Surrogate reservoir models have emerged as efficient alternatives to approximate full-physics reservoir simulation while reducing computational costs. Even though existing studies have used synthetic models to test the feasibility of surrogate models, the application to actual reservoirs is limited. To employ the surrogate model in real-life history matching and field development optimization, key geological properties and frequent development operations need to be jointly considered. This study develops a full-scale surrogate reservoir model based on the Koopman neural operator (KNO) for actual three-dimensional (3D) oil reservoirs under waterflood operations. The model integrates static reservoir properties (permeability, net-to-gross ratio, and relative permeability) and dynamic development parameters (well placement and controls) as model inputs. A scientific sampling method that considers geological principles and monthly production operations ensures feasible and diverse training samples. The proposed 3D KNO architecture incorporates a learned grid layer to handle corner-point grids and leverages Fourier transforms to linearize nonlinear dynamics in high-dimensional space. After validating on a real oil field in China, the method demonstrates great capability in predicting pressure and saturation changes and oil production rates. By comparing the prediction performance with a baseline physics informed neural network model, the KNO model greatly outperforms the convolution neural network-based discrete mapping model. The prediction results by the KNO model align well with numerical simulations, which offers a robust and efficient tool for history matching and field development optimization.

As pore space serves as the primary migration pathway of radon in rock media, investigating the influences of pore structural characteristics on radon migration is essential. In this study, the rock pore structure was numerically reconstructed via the Quartet Structure Generation Set (QSGS) method, based on the characteristic parameters extracted from real rock pore models obtained from CT scanning. Quantitative comparison results indicate that the permeability and radon diffusion coefficient of the QSGS-reconstructed models are highly consistent with those of the CT-based model, which verifies the reliability and effectiveness of the QSGS method. A series of three-dimensional (3D) rock pore models with different porosities (η), distribution probabilities (Pd), and growth probabilities (G) were constructed using the QSGS method. The radon diffusion coefficient, tortuosity factor and permeability of these models under dry conditions were quantitatively determined. The relationship between the radon diffusion coefficient, water saturation and temperature was obtained using the tortuosity factor of the pore models and the unsaturated non-isothermal radon diffusion coefficient model. Furthermore, the relationship between the relative permeability of the air and water phases and water saturation was obtained by coupling the calculated permeability with the Brooks–Corey model. The results demonstrate that the η was positively correlated with both the radon diffusion coefficient and permeability, with a more pronounced positive correlation observed for permeability. Under low η conditions, Pd was positively correlated with both the radon diffusion coefficient and permeability; under medium-porosity conditions, Pd was positively correlated with the radon diffusion coefficient but negatively correlated with permeability; under high-porosity conditions, Pd exhibited no significant correlation with the radon diffusion coefficient, while it shows a negative correlation with permeability. G in the principal direction was positively correlated with the radon diffusion coefficient and permeability along the same direction, but negatively correlated with those along orthogonal directions. The radon diffusion coefficient was strongly negatively correlated with water saturation, and weakly positively correlated with temperature. With an increase in water saturation, the relative air permeability presented a nonlinear decrease characterized by a fast-then-slow trend, whereas the relative water permeability showed a nonlinear increase with a slow-then-fast pattern.

Two-Phase Relative Permeability Curves Based on In Situ X-ray Computed Tomography

Channel gating in bacteriorhodopsin-like channelrhodopsins with contrasting K+ and Na+ selectivity.

High-water-cut oil reservoirs are considered promising candidates for underground gas storage (UGS); however, the multiphase flow mechanisms during UGS construction in such reservoirs are inadequately understood. To address this gap, an experimental method is developed to simulate the multicycle injection-production process of UGS under high temperature and pressure conditions, facilitating the conversion of high-water-cut oil reservoirs into UGS. Additionally, a gas flooding experiment under high temperature and pressure is conducted to demonstrate the advantages of reservoir conversion in enhancing recovery rates, with a comparative analysis of oil displacement efficiency between two experimental groups. To quantify the process of displacing fluids and creating pore space for gas storage, the concept of liquid displacement efficiency is introduced. The results show that oil displacement efficiency increases progressively with cycles, peaking at Cycle 3, suggesting that initial cycles effectively mobilize residual oil and clear pore space, after which efficiency declines due to reduced movable oil. Continuous gas injection displaces significant liquid volumes with the volume of liquid displaced during gas injection phases exceeding the produced liquid volume by 26.3%. Gas relative permeability increased most significantly in Cycle 6, indicating a progressive improvement in gas flow capability. Compared with single-cycle gas flooding, six injection-production cycles enhance oil and liquid displacement efficiencies by 14.7% and 16.2%, respectively. These findings confirm that multicycle injection-production strategies not only enhance hydrocarbon recovery but also demonstrate the engineering feasibility of converting high-water-cut reservoirs into large-scale UGS.

