To identify the causes behind low recovery in tight sandstone gas reservoirs, taking the Shan 2 gas reservoir in the Zizhou gas field as an example, and based on the definition of recovery for gas reservoirs, a zonal reserves producing model and an analytical theoretical model for recovery were established. With the 2 models, the recovery of the gas reservoir was calculated, and the causes behind the low recovery in the tight sandstone gas reservoir were systematically analyzed. The results show that the low recovery in the Shan 2 gas reservoir is primarily attributed to the low vertical sweep coefficient, low plane sweep coefficient, and low gas displacement efficiency. The vertical sweep coefficient is mainly influenced by the vertical heterogeneity of the reservoir, the gas displacement efficiency is closely related to the abandonment pressure of the gas reservoir, while the plane sweep efficiency is primarily constrained by the horizontal heterogeneity of the reservoir and the controlling extent of well pattern. Rationalizing well pattern deployment and enhancing plane sweep coefficient are effective methods for increasing the recovery of tight sandstone gas reservoirs. However, even when the plane sweep coefficient is 100%, the ultimate recovery remains relatively low. Therefore, strengthening research on increasing vertical sweep coefficient and improving gas displacement efficiency is crucial for enhancing recovery in tight sandstone gas reservoirs.
To clarify the occurrence space and mobility of the shale oil in the Fengcheng formation of the Mahu sag, Junggar Basin, the data of rock thin section, SEM and NMR, and experiments such as total scanning fluorescence were used, together with 2D NMR logging data, to systematically characterize the microscopic pore structure and crude oil occurrence characteristics of the shale reservoir, and identify the factors controlling oil mobility. The storage space of the shale reservoir of the Fengcheng formation in the study area is mainly composed of intergranular pores, intercrystalline pores, dissolution pores, organic pores, and microfractures, with dissolution pores and fractures in dominance. The mobility of shale oil varies significantly in reservoirs with different lithofacies. The best mobility is found in the felsic shale rich in terrigenous clastic silt-sand bands, followed by the dolomitic shale with well-developed dolomitic laminae, and the worst mobility is found in the mixed shale rich in clay minerals. Organic matter abundance, depositional fabric, and pore structure are key factors controlling the mobility of shale oil in the Fengcheng formation. When total organic carbon (TOC) content of the shale in the study area ranges from 0.5% to 1.5%, the oil saturation index reaches its maximum range, indicating good mobility of the shale oil. In thin-bedded felsic shale and laminated dolomitic shale, pores (mainly residual intergranular pores and dissolution pores) and microfractures are developed, with a high proportion of large pores, which facilitates the formation of favorable occurrence space and flow channels for shale oil, promoting the enrichment of mobile oil.
The tight oil reservoir in the Jinlong 2 well block in the Zhongguai bulge, western uplift of the Junggar Basin, is developed by horizontal well hydraulic fracturing. Frequent inter-well frac-hit caused by the large-scale well infilling and the presence of fault zones in the reservoir impedes production efficiency greatly. By investigating the applicability of monitoring and identification methods for inter-well frac-hit in multi-stage fractured horizontal wells, and combining field fracturing monitoring and production data from the Jinlong 2 well block, a comprehensive identification workflow for inter-well frac-hit was established. This workflow which integrates production performance, fracturing operation, and microseismic characteristics was used to identify and analyze inter-well frac-hit in the study area. The results show that severe inter-well frac-hit exists in the Jinlong 2 well block, not only within but also across individual horizons and fault blocks. The relatively small horizontal well spacing and developed fault system in the reservoir in the Jinlong 2 well block may induce inter-well frac-hit. It is recommended to avoid well infilling in large-scale fault zones and reduce fracturing scale for infill wells.
