves into a carbon sequestration interface. During the subsequent puff process, the more stable the carbon sequestration interface in the