Water Relative Permeability Research Articles

Development of an improved deep network model as a general technique for thin film nanocomposite reverse osmosis membrane simulation

Due to the complexity of the inherent trade-off between water permeability and salt rejection in thin film nanocomposite reverse osmosis membranes (TFN-ROMs), conventional methods have not performed satisfactorily in predicting the performance of TFN-ROMs. In this study, to address the limitations of traditional machine learning in predicting the performance of TFN-ROMs, we developed a three-component residual artificial neural network (R-TNN) and learned from membrane properties, nanoparticle properties, and membrane performance to capture the complex trade-off between water permeability and salt rejection of TFN-ROMs. The coefficients of determination of the trained R-TNN model for relative salt passage (RSP) and relative water permeability (RWP) of TFN-ROMs were 0.910 ± 0.028 and 0.739 ± 0.028, respectively, which showed good performance compared to fully-connected neural network and conventional machine learning models even with small sample data. Meanwhile, subsequent ablation experiments conducted verified that the improvement of the R-TNN model is practical and effective. In addition, we conducted data scale experiments, which showed that the R-TNN model has the potential to become a generalized technical framework for the initial informationization era and the future big data era. Subsequently, we employed the partial dependence plot to mechanistically interpret the model. Specifically, we observed a positive correlation between nanoparticle size and both RWP and RSP, while the loading of nanoparticles initially promoted and later inhibited these performances. The validated R-TNN model can better learn the inherent trade-off between salt rejection and water permeability of TFN-ROMs, which implies that this study can provide decision support for the fabrication of membranes with more outstanding performances, which greatly contributes to the promising applications of TFN-ROMs.

Characterization of multiphase flow in shaly caprock for geologic CO2 storage

Geologic carbon dioxide (CO2) storage is a promising strategy for reducing its atmospheric levels, but concerns regarding potential leakage through faults or high-permeability inclusions in caprock highlight the importance of understanding its multiphase flow mechanism. In this study, a comprehensive experimental approach is introduced to characterize the pore structure of heterogeneous and fractured caprock and its relationship to water/CO2 relative permeability. It is observed that intact caprock with higher clay content exhibits a higher decrease in water relative permeability in the drainage: the exponent values in the Brooks-Corey model are 3.89 for sandy Eau Claire Shale, 5.04 for the clayey shale, and 6.77 for intact Opalinus Clay - consistent with observations for porous and tight rock. CO2 relative permeability also exhibits an exponential increase with CO2 saturation, which is more pronounced for sandy and fractured caprock due to the higher endpoint CO2 relative permeability and CO2 saturation. Moreover, a method to estimate relative permeability based on the water-CO2 capillary pressure response derived from the pore structure analysis is adopted and its results are compared to the direct measurements. This approach provides a better fit for intact clay-rich caprock but tends to underestimate the relative permeability as a function of fluid saturation for heterogeneous and fractured caprock. The pore structure-based estimation allows for pre-assessing the multiphase flow through caprock, although the direct measurements are highly recommended, especially for fractured materials.

Iso-Permeability Point Trail Method to Determine the Relative Permeability Curve for a New Amphiphilic Polymer Flooding

Amphiphilic-polymer flooding, which can increase water viscosity, decrease oil viscosity, and improve oil displacement efficiency, is a promising oil exploitation method for heavy oil. Due to oil–water emulsification, shear-thinning, and changes in oil viscosity when determining the relative permeability data of new amphiphilic polymers, the conventional J.B.N. method is not accurate. This paper presents a new method called the iso-permeability point trial method to determine the relative permeability curve by combining the J.B.N. method, the Corey model, and the relationship between water saturation and the relative permeability ratio. To avoid using polymer viscosity, a mathematical equation was derived based on the characteristics of the relative permeability curve. The results indicate that the new method is feasible and the obtained curve is more reasonable and smooth. The influence of concentration, permeability, and oil viscosity on amphiphilic-polymer displacement relative permeability was also analyzed, demonstrating that under the same water saturation, the water relative permeability is lower than that of water flooding but the oil relative permeability is bigger, which manifests as the iso-permeability point moves to the right and results in a lower residual oil saturation. In addition, the aforementioned trends are more obvious when the amphiphilic-polymer concentration is high, formation permeability is low, and oil viscosity is low.

