Gas Relative Permeability Research Articles

Flow parameter setting methods in numerical simulation of the unconventional reservoir and its impact on production

Abstract Tight reservoirs have poor physical properties and complex pore structures, and well production is often affected by the starting threshold gradient, stress sensitivity, and water blockage. In this paper, the numerical simulation method is used to make these three factors equal. In addition, normalized influence coefficient analysis and grey relation analysis are used to investigate the degree of influence of each factor on well production. In this study, three methods are developed to set the threshold pressure gradient according to the permeability zoning, and the effect of reservoir heterogeneity is considered to set the threshold pressure gradient for unconventional reservoirs. The equivalent accuracy of the numerical simulation of the threshold pressure gradient can be improved compared to the traditional method. Stress sensitivity and water blockage effects are equated by correcting for rock compressibility coefficient and gas relative permeability. The fit rate of the gas well production history is improved by 2–3% after considering complex factors. The inclusion of the complex factors reduces the reservoir energy mobilization. The threshold pressure gradient results in an additional pressure reduction of about 1.8 MPa around the gas well. Residual gas identification and development is helped by clarifying the effect of complex factors on formation pressure When only the effect of a single factor is considered, water blockage has the most significant effect on gas well production, followed by threshold pressure and the weakest stress sensitivity. When several factors are considered together, the effect of stress sensitivity is increased.

Modeling two-phase flow behaviour in a shale gas reservoir with complex fracture networks and flow dynamics

In this work, a robust and pragmatic method has been developed, validated, and applied to describe two-phase flow behaviour of a multifractured horizontal well (MFHW) in a shale gas formation. As for a fracture subsystem, its permeability modulus, non-Darcy flow coefficient, and slippage factor have been defined and embedded into the governing equation, while an iterative method is applied to update the gas/water saturation in each fracture segment within discrete fracture networks. Different from the traditional treatment that a water-source/sink in the matrix is simplified by assuming it as a constant term, a skin factor on a fracture face is defined and introduced to represent the change in relative permeability in the matrix domain at each timestep, while the adsorption/desorption term is incorporated into the diffusivity equation to accurately calculate the shale gas production by taking the adsorbed gas in nanoscale porous media into account. Then, the theoretical model can be applied to accurately capture the two-phase flow behaviour in different subdomains. The accuracy of this newly developed model has been confirmed by the numerical simulation and then it is extended to field applications with excellent performance. The stress-sensitivity, non-Darcy flow, and slippage effect in a hydraulic fracture (HF) are found to be obvious during the production, while the initial gas saturation in a matrix and HFs imposes an evident influence on the production profile. As for an HF with a high gas saturation, the dewatering stage is missing and water from the matrix can be neglected during a short production time. For the matrix subsystem, a high-water saturation in the matrix near an HF can affect gas production during the entire stage since gas relative permeability in the HF remains low. In addition, the adsorption/desorption in the matrix subsystem can increase gas production but decrease water production. Compared to the observed gas/water production rates for field applications, the solutions obtained from the method in this work are found to be well matched, confirming its reliability and robustness.

Corner flow effect on the relative permeability of two-phase flow in nano-confined porous media

Relative permeability is a critical factor clarifying the multiphase flow behavior in nano-porous media. However, most studies have focus on the circle flow, neglecting the corner flow effect. Therefore, in this work, a comprehensive relative permeability model considering the corner flow effect is proposed. We integrated the corner flow with the immiscible flow model and the confined liquid-gas phase equilibrium with the near-miscible flow model. Then it was validated against the experimental measured data, indicating the proposed model can well describe the two-phase flow in the confined space. Subsequently, sensitivity analysis of corner number, fractal dimension, minimum radius, and viscosity ratio were conducted. Results show that the corner flow effect is noticeable when corner number is less than 8. Under the optimal pore radius of 2 × 10−5 m, the gas relative permeability increases from 0.4909 to 0.9274 with corner number raising from 4 to 10. Under critical oil phase saturation of 0.175, increase of fraction dimension, minimum radius, and viscosity ratio leads to the significant decrease of oil relative permeability and increase of gas relative permeability. In addition, nano-confinement effect and CO2 injection will reduce the interfacial tension and increase the near-miscible relative permeability. When CO2 injection increase to 100% under oil saturation of 0.4084, the increment of oil relative permeability is nearly 67.2%. Interfacial intension-based interpolation method indicates that the confined fluid is more likely to be miscible than the bulk fluid. This relative permeability model provides deeper understandings of two-phase flow in the nano-porous media, which is benefit for the better development of unconventional reservoirs.