Additive manufacturing of iron‐based metallic glass alloys enables the creation of customized soft‐magnetic components with unprecedented geometrical freedom. This work presents an efficient workflow for developing parameters for laser‐based powder bed fusion (PBF‐LB) of the Fe–Si–B–Cr–C metallic glass alloy Kuamet 6B2. The development focuses on combining checkerboard and double‐exposure printing to achieve low magnetic coercivity, high amorphous content, high relative density, and low residual stress. The workflow includes single‐tracks and melt‐pool imaging with Kerr microscopy to guide the selection of second‐exposure parameters. Samples are analyzed using X‐ray diffraction, magnetometry, magneto‐optical imaging, and electron backscatter diffraction. Using the optimized protocol, a ring‐shaped core with a diameter of 5 cm was produced and used for permeability testing. The relative permeability was 40 at 100 Hz due to crystalline grains up to a few microns in size. The size of the crystalline grains needs to be reduced for better soft‐magnetic properties. Designing novel Fe‐based soft‐magnetic metallic glass alloys for PBF‐LB manufacturing, with excellent soft‐magnetic properties, is an important future research direction.

Modeling fractional flow curves accurately is essential for optimizing reservoir performance and improving hydrocarbon recovery. This study introduces a robust analytical framework utilizing advanced computational techniques to predict fractional flow behavior. The model leverages Gradient Boosted Decision Trees (GBDT) and integrates key physical parameters such as water saturation, viscosity ratios, and relative permeability. The performance of the proposed framework was evaluated using data from reservoir simulations and experiments. The model demonstrated high predictive accuracy, achieving a Root Mean Square Error (RMSE) of 0.005, a Coefficient of Determination (R<sup>2</sup>) of 0.99, and a Mean Absolute Percentage Error (MAPE) of 1%. Compared to conventional fractional flow models based on Buckley-Leverett theory, which yielded an RMSE of 0.16 and a MAPE of 12.8%, the new approach showed significant improvement. Additionally, it outperformed other computational approaches, including Random Forest (RMSE: 0.02, MAPE: 10.4%) and Artificial Neural Networks (RMSE: 0.016, MAPE: 6.0%), providing both enhanced accuracy and consistency. A sensitivity analysis confirmed the robustness of the model across a range of viscosity ratios, showing strong alignment with physical principles, such as shock front behavior and saturation constraints. The practical utility of this model lies in its ability to accurately predict fractional flow under varying conditions, bridging gaps between analytical methods and data-driven techniques, while remaining computationally efficient. This development enhances the tools available for reservoir engineers, offering new insights for waterflooding strategies, enhanced oil recovery (EOR), and other multi-phase flow applications, with direct relevance to field operations.

Summary In recent years, advancements in microcomputed tomography (microCT) imaging technology and image processing have significantly enhanced our understanding of the internal structure of rock cores and the distribution of fluids during multiphase flow. Herein, we use microCT imaging to explore the impact of wettability on fluid flow in a sandstone rock at the pore scale in combination with relative permeability measurements. Steady-state experiments were conducted by the coinjection of decane and water into a sandstone core under different fractional flows (Fw = 0, 0.25, 0.5, 0.75, and 1) and wetting conditions. At each stabilized fractional flow, the system was imaged with microCT at a resolution of 6.7 µm under dynamic flow conditions. The sandstone core is initially tested in a clean state (i.e., water-wet condition), followed by aging in crude oil for 2 weeks at 90°C to create an aged state (i.e., oil-wet/mixed-wet condition). For the aged-state core, it was observed that the oil/water interface was dynamically changing under so-called steady-state conditions while the clean-state core provided less dynamic changes. Consequently, the aged-state core was also imaged under static conditions to capture fluid/fluid interfaces and common lines. Based on the scanned images, parameters such as contact angle, curvature, and pore occupancy were calculated, comparing differences between the clean-state and aged-state conditions. Furthermore, relative permeabilities were measured to analyze the flow characteristics at the continuum scale, providing a comprehensive understanding of pore-scale mechanisms linked to relative permeability behavior.

