Shale oil horizontal wells in the Lucaogou formation within the Jimsar sag vary greatly in productivity, with notable differences in water production rate. Main factors controlling this phenomenon remain unclear. Moreover, the existing sweet spot classification criteria fail to meet the requirements for fine development of shale oil in this area, and the interpretation of oil saturation and mobility based on the cutoff values from nuclear magnetic resonance (NMR) logging cannot realize precise identification of shale oil sweet spots. In this paper, based on the results of NMR logging and laboratory NMR testing, and through frequency division processing, NMR logging-based pore structure characterization by fluids, and elastic oil displacement simulation, the distribution of different types of fluids in shale oil reservoirs was characterized detailedly. The pore sizes for oil/water occurrence were delineated, and a model for evaluating movable oil amount was established to quantitatively characterize the fluid occurrence, pore size distribution, movable oil quantity, and other parameters. By integrating single-well testing and production data, the factors controlling horizontal well productivity were elucidated. The results show that horizontal well productivity is much more correlated to the large-pore light oil proportion (LOP) and movable oil porosity (MOP) than to porosity, oil saturation, NMR MOP and other parameters. The water influence index reflects the extent of formation water’s impact on shale oil flow, and given the same MOP, a smaller water influence index corresponds to a higher productivity and a lower water cut of a horizontal well. Based on large-pore LOP, water influence index and MOP, the shale oil sweet spots are classified into Class Ⅰ, Class Ⅱ and Class Ⅲ, with rapid decline in daily oil production and significant rise in water cut, which can serve as the basis for finely evaluating shale oil sweet spots in the Lucaogou formation.
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.
In order to evaluate the oil mobility in the tight sandy conglomerate reservoirs of the Triassic Baikouquan formation in the Mahu sag, the distribution characteristics of movable oil in typical rock samples from Type Ⅰ and Type Ⅱ reservoirs were compared through imbibition, centrifugation, and huff-n-puff tests. For the low-permeability conglomerate reservoirs in the Mahu sag, the imbibition oil recovery is related to the pore structure of the rock. The higher the proportion of small pores, the better the imbibition effect. After 144 hours of oil displacement by imbibition, the recovery rate can reach 30.9%, but the oil displacement process is slow, with low utilization of large pores. Under reservoir pressure of 40 MPa and reservoir temperature, during three cycles of CO2 huff-n-puff process, the recovery percent of each round increase, with the highest increase observed in the first cycle, reaching an oil exchange ratio of 27%. As the huff-n-puff cycle increases, the increment in recovery percent gradually decreases, and the oil exchange ratio of N2 huff-n-puff in the first cycle is 15%. Therefore, CO2 huff-n-puff has the best development effect.
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%.
Oxygen-reduced air injection is an effective technique for developing low-permeability oil reservoirs. Under reservoir conditions, oxygen-reduced air can undergo low-temperature oxidation reaction with crude oil, thereby enhancing oil recovery. Regarding the inadequate understanding of the mechanism underlying the oxygen-reduced air flooding for enhanced oil recovery (EOR) in the Guo-8 block of the Yuguo oilfield, isothermal oxidation experiments and long-core displacement experiments were conducted to investigate the influences of oil oxidation process and generated substances on EOR. The results of the isothermal oxidation experiments indicate that sedimentary substances are generated during the low-temperature oxidation process of light oil. With the increase of temperature, the degree of oxidation significantly increases, with the sedimentation of heavy components reaching 1.25×10-3 g/g at 89°C, 3.43×10-3 g/g at 100°C, and 5.02×10-3 g/g at 120 ℃. The results of the long-core displacement experiments demonstrate that the sedimentation of heavy components at different oxidation temperatures affects EOR. With temperature increasing, the timing of gas channeling delays, the sweeping effect improves, and the final recovery increases to 52.77%, 58.89%, and 65.23% at temperatures of 89°C, 100°C, and 120°C, respectively.
The depletion development of Y5 condensate gas reservoir in the Tarim basin encounters the challenges such as rapid decline in both reservoir pressure and well productivity, gradual decrease in produced gas-oil ratio, increase in condensate oil density and viscosity, and fast downgrading of development performance. Combining performance analysis and reservoir fluid component evaluation, the Y5 condensate gas reservoir was redefined as a layered condensate gas reservoir with oil ring and edge water and the thickness of the oil ring was determined through numerical simulation. To improve the development performance and enhance the condensate oil/gas recovery, a systematic investigation was conducted on the mechanism of enhanced recovery in the middle and late stages of depletion development of the condensate gas reservoir with oil ring. It is found that optimizing the well pattern and implementing cyclic gas injection can significantly improve oil and gas recovery. Gravity-assisted gas drive is recommended, with CO2 being the optimal injection medium, followed by reservoir gas. Based on reservoir type and enhanced recovery mechanism, a scheme of cyclic gas injection for enhancing the recovery of Y5 condensate gas reservoir was developed, with an expected oil recovery 29.96% higher than that of depletion development alone. Under this scheme, a cumulative gas volume of 0.19×108 m3 was injected, the reservoir pressure restored by 4.31 MPa, and the well productivity increased by 3.09 times compared to that before the scheme was implemented. The research results provide valuable reference for enhancing recovery in the middle and late development stages of similar reservoirs.