The mechanism of fracture propagation and changes in mechanical properties of deep shale reservoirs caused by the imbibition of fracturing fluid after hydraulic fracturing remain unclear. By CT scanning, continuous scratch testing, and overburden pressure porosity-permeability testing, as well as spontaneous imbibition experiments, the fracture propagation patterns, changes in rock mechanics, and variations in physical properties before and after imbibition were comprehensively evaluated. The results show that imbibition promotes the activation, propagation, and interconnection of shale beddings and pre-existing microcracks, forming a more complex fracture network to enhance reservoir porosity and permeability. The development of fracture and bedding plane reduce the overall strength and stability of rock, demonstrating a dual effect of improving fluid transport capacity while weakening mechanical performance. Under limited crack propagation conditions, the increase in porosity and permeability is modest. When a complex fracture network is developed, reservoir porosity and permeability significantly improve, and mechanical weakening becomes more pronounced. In the evaluation and stimulation design of unconventional reservoirs, it is essential to balance the fracture network induced by spontaneous imbibition to account for its impact on reservoir flow conditions and formation stability.
The Keshen gas field in the northern Kuqa depression of the Tarim Basin is a typical representative of ultra-deep fractured tight sandstone gas reservoirs. The intensifying water invasion has significantly affected the steady gas field development in recent years. Taking the Cretaceous Bashijiqike formation in the Keshen X gas reservoir as an example, the fault/fracture characteristics of the reservoir were analyzed using the drilling fluid loss and imaging logging data, and their controls over production performance were identified. Depending on production behaviors of various gas wells and water invasion patterns in the reservoir, a production performance model of the reservoir under fault/fracture control was established, and corresponding production strategies were proposed. The results show that microfractures are well developed in the Keshen X gas reservoir, and the reservoirs can be divided into three types by fault/fracture presence: multi-fracture, single-fracture and micro-fracture. Two wells targeting multi-fracture reservoirs are deployed in the middle-upper part of the Keshen X gas reservoir, four wells targeting single-fracture reservoirs in the middle and edge parts of the gas reservoir, and one well targeting micro-fracture reservoirs in the upper part of the gas reservoir. Based on production behaviors, gas wells can be classified into highly water-flooded wells, long-term water production wells, and long-term stable production wells without water breakthrough, corresponding to single-fracture reservoir, multi-fracture reservoir, and micro-fracture reservoir, respectively. It is recommended to maintain a moderate productivity for wells targeting multi-fracture reservoir, inject gas to replenish energy in the initial stage of water invasion for wells targeting single-fracture reservoir, and keep a proper production pressure differential for wells targeting micro-fracture reservoir.
The complex mineral components of conglomerate reservoirs have active surface physical and chemical properties, making them liable to interact with polymers and surfactants. These interactions may result in loss and alteration of binary flooding formulations underground. By using core samples from different types of conglomerate reservoirs, the microscopic structure and mineral composition/content were investigated, specific surface area and Zeta potential were measured, and the adsorption charts of chemical agents on the cores were established. Through oil displacement experiments, the impacts of rock mineral composition and structure of conglomerate reservoirs on the recovery of polymer-surfactant binary flooding was validated. The results show that in conglomerate reservoirs, clay and zeolite minerals have large specific surface areas and high Zeta potentials, and their active physical and chemical properties affect oil displacement efficiency. The cores from Class I reservoirs with the best petrophysical properties exhibited the highest ultimate recovery factor, the cores from Class II reservoirs with the lowest content of active minerals achieved the highest chemical flooding efficiency, while the cores from Class III reservoirs showed the lowest oil displacement efficiency.