From interface dynamics to Darcy scale description of multiphase flow in porous media.

Evaluating rock wettability in CO2-water systems using relative permeability data: Implications for geologic CO2 sequestration in saline aquifers

Equivalent relative permeability curves of dual-continuum model to represent two-phase flow through karstified porous media

Gas-water relative permeability significantly affects the efficiency of fluid transport. However, due to the complex fracture-pore structures in coal, accurately predicting this property remains a challenge. This study presents a novel gas-water relative permeability model developed based on the fractal characteristics of coal fracture-pore structures. The model utilizes a tree-like bifurcation network and a curved capillary bundle approach to characterize the roughness of the fracture-pore system. By incorporating the distribution theory of gas-water phases in annular flow and integrating the cubic law with the momentum balance equation, two permeability solution methods were established, grounded in two-phase flow regimes and multi-scale structural features. Moreover, the structural clogging mechanism is incorporated into the model to further improve its applicability and accuracy. To validate the model, theoretical results were compared with experimental data obtained using a self-developed experimental system. Additionally, a sensitivity analysis was conducted to evaluate the influence of various parameters. Several key factors were found to affect coal permeability: permeability K g was positively correlated with maximum fracture opening (e smax ), maximum pore diameter (r max ), fracture opening fractal dimension (D e ), pore distribution fractal dimension (D r ), and length ratio (χ); and negatively correlated with fracture tortuosity fractal dimension (D T ), pore tortuosity fractal dimension (D t ), characteristic length (L), bifurcation angle (α), and residual water saturation (S w ). Notably, fracture structure parameters exert a much greater influence on permeability than pore structure parameters, highlighting the critical role of fracture networks in controlling permeability in fracture-pore such as coal rock. This model provides parameter support for developing CO 2 storage efficiency prediction models and offers scientific guidance for designing fracture network regulation strategies in CO 2 storage schemes.

The flow characteristics of water and gas are closely linked to pore structure of porous media, which is of critical importance across various scientific and industrial fields. In this study, synthetic porous media with varying grain sizes and porosity were generated, and their corresponding pore structures were characterized using pore network modeling. Furthermore, the intrinsic permeability, water retention curve, water-gas relative permeability and relative gas diffusivity of the synthetic porous media were simulated via pore network modeling. The results demonstrate that the pore networks extracted from images can effectively distinguish pore structural characteristics. Specifically, the mean pore diameter, throat diameter, and throat length were larger in coarse-grained media compared to fine-grained media of the same porosity. In contrast, fine-grained media exhibited higher values for pore number, throat number, and coordination number. Additionally, the distributions of pore diameter, throat diameter, throat length and coordination were found to follow a lognormal distribution. Porous media with coarse grains and larger porosity exhibit greater intrinsic permeability and relative gas diffusivity compared to media composed of finer grains or lower porosity. The water-retention curves were fitting by van Genuchten model, revealing an exponential relationship between parameter α and throat diameter (or pore diameter). But the parameter n did not show a clear trend across various synthetic porous media, which is attributed to the relatively narrow range of pore size distribution. Similarly, for water-gas relative permeability, the critical water saturation did not vary significantly across different porous media. A strong correlation was observed among the pore structural parameters, irrespective of grain shape and size. Both intrinsic permeability and relative gas diffusivity exhibited a power-law relation with the porosity as well as with pore or throat radius. Moreover, the relationship between intrinsic permeability and relative gas diffusivity can be expressed as k = 166.51(Dp/D0)0.98, which provides a direct means of estimating relative gas diffusion from intrinsic permeability directly.