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.

Experimental study on dynamic pore-fracture evolution and multiphase flow in oil-saturated coal considering the influence of in-situ stress

The methane drainage in liquid-saturated coal is directly related to the multiphase flow in complex geological structures. In this study, the pore-fracture dynamic evolution induced by in-situ stress and the corresponding gas-liquid migration and morphology characteristics were investigated by a self-developed online LF-NMR triaxial stress system. The dynamic variation, obvious change, and slight response were occurred at the migration pore (MP＞3ms), percolation pore (0.3ms < PP < 3ms), and adsorption pore (AP<0.3ms) with the increased stress, and development of gas channel was contributed by MP (15%–20%), AP (5%–10%), and PP(0–5%) responding to the gas flooding. The pore-fracture successively experienced compression, dilation, expansion, and coalescence, and PP and MP dominated the fracture initialization and connection. The permeability is negatively correlated with the fractal dimension of the pore-fracture structure and is exponentially related to the porosity and MP porosity. The longitudinal shear fracture is beneficial for the gas-liquid migration, and the horizontal tension crack connects the scattered pore and branch fracture. The gas channel was influenced by the liquid capillary pressure and gas jiamin effect in poor pore-fracture and mainly influenced by the gas slippage effect, immiscible behavior, and fracture surface tension force in mature pore-fracture. The optimal gas channel occurred at the crack-propagation period, which was located at around 70% peak strength with 1.5md permeability, high liquid relative permeability and lower gas relative permeability. The findings provide significant insight into methane extraction.

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.

The effect of H2S content on acid gas migration and storage in shale reservoir by numerical simulation

AbstractAcid gas injection is one of the most effective strategies to deal with waste gas generated during the development of sour oil and gas reservoirs. This study numerically investigates the effect of H2S content on the acid gas migration and storage in shale reservoirs. The results indicate that the variations of acid gas density, viscosity, solubility, relative permeability, and capillary pressure caused by different H2S contents have great influence on the acid gas plume migration. When acid gas is in gas state, the maximum horizontal flow appears at the lower part of the reservoir after 5 years, and the horizontal migration distance first decreases and then remains unchanged with the increase of H2S content. Hereafter, the maximum horizontal migration distance appears at the top of the reservoir, and the horizontal migration distance first increases and then remains unchanged with the increase of H2S content. When acid gas is in liquid state, the maximum horizontal migration distance appears at the lower part of the reservoir in the early stage of injection. The horizontal migration distance decreases with the increase of H2S content. Subsequently, the maximum horizontal migration distance first decreases and then increases. The vertical migration distance increases gradually with the increase of H2S content until the acid gas reaches the top of the reservoir, and then the vertical migration distance remains unchanged. © 2023 Society of Chemical Industry and John Wiley &amp; Sons, Ltd.

The pore-network modeling of gas-condensate flow: Elucidating the effect of pore morphology, wettability, interfacial tension, and flow rate