In the Bozhong 19-6 structure, fractures serve as the primary flow channels and storage spaces in the metamorphic buried-hill reservoirs, significantly controlling the formation of high-quality reservoirs and well productivity. To accurately identify high-quality reservoirs in the Bozhong 19-6 structure and predict their productivity, fractures were quantitatively characterized using thin sections, imaging logs, and other data. Based on the division of vertical structural units within the buried-hill reservoirs, high-quality reservoirs in the target intervals were identified using conventional mud log, wireline and imaging logging data. The reservoirs were finely evaluated by introducing fracture development index and comprehensive index methods and then a comprehensive method for identifying high-quality reservoirs was established. By substituting the effective thickness and fracture parameters of the high-quality reservoir into productivity evaluation equation, the gas layer productivity of the target intervals was calculated and compared with the test results. It is found that the relative error between the predicted productivity index per meter and the actual productivity values is less than 15%, which indicates a high feasibility of this comprehensive evaluation method in identifying high-quality reservoirs in metamorphic buried hills. This study offers a guidance for oil and gas development in the metamorphic buried hills in the Bozhong 19-6 structure.
Heating formation to reduce crude oil viscosity is one of the main mechanisms of cyclic steam stimulation (CSS). A dynamic heat transfer model considering both thermal convection and thermal conduction was established. Coupling temperature and pressure fields, this model was used to determine formation pressure, formation temperature, and fluid convection velocity, so that the dynamic variation of formation heat was analyzed. The research results show that, in the steam injection stage, given the same cyclic steam injection volume, higher heating rates and net heat are achieved when the injection duration is 6.0-10.0 days. In the soaking stage, when the pressure stops rising, thermal convection weakens rapidly, and formation heating rate significantly decreases, with an 88.3% drop in heating rate after 4.0 days of soaking, allowing for well production. In the production stage, thermal conduction becomes the dominant mechanism, and the formation heat increases slowly and steadily. After one cycle of CSS, 57.7% of the incremental heat is recovered with the produced fluid, while 42.3% remains in the formation. This study provides a deeper understanding of the formation heat variation during CSS, which supports the optimization of injection-production parameters and the analysis of steam heat flow.
The Kelasu ultra-deep gas field in the Kuqa depression of the Tarim Basin is challenged by severe water invasion, leading to rapid decline in production. Through analysis on surface seismic data and imaging logging data, the distribution patterns of faults and fractures were determined. Combining with the production performance of the gas field, three types of water invasion were identified in the Kelasu ultra-deep gas field: fault-communicated edge or bottom water, non-uniform water invasion along fractures, and occluded water invasion due to locally incomplete displacement. The former two types are dominant in the gas field. The three types differ significantly in characteristics and influence range. On one hand, the ability to communicate with edge or bottom water along the trend of second-order faults and vertically is strong, but water invasion perpendicular to the trend of faults has a minor, localized impact. On the other hand, fractures are oriented and distributed regularly, showing a feature of “zones generally and belts locally”. The differences in the internal connectivity of the gas reservoir, the order and the speed of water invasion in the gas reservoir are the external manifestations of the division and zonation of fractures, which have a global effect on water invasion in the gas reservoir. Considering the water invasion characteristics and development status of the gas field, strategies were proposed to optimize well pattern according to spatial distribution of fractures, and to strengthen researches on two supporting gas production technologies: chemical water plugging and gas injection to alleviate water lock.
The shale gas field in Anchang area in the northern part of Guizhou province is primarily producing from the shales in the Wufeng formation to Longmaxi formation. This gas field is characterized by a source-reservoir integrated system in stable distribution and self-generation and self-storage pattern, and it is classified as a shallow mountainous shale gas field under normal pressure. From top to bottom, the gas-bearing layers show an increasing content of siliceous minerals and a decreasing content of clay minerals. The shale reservoir space primarily consists of nanometer-scale organic pores, followed by residual intergranular pores, intercrystalline pores, secondary dissolution pores, and clay mineral interlamellar pores. The gas wells generally exhibit low flowback rates upon gas breakthrough, slow production decline, and long stable production period. Considering the geological and developmental characteristics of this type of gas reservoir, it is important to enhance detailed geological modeling and fracturing design optimization, as well as to moderately expand well spacing. Given the presence of faults and strong heterogeneity, integrated geological and engineering design should be strengthened, and the 3D reservoir geological model should be iteratively optimized to establish an accurate shale gas reservoir model. In view of the large differential horizontal stress ratios and the difficulty in forming complex fracture networks, fracturing stage length and cluster spacing should be optimized, and multi-cluster fracturing and fracture diversion techniques can be implemented. For low reservoir pressure, fast decline in wellhead pressure, and low gas production, the flowback management system in the gas testing stage should be further optimized.