Effective Relative Permeabilities Based on Momentum Equations with Brinkman Terms and Viscous Coupling

Summary The relative permeability expresses the mobility reduction factor when a fluid flows through a porous medium in the presence of another fluid and appears in Darcy’s law for multiphase flow. In this work, we replace Darcy’s law with more general momentum equations accounting for fluid-rock interaction (flow resistance), fluid-fluid interaction (drag), and Brinkman terms responding to gradients in fluid interstitial velocities. By coupling the momentum equations with phase transport equations, we study two important flow processes—forced imbibition (coreflooding) and countercurrent spontaneous imbibition. In the former, a constant water injection rate is applied and capillary forces are neglected, while in the latter, capillary forces drive the process and the total flux is zero. Our aim is to understand what relative permeabilities result from these systems and flow configurations. From previous work, when using momentum equations without Brinkman terms, unique saturation-dependent relative permeabilities are obtained for the two flow modes that depend on the flow mode. Now, with Brinkman terms included, the relative permeabilities depend on local spatial derivatives of interstitial velocity and pressure. Local relative permeabilities are calculated for both phases utilizing the ratio of phase Darcy velocity and phase pressure gradient. In addition, we use the Johnson-Bossler-Naumann (JBN) method for forced imbibition (with data simulated under the assumption of negligible capillary end effects) to calculate interpreted relative permeabilities from pressure drop and average saturation. Both flow setups are parameterized with literature data, and sensitivity analysis is performed. During coreflooding, Brinkman terms give a flatter saturation profile and higher front saturation. The saturation profile shape changes with time. Local water relative permeabilities are reduced, while they are slightly raised for oil. The saturation range where relative permeabilities can be evaluated locally is raised and made narrower with increased Brinkman terms. JBN relative permeabilities deviate from the local values: The trends in curves and saturation range are the same but more pronounced as they incorporate average measurements, including the strong impact at the inlet. Brinkman effects vanish after sufficient distance traveled, resulting in the unique saturation functions as a limit. Unsteady state (USS) relative permeabilities (based on transient data from single-phase injection) differ from steady-state (SS) relative permeabilities (based on SS data from coinjection of two fluids) because the Brinkman terms are zero at SS. During spontaneous imbibition, the higher effect from the Brinkman terms caused oil relative permeabilities to decrease at low water saturations and slightly increase at high saturations, while water relative permeability was only slightly reduced. The net effect was a delay in the imbibition profile. Local relative permeabilities approached the unique saturation functions without Brinkman terms deeper in the system because phase velocities (involved in the Brinkman terms) decreased with distance. In both systems, scaling and simulations demonstrate that the relative change in relative permeabilities due to Brinkman terms increases with the Brinkman coefficient, permeability, and inverse squared distance from the inlet.

Analyzing the impact of the interaction between hydraulic fracturing fluid and Kerogen on its wettability alteration

The increasing demand for exploring and developing unconventional reservoirs has sparked active research into hydraulic fracturing. However, the effect of hydraulic fracturing fluid on kerogen wettability alteration resulting from their interaction remains inadequately understood. This study aims to experimentally quantify the impact of hydraulic fracturing fluid on kerogen wettability alterations as a function of thermal maturity level. To achieve this objective, kerogens isolated from various organic-rich shale rocks of different types and maturities were mixed with synthetic hydraulic fracturing fluid at a temperature of 80 °C for 14 days. The resulting kerogen wettability was analyzed with the sessile drop method, Ion Chromatography (IC), and Attenuated Total Reflectance Fourier-Transform Infrared spectroscopy (ATR-FTIR), while Rock-Eval pyrolysis experiments were conducted as well to determine the kerogen geochemistry changes. After experiments, ANSYS-CFD was utilized to conduct numerical simulations of two-phase fluid flow to identify the impact of wettability on gas-water relative permeability.This study experimentally demonstrated that hydraulic fracturing fluid interacting with kerogen results in significant wettability alterations, which depend on the type and maturity of the kerogen. The Drop Shape Analyzer (DSA) results revealed that the air/water-contact angle decreased after the reaction for every type and maturity of kerogen, although the wettability alteration was greater with higher kerogen maturity. The ATR-FTIR findings revealed that mature kerogen isolates experienced a reduction in their hydrophobic functional groups, whereas kerogen isolates with relatively lower maturity demonstrated a potential loss of such groups, possibly resulting from oxidation. This trend toward hydrophilicity is consistent with the DSA results. The numerical modeling results indicated that the relative permeability was strongly influenced by the wettability of the formation. A water-wet formation led to a higher water relative permeability compared to the relative permeability of gas, and vice versa. These results represent a significant step forward in assessing multiphase fluid transport in organic-rich shales and hydrocarbon production.