The gas-condensate flow in the near-well region is significantly influenced by phase behavior, flow regimes, and pore geometries. In conventional gas-condensate reservoirs the key pore-scale parameters affecting gas and condensate relative permeabilities include velocity (i.e., pressure gradient), interfacial tension (IFT), wettability, and pore structure. To examine the impact of these parameters, three-dimensional (3D) and two-dimensional (2D) pore-network models (PNMs) were developed. A proposed compositional model was used to implement the cyclic process of condensate corner flow (film flow for circular tubes) and condensate blockage. Response surface methodology (RSM) was employed to achieve high accuracy in phase equilibrium calculations and to enhance computational speed.The 3D PNM simulations of gas-condensate core-flood experiments confirmed the consistency and accuracy of the implemented methodology. A parametric study of governing factors such as pore shapes, wettability, IFT, and flow rate was conducted using the developed PNMs. The findings revealed that pore geometry and contact angle dictate the condensate meniscus curvature and snap-off process in pore throats. The unblocking of throats by condensate bridges was primarily controlled by contact angle, IFT, and pore cross-section. A shift to neutral wetting substantially improved gas-condensate flow in higher IFTs and angular pore shapes.The positive velocity effect on low-IFT gas-condensate flow, known as the coupling rate effect, was more pronounced in simulations with lower contact angles, and its impact was negligible at neutral wettability, similar to the IFT effect. The simulation results and findings underscore the influence of each factor and offer a method for incorporating the effects of pore shape (i.e., formation type and structure), contact angle, velocity, and IFT in continuum scale simulations.

Numerical investigations on sc-CO2 gas sequestration in layered heterogeneous deep saline aquifers

Abstract Carbon capture and storage (CCS) technology is regarded as the feasible solution to mitigate CO2 emissions from the burning of fossil fuels in large-scale industries to meet energy demand. The storage of CCS requires the injection of CO2 gas captured from bulk sources into geological formations. Deep saline aquifers are the largest identified storage potential formations for injecting high volumes of gas. The safe storage of CO2 gas requires a better understanding of the gas migration and pore pressure buildup in the aquifer. In the present work, a numerical has been developed to study the various factors impacting the CO2 gas migration in the formation of both homogeneous and multi-layered deep saline aquifers. The numerical model has been history matched with an analytical solution and the plume thickness data reported by Nordbotten, J. M., M. A. Celia, and S. Bachu. (2005). “Injection and Storage of CO2 in Deep Saline Aquifers: Analytical Solution for CO2 Plume Evolution during Injection.” Transport in Porous Media 58 (3): 339–60. The saturation distribution and pressure buildup in the aquifer are different for each case. The relative permeability of gas increases in the homogeneous case. The drainage efficiency increases along with injection time in any formation. However, the drainage process is less in layered formation compared with homogeneous formation. The parameterized storage efficiency factor (Ɛ) is calculated to understand the storage capacity of the aquifer along the lateral direction near to injection well. The formations having low permeability in the top and below layers of the aquifer, the storage efficiency factor is high indicating more amount of gas is stored.

Pore‐Scale Determination of Residual Gas Remobilization and Critical Saturation in Geological CO2 Storage: A Pore‐Network Modeling Approach

AbstractRemobilization of residually trapped CO2 can occur under pressure depletion, caused by any sort of leakage, brine extraction for pressure maintenance purposes, or simply by near wellbore pressure dissipation once CO2 injection has ceased. This phenomenon affects the long‐term stability of CO2 residual trapping and should therefore be considered for an accurate assessment of CO2 storage security. In this study, pore‐network modeling is performed to understand the relevant physics of remobilization. Gas remobilization occurs at a higher gas saturation than the residual saturation, the so‐called critical saturation; the difference is called the mobilization saturation, a parameter that is a function of the network properties and the mechanisms involved. Regardless of the network type and properties, Ostwald ripening tends to slightly increase the mobilization saturation, thereby enhancing the security of residual trapping. Moreover, significant hysteresis and reduction in gas relative permeability is observed, implying slow reconnection of the trapped gas clusters. These observations are safety enhancing features, due to which the remobilization of residual CO2 is delayed. The results, consistent with our previous analysis of the field‐scale Heletz experiments, have important implications for underground gas and CO2 storage. In the context of CO2 storage, they provide important insights into the fate of residual trapping in both the short and long term.