Abstract In the process of coal mining, high gas and low-permeability coal seam mines face problems such as low gas extraction efficiency and frequent ground pressure activities. In order to enhance the permeability and gas extraction efficiency of coal seams, a carbon dioxide phase change fracturing and permeability enhancement method is raised. By arranging drilling holes and setting blasting parameters, the coal seam is fractured employing shock waves and stress waves generated by the phase transition of liquid carbon dioxide. The experimental results show that the natural gas flow rate in the borehole significantly increases after blasting, with an average increase of nearly 15 times. The permeability coefficient also increases from 0.610-0.920 (10-15 m2) before blasting to 1.90-2.98 (10-15 m2), and the permeability coefficient of some measurement points even increases several times. In addition, the pore structure of coal seams has undergone significant changes, with a rise in the number of medium and large pores and an improvement in pore connectivity. These results indicate that carbon dioxide phase change induced fracturing and permeability improvement technique can effectively raise the permeability and gas extraction efficiency of coal seams. The research provides a new technological means for the secure and effective mining of high gas and low-permeability coal seam mines. By raising the permeability of coal seams and gas extraction efficiency, it can reduce the risk of mine gas accidents and ensure the safe production of coal mines.

Increasing the recovery factor in oil fields is a critical task for improving reservoir performance and energy sustainability. This study investigates the novel application of graphene oxide (GO) nanoparticles as an enhanced oil recovery (EOR) agent in heavy oilfields, with an integrated multiscale approach combining laboratory experiments and numerical reservoir simulation. The nanofluids were optimized by evaluating the influence of salinity (300-900 ppm), pH (4-8), and GO concentrations (0.03-0.09 wt %) on interfacial tension (IFT) and wettability. Under optimal conditions (900 ppm brine, pH 8, and 0.09 wt % GO), the IFT decreased from 32.5 to 15.8 mN/m, and the contact angle shifted from 140° (oil-wet) to 90° (intermediate). Coreflooding tests confirmed the EOR potential of GO nanofluids, achieving 63.60% oil recovery compared to 56.72% with conventional waterflooding, an incremental gain of 7%. Relative permeability curves and advanced wettability indices (Lak and modified Lak) validated wettability alteration effects. To evaluate the scalability of this technology, the experimental data were incorporated into a numerical simulation using CMG-STARS. First, a history-matched core-scale model was developed to reproduce laboratory results. Then, a conceptual reservoir model was constructed using representative petrophysical properties from Colombian fields. The reservoir-scale simulation showed that nano-GO injection could yield an additional 402,431 barrels of oil over a 20-year period compared to conventional waterflooding, while maintaining a more favorable water cut. These findings highlight the potential of GO nanofluids as a viable and scalable EOR strategy for heavy-oil reservoirs. Future studies will focus on field-scale validation, economic feasibility, and environmental impact.

As a clean energy source, shale gas plays a vital role in supporting China’s strategic objectives of carbon peaking and carbon neutrality through its efficient development. Due to the low porosity, low permeability, complex pore structure, and strong heterogeneity of deep shale gas reservoirs, the gas-water two-phase seepage law and flow characteristics remain unclear. This study focuses on deep shale gas in the Western Chongqing block as the research subject. Through the gas-water displacement experiments combined with NMR techniques, the gas-water two-phase seepage laws and flow characteristics of the shale gas matrix-fracture system were revealed. The results show that: (1) In the water displacement gas experiment, formation water cannot break through the matrix-type sample, with its displacement velocity decreasing over time and eventually approaching zero. Under the same time conditions, the higher the displacement pressure, the faster the displacement velocity, and the higher the NMR signal. The matrix-fracture type sample breaks through in a short time, and the time when the NMR signal is stable is much less than that of the matrix-type sample. The displacement pressure is negatively correlated with the NMR signal. (2) In the reverse gas displacement experiment, the gas cannot break through the matrix-type sample. For the matrix-fracture type sample, as the displacement pressure increases, the water phase relative permeability increases, the irreducible water saturation decreases, the gas phase relative permeability decreases, the co-permeability zone slightly expands, and the equal permeability point shifts to the lower left. The findings provide a theoretical basis for the efficient development of shale gas in China.