Simulation study of affecting parameters during low salinity water injection in carbonate reservoirs: from core to field scale

Over the last decade, economic and environmental factors have led to low salinity water injection (LSWI) becoming one of the most important improved oil recovery methods. Although many results have been obtained from laboratory tests, only a few papers have been published regarding the modeling and simulating LSWI in carbonate reservoirs compared to sandstone reservoirs. This paper investigated the most affecting parameters on oil recovery during LSWI at the core and field scale. The published work focused more on the effective parameters related to ultimate oil recovery using LSWI. However, important parameters affecting the oil recovery rate were not investigated. We compared how important parameters affected the ultimate oil recovery factor and ultimate oil recovery rate. According to the results of this study, the salinity of injected water and curvature of oil relative permeability were the most important factors on the ultimate oil recovery factor. By reducing both of these parameters, more increment oil was recovered. By increasing the injection rate of water, the curvature of the water relative permeability, wettability, and the endpoint of oil relative permeability, the oil recovery rate also increased. Furthermore, threshold capillary pressure and the endpoint of relative permeability of water had inverse effects on oil recovery. Injecting low salinity water into the reservoir will change its wettability. As a result, it will change the properties of the reservoir and increase the production from the reservoir, resulting in more oil being produced. LSWI resulted in an increase of oil recovery factor of 5% and 11% respectively after 25 and 58 years in this case.

The differences on gas–water relative permeability characteristics of low and high rank coal and its controlling factors

A comprehensive comparison was conducted in terms of the gas–water relative permeability characteristics of high rank coals from south Qinshui Basin and low rank coals from Erlian Basin, China. The results show that: High rank coal samples are featured with a larger percentage of micropores. Compared with high rank coal samples, low rank ones display a smaller irreducible water saturation (S wo) and higher methane (K rg) and water (K rw) permeability and wider spans of two-phase flow region. High rank coal samples with a large percent of micropores are featured with a larger S wo and a narrower two-phase flow span. Gas displacement pressure increases K rg, while decreases K rw and S wo, and the changing rule is more pronounced in low rank coal samples. The effective stress is inversely proportional to the K rg and the span of two-phase flow, whereas proportional to the K rw. Influenced by effective stress, the dynamic changes of the cross points are more obvious in the low rank coal samples, however that of two-phase flow spans and S wo are not so pronounced. The conclusion will be helpful for CBM exploration and development.

The impact of grain size heterogeneity on the performance of low-salinity waterflooding in carbonate formations

Low-salinity waterflooding (LSWF) is a proven enhanced oil recovery method for many target fields. The efficiency of this technique depends on both operational factors as well as reservoir settings such as heterogeneity. Micro-scale rock heterogeneity can critically affect the performance of LSWF as it governs the flow path of the injected water, oil-brine-rock contacts and trapping mechanisms, thus sweep efficiency. However, there exist lack of experimental data and detailed understanding of the effect of grain size heterogeneity on LSWF performance. To address this gap, a systematic series of coreflooding experiments were designed using artificial calcite core plugs to investigate the effect of micro-scale heterogeneity, such as grain size and grain heterogeneity, on oil recovery factor by high-salinity waterflooding (HSWF) and LSWF. High salinity formation water, seawater, and diluted seawater were used as injection brines. For this purpose, two relevant grain size ranges (a) from 38 to 75 µm and (b) from 75 to 125 µm were considered to fabricate homogeneous plugs. Heterogeneous core plugs were made by mixing (a) and (b) grain samples. The artificial cores were initialized with the formation brine and crude oil, and aged to restore wettability. Then a set of coreflooding experiments were performed using the mentioned brine samples, in both secondary and tertiary modes by considering a shut-in period.The results reveal that grains size (or micro-scale) heterogeneity has a significant negative impact on both HSWF and LSWF performance and reduces the oil recovery efficiency of HSWF by approximately 15%. This is primarily attributed to the bypassing and entrapment of oil in heterogeneous cores. Moreover, the results show that regardless of the grain size, LSWF in homogeneous plugs result in almost similar recovery factors. The key finding of this study is that LSWF in heterogeneous plugs is more effective and recovers almost 10% more oil compared to HSWF. This is attributed to wettability alteration as indicated by the reduction of water relative permeability endpoint and delay of breakthrough time. The improvement in oil recovery was consistent with the results obtained from the flotation tests and dynamic IFT measurements. However, although LSWF outperforms HSWF in heterogeneous cores, the ultimate recovery factor becomes less in these plugs. Besides, superior performance of secondary flooding was observed compared to tertiary mode for LSWF, especially in cores with heterogeneous grain sizes, leading to almost 10% higher recovery factor.The novel insights gained through this research help identify the proper targets for LSWF in terms of small-scale heterogeneity and can be potentially applied in other water-based EOR techniques.