Ultra-low permeability gas reservoirs are complex in gas-water contact, and differ significantly in formation water occurrence state from conventional gas reservoirs. The occurrence state of formation water and the water saturation in such reservoirs were determined through mercury intrusion experiments and relative permeability tests, and the gas-water segregation was analyzed using the trap closure height method. Logging curves were used to predict the distribution of formation water saturation in different states for a single well, and the impact of formation water on productivity was assessed. The results show that the formation water in the study area mainly consists of strongly bound water and weakly bound water, with a small amount of movable water. No distinct gas-water segregation was observed. The clay water film is a key component of strongly bound water. In fine sandstone and the sandstone with high content of carbonate cements, the saturation of weakly bound water is higher. The movable water saturation in the study area is generally less than 6%, and the initial water production is low, exerting slight impact on productivity.
To reveal expansion pattern of steam chambers in heavy oil reservoirs during steam-assisted gravity drainage (SAGD), the time-lapse microgravity monitoring technology was employed to investigate the expansion pattern of SAGD steam chambers in the heavy oil reservoirs of the Jurassic Qigu formation in the H well block of the Xinjiang oilfield. This technology provided residual gravity anomaly data reflecting the remaining density of the reservoir. Using these data, a 3D least-squares inversion was performed to accurately depict the vertical distribution of the steam chambers. Furthermore, a method for interpreting the relationship between the steam chamber expansion pattern and residual gravity anomalies was proposed. The results indicate that the evolution of the steam chambers can be divided into three stages: rising, lateral expansion, and downward expansion. The proposed method can effectively explain the expansion patterns of the steam chambers in five well groups in the H well block, and its accuracy and reliability were validated with well temperature data. The method reveals the expansion patterns of the SAGD steam chambers in the reservoirs, providing a technical support for the efficient development of heavy oil reservoirs and aiding in the optimization of production control measures. It also offers a theoretical and practical foundation for similar reservoir development.
Water drive curve method is one of the important methods in dynamically calibrating recoverable reserves. This is a forward estimation method for water flooding reservoir without major adjustment measures and changing development modes, and with basically steady water flooding status. Setting the limit water cut at 0.98 lacks a solid scientific basis. Since the water drive characteristics vary significantly among different reservoirs, it is essential to select a water drive curve that best aligns with the reservoir’s actual behavior from the four water drive characteristic curves, rather than choosing the one with the lowest technically recoverable reserves, which will lead to weak reliability of calibration. Therefore, the four water drive characteristic curves and the production decline method were inverted and optimized for joint elimination, and a new relationship between water/liquid-oil ratio and production decline was established. This can determine the limit water cut and also ensure the uniqueness of the recoverable reserves calibrated by dynamic methods.
The Duong production decline model and modified Duong production decline model widely used for unconventional oil and gas reservoirs are disadvantageous in some aspects, such as incorrect definitions of characteristic parameters, inability to take zero as an independent variable, and lack of flow theoretical basis as a mathematical model. To address these problems, a new production decline equation was proposed by improving the mathematical model of relative permeability of oil phase in fractured reservoirs, and integrating the more applicable water phase relative permeability relational expression and the Welge equation. The new equation is similar in form to the modified Duong model, and can be transformed into the Arps production decline equation when the characteristic parameter A is zero, indicating that the new equation is a generalized production decline equation. The application of the new equation to the tight tuff oil reservoir of the Tiaohu formation in Block Ma56 of Tuha oilfield demonstrated a favorable effect, providing a valuable reference for similar unconventional reservoirs.