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.
To enhance the fracturing performance of coalbed methane (CBM) horizontal wells in the Qinshui basin, by analyzing the data of distributed optical fiber monitoring of water and gas production profiles, mud log, and well logging, the key factors influencing the fracturing performance were identified. These factors include coal quality, coal structure, drilling position, and perforation method. The middle to upper part of coal seam No. 3 in the Qinshui basin, characterized by low GR values, high coal quality, and intact coal structure, is identified as the optimal interval for fracturing stimulation. Based on the double GR curves, the drilling position of horizontal wellbore trajectory in the coal seam can be accurately determined, aiding in the selection of optimal fracturing interval and perforation method. When the drilling position is located in the middle part of the coal seam, conventional perforation method can be efficient. When the drilling position approaches the roof or is beyond the seam, downward directional perforation is preferred to effectively stimulate the high-quality upper part of the coal seam. When the drilling position is near the lower dirt band, upward directional perforation is advisable to target the high-quality middle part of the coal seam. Field application to 46 horizontal wells demonstrated that the single well production exceeded 2.5×104 m3/d and was stabilized at 2×104 m3/d, and the reservoir fracturing efficiency increased by 10% to 50%, recording a satisfactory development effect of the horizontal wells.
During the development of gas-cap reservoirs, crude oil, dissolved gas, gas-cap gas, condensate oil, and formation water may be produced simultaneously. Accurately calculating formation pressure and recovery percent of each phase is crucial for dynamic diagnosis and potential tapping of remaining oil and gas in such reservoirs. Current methods for calculating formation pressure fail to take water invasion into consideration, leading to uncertainty in production splitting, which increases the risks in subsequent adjustment and potential tapping. Through water influx fitting and Newton iteration methods, a new method for dynamic diagnosis of gas-cap reservoirs based on water invasion characteristic analysis and average formation pressure prediction was established. The application of this method in the Y3 gas-cap reservoir in the M oilfield indicates that crude oil and condensate oil account for 89.7% and 10.3% in the produced oil, respectively, and the produced gas contains 97.9% gas-cap gas and only 2.1% dissolved gas. The recovery efficiency of gas-cap gas and condensate oil is as high as 46.6% and 31.2%, respectively, while the recovery efficiency of crude oil and dissolved gas is merely 12.1% and 1.7%, respectively. These results are consistent with production test results.
Main pay zones of tight gas reservoirs are usually multiple layers of stacked channel sandbodies. Commingled production of these layers is commonly challenged by unclear contribution from each layer and undefined boundaries of sandbodies. Considering the morphological characteristics and different boundary sizes of channel sandbodies in the layers, and according to the principle of equivalent flow volume, a model of multi-layer commingled production well in tight gas reservoir was established. Then, based on the theory of modern production decline analysis, a method for determining the boundaries of channel sandbodies in tight gas reservoirs was proposed, and the production decline analysis charts for multi-layer commingled production wells were plotted. Finally, the production decline was discussed by boundary size, amount, and position of channel sandbodies, and the impacts of multi-layer channel sandbodies on production decline were clarified. The study shows that the production deline of multi-layer commingled production wells in tight gas reservoirs exhibits five stages. In the middle unsteady flow stage, it is possible to diagnose whether the boundary sizes of the sandbodies in each layer are equal. The smaller the range of channel sandbodies, the fewer the wide sandbodies, the smaller the proportion of wide sandbody, the poorer the stable productivity of the reservoir, and the more likely the increase in production decline rate occurs in the early and middle unsteady flow stages. The established method of production decline analysis provides a basis for evaluating the producing degree of each layer and determining reservoir stimulation treatments.
In order to investigate the production of crude oil during the imbibition period after hydraulic fracturing of the bedding shale in the Permian Lucaogou formation in the Jimsar sag, core imbibition replacement experiments and nuclear magnetic resonance (NMR) technology were combined to quantitatively describe the relative content of crude oil in different pores. Cores from the upper sweet spot in Jimsar sag were used in the experiments to identify the impacts of gravity, anisotropy, gravity differentiation, and hydraulic fracture width on imbibition replacement and quantitative characterization was conducted. The results show that during the spontaneous imbibition process of bedding shale, gravity plays a dynamic role, and the recovery of top imbibition is higher than that of horizontal imbibition. Anisotropy has a significant impact on imbibition of bedding shale, with a larger imbibition displacement of fracturing fluid into parallel bedding and a shorter period to reach imbibition equilibrium compared to vertical bedding, and imbibition recovery of parallel bedding is higher than that of vertical bedding. Gravity differentiation means that during the imbibition at the bottom of the core, the crude oil is displaced by imbibition and stays on the surface of the core to form an oil film, which prevents the fracturing fluid from further entering the matrix, deteriorating the imbibition effect. The recovery of imbibition at the bottom differs by 14.12% from the recovery of imbibition at the top. Given a simulated hydraulic fracture width of 2 mm, the volume of liquid involved in imbibition replacement is limited, causing a rapid decline of water saturation within the simulated fracture, which restricts further imbibition. Therefore, the fracture height should be oriented to pass through parallel bedding, so that the fracture width and the stimulated reservoir volume can be increased.