Experimental Study on the Influence of Wettability Alteration on Gas–Water Two-Phase Flow and Coalbed Methane Production

The surface wettability is important in the change in the relative permeability of gas and water. Due to the heterogeneous property of coal, it has a mixed wetting state, which makes it difficult to predict the change in permeability. To investigate the influence of different wettabilities on two-phase flow, a total of three different rank coal samples were collected and were treated with different chemicals. The alteration of the coal’s wettability, characteristics of gas–water flow, and relative permeability of the coal after the chemical treatments were analyzed. The research conclusions suggest that (1) the coal samples treated with SiO2 and H2O2 increased the hydrophilicity of the coal surface, while the coal samples treated with DTAB increased the hydrophobicity of the coal surface. Compared to SiO2, both H2O2 and DTAB can form a uniform wetting surface. (2) The wettability alteration mechanism among the three different chemical reagents is different. (3) All the chemicals can change the gas–water interface. The water migrates more easily through the cleats after H2O2 treatment, while it is more difficult for the water to migrate through cleats after the DTAB treatment. (4) There are two types of flow states of gas and water on different wetting surfaces. A slug flow is formed on a hydrophilic surface, while an annular flow is formed on a hydrophobic surface. (5) The crossover point and the residual water saturation of the relative permeability curves were influenced by the surface wettability.

Modeling of multiphase flow in low permeability porous media: Effect of wettability and pore structure properties

Multiphase flow in low permeability porous media is involved in numerous energy and environmental applications. However, a complete description of this process is challenging due to the limited modeling scale and the effects of complex pore structures and wettability. To address this issue, based on the digital rock of low permeability sandstone, a direct numerical simulation is performed considering the interphase drag and boundary slip to clarify the microscopic water-oil displacement process. In addition, a dual-porosity pore network model (PNM) is constructed to obtain the water-oil relative permeability of the sample. The displacement efficiency as a recovery process is assessed under different wetting and pore structure properties. Results show that microscopic displacement mechanisms explain the corresponding macroscopic relative permeability. The injected water breaks through the outlet earlier with a large mass flow, while thick oil films exist in rough hydrophobic surfaces and poorly connected pores. The variation of water-oil relative permeability is significant, and residual oil saturation is high in the oil-wet system. The flooding is extensive, and the residual oil is trapped in complex pore networks for hydrophilic pore surfaces; thus, water relative permeability is lower in the water-wet system. While the displacement efficiency is the worst in mixed-wetting systems for poor water connectivity. Microporosity negatively correlates with invading oil volume fraction due to strong capillary resistance, and a large microporosity corresponds to low residual oil saturation. This work provides insights into the water-oil flow from different modeling perspectives and helps to optimize the development plan for enhanced recovery.

A Method to Correct Steady-State Relative Permeability Measurements for Inhomogeneous Saturation Profiles in One-Dimensional Flow

AbstractTraditionally, steady-state relative permeability is calculated from measurements on small rock samples using Darcy’s law and assuming a homogenous saturation profile and constant capillary pressure. However, these assumptions are rarely correct as local inhomogeneities exist; furthermore, the wetting phase tends to be retained at the outlet–the so-called capillary end effect. We have introduced a new method that corrects the relative permeabilities, analytically, for an inhomogeneous saturation profile along the flow direction. The only data required are the measured pressure drops for different fractional flow values, an estimate of capillary pressure, and the saturation profiles. An optimization routine is applied to find the range of relative permeability values consistent with the uncertainty in the measured pressure. Assuming a homogenous saturation profile systematically underestimates the relative permeability and this effect is most marked for media where one of the phases is strongly wetting with a noticeable capillary end effect. Relative permeabilities from seven two-phase flow experiments in centimetre-scale samples with different wettability were corrected while reconciling some hitherto apparently contradictory results. We reproduce relative permeabilities of water-wet Bentheimer sandstone that are closer to other measurements in the literature on larger samples than the original analysis. Furthermore, we find that the water relative permeability during waterflooding a carbonate sample with a wide range of pore sizes can be high, due to good connectivity through the microporosity. For mixed-wet media with lower capillary pressure and less variable saturation profiles, the corrections are less significant.