Regarding gas channeling during CO2 flooding in high-salinity, low-permeability reservoirs, taking the H3 block of Changqing oilfield as an example, an enhanced CO2 foam system with SiO2 nano-particales was constructed to evaluate its salt tolerance with respect to foam rheology, gas-liquid interfacial tension, liquid film thickness and permeability, and foam microstructure. A parallel core displacement experiment was conducted for the foam system to assess its profile control performance. Based on the experimental results, a foam system of 0.20%(OW-1)+0.30%(OW-4)+0.05%(SiO2) was developed under reservoir conditions, achieving a comprehensive index of 36,834 mL·min. The microscale salt tolerance evaluation indicates that, as compared with the foaming agents prepared at salinity of 46,357 mg/L and 500 mg/L, the developed foam system exhibits better rheological properties. The gas-liquid interfacial tension increased by only 1 mN/m at 10 MPa, and the liquid film permeability was improved by 0.14 cm/s. However, the foam system still maintains a robust skeletal structure. Thus, it is demonstrated with excellent salt tolerance at the microscale. Furthermore, for parallel cores with the permeability ratio of 15.55, the developed SiO2 nanoparticle-enhanced CO2 foam system improves the core profile by 97.28%, suggesting a remarkable enhancement in oil recovery, and demonstrating a good profile control performance.
In low-permeability reservoirs, CO2 flooding can enhance oil recovery and achieve CO2 geological storage. Based on the CO2 storage mechanisms, by using a numerical simulation method, a CO2 EOR and storage model considering CO2 structural storage, residual storage, and dissolution storage mechanisms was established. This model was used to analyze the sensitivity of injection-production parameters (e.g. water injection period, CO2 injection rate, injection-production ratio, lower limit of bottomhole flowing pressure in production wells, upper limit of bottomhole flowing pressure in injection wells, number of cycles, and gas-to-water slug ratio) on CO2 EOR and CO2 storage efficiency in low-permeability reservoirs under continuous gas injection and water-alternating-gas (WAG) injection modes. The results demonstrate that CO2 storage mechanisms have significant impacts on both CO2 EOR and CO2 storage. Under the mode of continuous gas injection, CO2 residual storage aids CO2 EOR but has minimal effect on CO2 storage, while dissolution storage hinders CO2 EOR but benefits CO2 storage. Under the mode of WAG injection, the storage mechanisms are less favorable for CO2 EOR but promote CO2 storage. These findings reveal the influences of storage mechanisms on CO2 EOR and storage under different injection modes.
Fault-controlled karst fractured-vuggy reservoirs that are characterized by well-developed fault systems exhibit complex reservoir spaces with significant discreteness and heterogeneity, posing great challenges to fault system modeling and description. Guided by the developmental and genetic patterns of fault-controlled karst reservoirs, a multi-scale and multi-constraint geological model of fault-controlled karst reservoir was established. Depending on the genesis of fault-controlled karst, the development of these reservoirs was divided into four stages (Ⅰ-Ⅳ). Based on the reservoir model of Stage Ⅳ, the fault-controlled karst reservoirs were divided into karst cave facies, dissolution pore facies, and dissolution fracture facies. A fracture development probability cube was constructed with multiple constraints which include ant weight sampling, fault displacement model, and fracture parameter characterization, and two groups of small-scale fractures of NW-SE and NE-SW trending were generated by applying a goal-oriented simulation algorithm. A fracture model of fault-controlled karst was established to reflect the development characteristics of the fractures in fault-controlled karst to the greatest extent, for reducing the uncertainty in fracture prediction. Thus, a new method for predicting fractures in fault-controlled karst reservoirs was formed. The reliability of the proposed model has been validated by the application in two wells, which may support subsequent development research.