In order to explore the post-fracturing EOR technologies for efficient development of highly sensitive tight conglomerate oil reservoirs in horizontal wells in the Mahu sag, a simultaneous CO2 huff-n-puff test was carried out in the Mahu 1 well block. The results show that simultaneous CO2 huff-n-puff can enhance oil recovery of highly sensitive tight conglomerate reservoirs, and its oil displacement mechanisms mainly include extraction, miscibility, competitive adsorption, and expansive displacement. Fracture communication is the main cause of gas channeling. Through field regulation and control, synchronous soaking of well groups and gas channeling wells was achieved, ensuring the field implementation effect. Soaked by fracturing fluid, the clay minerals in the tested well group hydrate and expand, causing pore throat blockage, which affects CO2 swept range and results in a low interim oil exchange ratio. The simultaneous CO2 huff-n-puff test achieved favorable stimulation effects, with an interim oil increment of 3,983 tons and an oil exchange ratio of 0.36 in the tested well group. This test provides technical ideas and field experience for horizontal wells in enhancing oil recovery of highly sensitive tight conglomerate reservoirs after fracturing.
CO2 flooding is a technique that utilizes CO2 to enhance oil recovery (CCUS-EOR), and an effective means to reduce carbon emissions. To understand the interphase mass transfer in the petroleum system during CCUS-EOR, CO2/dry gas contact experiments were conducted to elucidate the changes in components of the petroleum system during the initial contact conditions at different pressures. The results indicate that during the initial contact between CO2 and oil, the interphase mass transfer for volatile and non-volatile components occurs through evaporative extraction, while the interphase mass transfer for intermediate components occurs through dissolution diffusion, which is stronger than evaporative extraction. As pressure increases, the volatile components show enhanced evaporative extraction, the non-volatile components reflect diminished evaporative extraction, and the intermediate components exhibit augmented dissolution diffusion. At relatively low pressure in the initial stage of gas injection, the interphase mass transfer of the petroleum system is dominated by evaporative extraction. As pressure increases, the mechanism of interphase mass transfer for volatile components shifts to dissolution diffusion. During the initial contact process between dry gas and oil, the interphase mass transfer for intermediate and non-volatile components is dominantly evaporative extraction. CO2 is more capable of evaporative extraction than dry gas.
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.
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.
To enhance the recovery of fracture-cavity carbonate reservoirs and investigate the oil-water two-phase flow behaviors under fluid-solid coupling effect, a Darcy-Stokes two-phase flow model was established based on the fluid flow patterns in different media. According to the principles of effective stress and the generalized Hooke’s law, an oil-water two-phase Darcy-Stokes coupled mathematical model suitable for fracture-cavity carbonate reservoirs was developed. Macroscopic and microscopic simulations of oil-water two-phase flows were conducted for carbonate reservoirs with and without fluid-solid coupling effect. The results show a significant difference in oil-water two-phase flow behaviors within the matrix zones of reservoirs with and without fluid-solid coupling effect, but a small difference within cavities. Water injection rate greatly influences oil-water flows in fracture-cavity carbonate reservoirs.
High-pressure water injection for capacity expansion is an effective method to enhance the recovery of fractured-vuggy reservoirs. However，the injection-production process during high-pressure water injection remains unclear. In this paper，three modes of high-pressure water injection for capacity expansion were proposed. Based on a dynamic model of high-pressure water injection for capacity expansion，the impacts of sensitivity parameters on the injection-production process during high-pressure water injection were simulated. The three modes of high-pressure water injection for capacity expansion were analyzed using actual wells drilled in the fractured-vuggy reservoirs in Halahatang oilfield. The high-pressure water injection for capacity expansion conforms to three modes：far-end low-energy，flow barrier，and near-end small reservoir. All three modes can realize effective production of far-end reservoirs to improve recovery efficiency. Flow barrier mode has the optimal EOR effect. The size of the near-end reservoir affects the time at which the water-injection indicator curve inflects，and the size of the far-end reservoir influences the difficulty degree of water injection after the water-injection indicator curve inflects. The fluid exchange index in the water injection process is greater than that in the production process，which indicates that the high-pressure water injection for capacity expansion is effective. The smaller the fracture closure pressure and stress sensitivity coefficient，the earlier the water-injection indicator curve inflects，and the higher the cumulative liquid production.
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.
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.
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.