The effect of H2S content on acid gas migration and storage in sandstone reservoir via numerical simulation

Acid gas injection, as one of the technologies for carbon dioxide capture, utilization and storage (CCUS) technologies, has been widely used in the development of sour oil and gas reservoirs. The current study numerically investigates the effect of hydrogen sulfide (H2S) content on the acid gas migration and storage in sandstone reservoir. The results suggest that the variations of acid gas density and viscosity induced by different H2S contents have little influence on the distribution of acid gas plume. However, the higher solubility of acid gas at higher H2S content results in a decrease of migration distance. The variation of relative permeability induced by different H2S contents has great influence on the acid gas migration. With the increase of H2S content, the horizontal migration distance decreases due to the decrease of gas relative permeability. Whereas, the water relative permeability increases and the gravity number increases with increasing H2S content. As a result, most of the horizontal flow occurs at the top of the reservoir and the lateral gas migration at the lower part of the reservoir is weakened. Furthermore, the variation of capillary pressure induced by different H2S contents has little influence on the distribution of acid gas plume during the injection period. However, capillary pressure hinders the migration of acid gas during post-injection period. Thus, for the sandstone reservoir with surface contamination, the horizontal and vertical migration distance decrease with increasing H2S content. For the sandstone reservoir with clean surface, the horizontal migration distance first increases and then remains unchanged with the increase of H2S content. After 50 years, the residual and mobile trapping of acid gas decrease with the increase of H2S content, and the solubility trapping of acid gas increases with the increase of H2S content.

Multiscale fractal-power-law model for shale extraction with water reflux case

After the shale reservoir is hydraulically fractured, the shale gas is transported to the horizontal well through various media. Hydraulic fracturing produces hydraulic fractures and generates secondary fractures. The hydraulic fractures and fracture induction areas are filled with gas and water phases. In this work, using power-law fracture distribution and porous media fractal theory, as well as accounting for seepage mechanisms in both the water and gas phases, a shale multi-scale mining model is constructed. The results of the study demonstrated that: (1) The degree of hydraulic fracturing is determined by a number of factors. An appropriate degree of hydraulic fracturing is more conducive to improving gas production. There is a competitive relationship between shale gas seepage and water reflux. Either above or below the moderate interval may lead to excessive water reflux and affect gas production. (2) Various properties of the water phase also influence the production results and pore structure evolution. A moderate maximum relative permeability of water and non-wetting phase entry pressure can contribute to a good pore structure progression and a more desirable gas production. (3) The contribution of hydraulic fracturing porosity to pore structure evolution is greater than the initial relative permeability of water and non-wetting phase entry pressure.

Effects of salinity alternation on relative permeability and capillary pressure as determined from steady-state-transient test

This paper aims the development of a new laboratory method for the simultaneous determination of phase relative permeability (Kr) and capillary pressure (Pc) for low salinity (LS) waterflooding. The proposed method is based on the so-called steady-state-transient (SSTT) method that uses steady-state and transient coreflood data, which allows calculating Kr and Pc from the same coreflood. A novel mathematical modelling is developed to determine Kr and Pc for two-phase multicomponent transports, where these parameters also depend on component concentrations, i.e. kr(s,c) and pc(s,c).Two sister cores from the same outcrop are used for the SSTT and wettability measurement experiments. The SSTT is performed using a sequence of HS injection → core re-initialization → LS injection to enable comparison of Kr and Pc curves for the same initial conditions. The modelling resultsusing a well-posed inverse algorithm - indicate a significant decrease in relative permeability for water, an insignificant increase in relative permeability for oil, a slight reduction in residual oil saturation, and a negligible downward shift in the Pc curve after LS water injection. This is explained by the formation damage caused by the mobilization of fine particles and the consequent pore-scale flow diversion due to pore plugging.