The Chang 6 reservoir in the Shuanghexi block of Yanchang oilfield in the Ordos basin is characterized by low permeability. Conventional calculation methods for development indices are not conducive to geological research, policy formulation and cost control for oilfield development. The production decline patterns, producing degree of reserves by water flooding, injection-production ratio, water cut, injected water utilization, and recovery of the Chang 6 reservoir were analyzed. The results show that the production of the Chang 6 reservoir follows a hyperbolic decline pattern. The block has significant potential for water injection development, with the current control degree and producing degree of reserves by water flooding at 74.54% and 36.94%, respectively, and an injection-production connection rate of 27.27%. The optimal injection-production ratio is approximately 2.5. As the recovery efficiency increases, the water cut rises rapidly at the first and then slows down. Based on the water retention rate, water consumption index, and water flooding index, it is evident that in the late stage of development, the water injection effectiveness improves, leading to an increase in ultimate recovery. During the development process, the water cut rise rate should ideally be kept below 6.1%, and the reasonable formation pressure should be maintained above 9.1 MPa. Under these conditions, the final recovery in the study area is approximately 23%.
The Y reservoir in the JY oilfield is a typical elongated anticlinal structure, where the injected water readily advances along channel centerline, resulting in rapid water-flooding and rapid production decline in producers. Development of such reservoirs is challenging due to unclear factors influencing productivity, such as water body size, structural amplitude, and reservoir physical property. To address these issues, a fine numerical model was established for the elongated anticlinal reservoir, and an “edge waterflood + progressive producer-injector conversion” process was proposed. On this basis, the influences of water body size, structural amplitude, and reservoir physical property on productivity were analyzed. The results indicate that the “edge waterflood + progressive producer-injector conversion” process enhances the edge water energy to allow for bidirectional responses of well patterns, and also delays water breakthrough in producers at the structural high to significantly reduce the water cut of oil well. Furthermore, considering the structural characteristics of the reservoir, the production performance under different factors were quantified, reasonable limits for the parameters such as water body size, structural amplitude, and the ratio of vertical permeability to horizontal permeability were defined, and the adaptability of reservoir area under different reservoir physical properties was demonstrated. The study results provide valuable insights for improving waterflood effects in similar reservoirs.
The application of polymer flooding is expanding in Daqing oilfield, with the target transferring to poor-quality Class ⅡB reservoir. The existing polymers exhibit poor compatibility with the reservoir, the producing patterns of the profile remain unclear, and the effects of polymer flooding development vary greatly in different areas. To address these issues, through the analysis of field profile data statistics and laboratory experiments, the producing patterns and improvement methods for the profiles in Class ⅡB reservoir were investigated. In view of the producing status from water-injected layers, Lamadian area which is characterized by thick channel sandbodies and good reservoir properties exhibits the highest proportion of net pay producing, with the reservoir exploited frequently, multiple polymer breakthrough layers, and relatively high liquid absorption. The Sazhong and Sanan areas, with limited channel sandbodies and multiple thin sand layers with poor properties, show a low net pay producing proportion in the water flooding stage, after polymer flooding which is 12.5% and 15.4% higher than those in the water flooding stage, respectively. Additionally, the reservoirs with permeability ranging from 100 to 300 mD show a significant profile improvement. In view of the producing status of water-unswept layers, the strong vertical heterogeneity of Class ⅡB reservoir results in a high net pay unproducing proportion between layers. In this case, the profile should be improved by achieving balanced interlayer production. The alternating injection of salt-resistant polymer of high and low concentrations can delay the rise of water cut, enhance the liquid absorption in low-permeability layers, and significantly improve the recovery efficiency of polymer flooding. A pilot test on alternating injection of DS1200 salt-resistant polymer of high and low concentrations was conducted in A area of Beibei block in Lamadian, achieving satisfactory water-cut reduction and oil increment. This technology provides a guidance for improving the polymer flooding profiles of Class ⅡB reservoir in Daqing oilfield.