Late-stage sandstone reservoirs often exhibit flow behavior markedly different from early performance, reducing recovery. This study quantifies two-phase flow in Jilin Oilfield sandstone cores to support production optimization. An oil–water displacement apparatus was built and unsteady-state relative-permeability tests were performed on core plugs from multiple well blocks. Permeability, pressure gradient, water saturation, and displacement efficiency were tracked over a range of injection multiples. Water-phase relative-permeability curves classify three seepage types: concave-down (12 cores, 2.10–46.17 mD), linear (7 cores, 1.58–12.23 mD), and concave-up (3 cores, 8.74–30.73 mD). Permeability is strongly negatively correlated with irreducible water saturation (R2 = 0.84) and positively correlated with residual oil saturation (R2 = 0.58), two-phase flow interval (R2 = 0.51), and movable oil saturation (R2 = 0.89); other relationships are weak. An increasing pressure gradient markedly improves displacement efficiency in low-permeability cores. Higher injection multiples further raise displacement efficiency across all permeability classes, but gains diminish with increasing permeability. Displacement efficiency also increases with water cut when used as a flooding-stage indicator in these unsteady-state tests.

To solve the relevant problem of analyzing the stability of non-isothermal oil displacement by a vapor-liquid mixture, a criterion is introduced that considers the densities of the oil and the vapor-liquid mixture, the viscosity and the relative phase permeability of these phases. A system of equations of mechanics of multiphase media is written considering nonisothermal filtration and cylindrical symmetry. The discontinuity ratios for the law of conservation of mass, momentum, and energy are considered. The presence of a critical pressure gradient has been established, at which the displacement process is still stable. The influence of fluid viscosities and relative phase permeabilities on the value of the introduced criterion is analyzed. It is shown that this value increases linearly with an increase in the ratio of oil viscosity to steam viscosity.

— Assessment of groundwater availability at a building project location in Ituku town to serve as source of water for the area was carried out. Initial geophysical evaluation using ABEM Signal Average System (SAS) 1000 Terrameter was made complimented by dowsing rod assessment to pin-point the location of sufficient groundwater resource. The geophysical survey measures the subsurface stratigraphy by estimating the variation in electrical properties of the geological formation which measures permeability in relation to depth. From the examinations, it was estimated that the proposed project location has sufficient water to support the costly venture of drilling of borehole to supply not just the project site owner facility but the neighborhood also. The geophysical and actual drilling of the borehole confirmed that sufficient water for Ituku town could be located at the depth of 175m below ground level. Sample test results confirm that the water is of good quality but there is the need for some form of treatment such as filtration and disinfection for its improvement before use. Physio-chemical analysis also indicates that Sodium Adsorption Ration (SAR) and percentage of Sodium Na+ are low but the Permeability Index (PI) of the location is high. Water resources professionals now have a useful baseline information on the depth and quality of water available in the area that should guide decisions on exploration and exploitation activities.

The Chang 7 shale oil reservoirs of the Yanchang Formation in the Heishui Area of the Ordos Basin display typical tight sandstone characteristics, marked by complex microscopic pore structures and limited flow capacity, which severely constrain efficient development. Using a suite of laboratory techniques—including nuclear magnetic resonance, mercury intrusion porosimetry, oil–water relative permeability, spontaneous imbibition experiments, scanning electron microscopy, and thin section analysis—this study systematically characterizes representative tight sandstone samples and examines the microscopic distribution of remaining oil, flow behavior, and their controlling factors. Results indicate that residual oil is mainly stored in nanoscale micropores, whereas movable fluids are predominantly concentrated in medium to large pores. The bimodal or trimodal T2 spectra reflect the presence of multiscale pore–fracture systems. Spontaneous imbibition and relative permeability experiments reveal low displacement efficiency (average 41.07%), with flow behavior controlled by capillary forces and imbibition rates exhibiting a three-stage pattern. The primary factors influencing movable fluid distribution include mineral composition (quartz, feldspar, lithic fragments), pore–throat structure (pore size, sorting, displacement pressure), physical properties (porosity, permeability), and heterogeneity (fractal dimension). High quartz and illite contents enhance effective flow pathways, whereas lithic fragments and swelling clay minerals significantly impede fluid migration. Overall, this study clarifies the coupled “lithology–pore–flow” control mechanism, providing a theoretical foundation and practical guidance for the fine characterization and efficient development of tight oil reservoirs. The findings can directly guide the optimization of hydraulic fracturing and enhanced oil recovery strategies by identifying high-mobility zones and key mineralogical constraints, enabling targeted stimulation and improved recovery in the Chang 7 and analogous tight reservoirs.