Hydrogel nanocomposite network elasticity parameters as a function of swelling ratio: From micro to macro flooding

Gel flooding is one of the most important cEOR methods. In this study, a Co[AM-AMPS-MA-AAC]/PEI-MBA nanocomposite, using zirconium or zinc nanoparticles, was synthesized to improve the performance of traditional hydrogels. FTIR and XRD tests confirmed the three-dimensional structure and homogeneous distribution of nanoparticles. The SEM and ESEM images revealed a homogeneous and 3D structure with an average pore size of 35 nm. The sweep strain test showed that the maximum storage moduli of Zr and Zn nanocomposites are 21,300 and 7700 Pa, respectively. The frequency sweep test showed linear viscoelastic behavior at various frequencies. According to TGA results, less than 1% of the nanocomposites degraded at reservoir temperatures. Network parameter calculations revealed the average pore size for Zr and Zn nanocomposites was 35 and 27 nm, respectively, showing high agreement with ESEM. The micromodel test showed a 22% increase in oil recovery, and the core-flooding test showed that Zr-nanocomposite caused a 98% decrease in water production and lowered the relative permeability of water by 37 times that of oil's relative permeability reduction. According to the research results, the synthesized nanocomposites have good structural and thermal strength, increase oil recovery, and decrease water production, making them a promising candidate for EOR processes.

A Novel Method for the Calculation of Oil–Water Relative Permeability for Tight Oil Reservoirs by Considering Nonlinear Seepage Characteristics

In view of the lack of clear physical significance of the parameters of the traditional nonlinear seepage models and the difficulty of obtaining accurate experimental measurements of the two-phase relative permeability curve, a nonlinear seepage model of a tight reservoir is established on the basis of fractal theory and boundary layer theory. The results show that the proposed model can comprehensively reflect the effects of reservoir matrix physical properties, reservoir fluid physical properties, wettability, and displacement-pressure gradient on the single-phase and two-phase nonlinear seepage characteristics of tight reservoirs. Furthermore, the introduction of the permeability loss factor makes the two-phase relative permeability model more representative of the morphological characteristics of the actual relative permeability curve and avoids the disadvantage that the relative permeability at the end point of the wetting phase has in the traditional model. Finally, by taking the tight core of Changqing Oilfield as an example, a sensitivity analysis of the proposed model is conducted, which proves the practical application of this model. The proposed model provides a convenient theoretical method for the accurate characterization of nonlinear seepage characteristics of tight reservoirs and is of great significance to the numerical simulation, productivity evaluation, and optimization of tight reservoirs.

Three-dimensional core reconstruction and performance evaluation of CO2 displacement in a tight oil reservoir

In this study, a three-dimensional tight sandstone core was reconstructed digitally using serials thin sections cut from a core sample used in laboratory carbon dioxide (CO2) flooding experiments. Based on the digital core, multiphase flow simulations were carried out to evaluate the performance of three prior laboratory-tested injection strategies: CO2 continuous injection, water alternative gas (WAG: CO2) injection, and cyclic CO2 injection. The chosen image-based reconstruction led to a close porosity and permeability match with the sampled core in an economical way. The numerical evaluation closely replicated the laboratory-tested procedures, thus providing realistic fluid distributions before CO2 injection. To determine saturation functions for CO2 injection after water flooding, sensitivities of endpoint relative permeability and capillary pressure to CO2 continuous injection were quantified. Water relative permeability was identified as a key factor. The saturation functions were used in a history match between simulations and laboratory data where close agreements were observed for all three CO2 injection strategies. Then critical enhanced oil recovery (EOR) operational parameters (soaking time, slug ratio, cycle size, and test duration) were optimized to maximize CO2 displacement performance, which led to the following observations: (1) While extended soaking after CO2 continuous injection increased incremental oil recovery, such increase was limited due to concurrent soaking during low-rate CO2 injection. (2) In WAG injection, CO2 and brine slug sizes and ratios were optimized: increasing the cycle size performed better than adjusting the slug ratio for favorable mobility control and efficient CO2 EOR. (3) For cyclic CO2 injection, the total CO2 injection volume was the most important factor, followed by the number of cycles, to allow CO2 diffusion into tight core to maximize the swept pore volumes. The history-matched simulations suggest that both WAG and cyclic CO2 injection can achieve high displacement effectiveness for the tight reservoir, compared with that achieved with slight soaking after CO2 continuous injection. The injected brine slugs in the WAG injection reduced the CO2 needed at the expense of reduced storage capacity. Compared to WAG, cyclic CO2 injection, though realizing the highest oil recovery and gas storage, requires more CO2.

Research Progress on Factors Affecting Oil-Absorption Performance of Cement-Based Materials.

With the wide application of petroleum resources, oil substances have polluted the environment in every link from crude oil extraction to utilization. Cement-based materials are the main materials in civil engineering, and the study of their adsorption capacity for oil pollutants can expand the scope of functional engineering applications of cement-based materials. Based on the research status of the oil-wet mechanism of different kinds of oil-absorbing materials, this paper lists the types of conventional oil-absorbing materials and introduces their application in cement-based materials while outlining the influence of different oil-absorbing materials on the oil-absorbing properties of cement-based composites. The analysis found that 10% Acronal S400F emulsion can reduce the water absorption rate of cement stone by 75% and enhance the oil-absorption rate by 62%. Adding 5% polyethylene glycol can increase the oil-water relative permeability of cement stone to 1.2. The oil-adsorption process is described by kinetic and thermodynamic equations. Two isotherm adsorption models and three adsorption kinetic models are explained, and oil-absorbing materials and adsorption models are matched. The effects of specific surface area, porosity, pore interface, material outer surface, oil-absorption strain, and pore network on the oil-absorption performance of materials are reviewed. It was found that the porosity has the greatest influence on the oil-absorbing performance. When the porosity of the oil-absorbing material increases from 72% to 91%, the oil absorption can increase to 236%. In this paper, by analyzing the research progress of factors affecting oil-absorption performance, ideas for multi-angle design of functional cement-based oil-absorbing materials can be obtained.

Characterization of the generalized permeability jail in tight reservoirs by analyzing relative-permeability curves and numerical simulation

This study comprehensively characterizes the boundary values of generalized permeability jail in tight reservoirs through relative-permeability curve analysis, numerical simulation, and economic evaluation. A total number of 108 relative-permeability curves of rock samples from tight reservoirs were obtained, and the characteristics of relative-permeability curves were analyzed. The irreducible water saturation (Swi) mainly ranges from 20% to 70%, and the residual gas saturation (Sgr) ranges from 5% to 15% for 55% of the samples. The relative-permeability curves are categorized into six types (Category-I to VI) by analyzing the following characteristics: The relative permeability of gas at Swi, the relative permeability of water at Sgr, and the relative permeability corresponding to the isotonic point. The relative permeability curves were normalized to facilitate numerical simulation and evaluate the impact of different types of curves on production performance. The results of simulation show significant difference in production performance for different types of relative-permeability curves: Category-I corresponds to the case with best well performance, whereas Categories-V and VI correspond to the cases with least production volume. The results of economic evaluation show a generalized permeability jail for Categories-IV, V, and VI, and the permeability jail develops when the relative permeability of gas and water is below 0.06. This study further quantifies the range of micro-pore parameters corresponding to the generalized permeability jail for a tight sandstone reservoir.

Pore-scale modeling of pore structure properties and wettability effect on permeability of low-rank coal

Permeability is a key parameter for coalbed methane development. Although the absolute permeability of coal has been extensively studied, wettability and pore structure properties continue to challenge the microscopic description of water-gas flow in coal. For this purpose, we reconstructed the microstructures of low-rank coal using micro-computed tomography (micro-CT) images. Pore geometry and pore-throat parameters are introduced to establish a relationship with absolute permeability. A dual-porosity pore network model is developed to study water-gas displacement under different wetting and pore structure properties. Results show that absolute permeability is significantly affected by pore geometry and can be described using a binary quadratic function of porosity and fractal dimension. Water-gas relative permeability varies significantly and the residual gas saturation is lower; the crossover saturation first decreased and then increased with increasing porosity under hydrophobic conditions. While the water relative permeability is lower and a certain amount of gas is trapped in complex pore-throat networks; the crossover saturation is higher under hydrophilic conditions. Models with large percolating porosity and well-developed pore networks have high displacement efficiency due to low capillary resistance and avoidance of trapping. This work provides a systematic description of absolute permeability and water-gas relative permeability in coal microstructure for enhanced gas recovery.