The influence of irreducible water for enhancing CH4 recovery in combination of CO2 storage with CO2 injection in gas reservoirs

CO2 flooding to enhance gas recovery (CO2-EGR) with CO2 storage offers the prospects of significant environmental and economic benefits by increasing CH4 recovery while simultaneously storing CO2. Most studies ignored the interaction of water with CO2 and the formation rocks and the influence of irreducible water to enhance CH4 recovery combined with CO2 storage were poorly understood by core-flooding experiments. In this research, a numerical model of a five-spot well pattern was developed by benchmarking against the existing literature, and the model was further modified to investigate the effects of irreducible water on CO2-EGR and CO2 storage in gas reservoirs. The injected CO2 preferentially moved horizontally and gradually flowed vertically to flood CH4, making the displacement front an inclined CO2-CH4 mixing zone. The model with irreducible water changed from 0% to 40%, the CO2 sweep efficiency improved and the CH4 recovery increased by 4.37%. This could be attributed to the narrowing of the CO2-CH4 mixing zone and the change in displacement front from an inclined horizontal plane to a near arc plane with better stability. The cumulatively stored CO2 decreased by 21.24%, due to the early CO2 breakthrough and shut-in times. However, because more CO2 was dissolved in water and trapped in residual gas, the contribution of CO2 solubility trapping and CO2 residual trapping increased by 12.01% and 10.34% respectively, while CO2 structural trapping decreased by 22.86%, resulting in a significant increase in long-term storage security. Mineral reactions had a negligible influence on CO2-EGR and CO2 sequestration in the CO2 flooding process. The higher the salinity, the lower the amount of dissolved CO2, and the lower the CH4 recovery and cumulatively stored CO2, with decreased security of CO2 storage with limited impact. The higher the irreducible water saturation (Swi), the more CO2 dissolved, and the CH4 recovery and long-term storage security of CO2 improved with a reduction of cumulatively stored CO2. Changing the gas relative permeability (Krg) has a small effect for CH4 recovery and CO2 storage. This research may provide new insights into analyzing the mechanism of irreducible water on the influence of CO2-EGR and CO2 storage, laying a foundation for the optimization of CO2-EGR schemes and the implementation of field applications in water-bearing gas reservoirs with CO2 injection in the future.

Experimental determination of gas-water relative permeability for ultra-low-permeability reservoirs using crushed-rock samples: Implications for drill cuttings characterization

Relative permeability controls fluid flow through rocks, with applications to hydrocarbon production, geologic carbon and energy storage. However, significant challenges are associated with the measurement of relative permeability for rocks with matrix permeability in the microdarcy to nanodarcy range. The primary objectives of this study are therefore to 1) propose an integrated experimental and modeling approach for gas relative permeability (krg) evaluation using crushed-rock samples and 2) perform a proof-of-concept study to demonstrate that gas–liquid relative permeability can be determined for ultra-low-permeability (unconventional) reservoir samples that have been crushed to certain grain sizes (20–35 mesh size).In this study, the water vapor ad-/desorption technique was employed to provide a wide range of water saturations (Sw). The evolution of water distribution in the shale matrix with a change in Sw was investigated by using a modified low-pressure adsorption (LPA) technique. A recently-developed numerical model was modified to estimate effective permeability to gas at each saturation level. Four clay-rich shales from the Duvernay (Canadian) and Kyalla (Australian) formations were analyzed.The vapor ad-/desorption technique provided an efficient approach to saturate the studied samples. By changing relative humidity in sealed desiccators using different salt solutions, a maximum Sw of 83% was obtained for organic-matter rich samples, and 99% for organic-matter lean shales. As interpreted using the modified LPA technique applied at different saturation levels, water is held in films in mineral-associated macro-/mesopores, and can block access to organic-matter pores through the formation of water clusters, significantly reducing the accessible organic-matter porosity and gas effective permeability. Imbibition krg decreases rapidly and significantly (over 90%) when Sw reaches approximately 0.3–0.4 for samples containing significant amounts of water-sensitive clay minerals (Kyalla #2) and TOC (Duvernay #2). Relative permeability hysteresis occurs for Duvernay #2 and Kyalla #1. Overall, the use of crushed-rock samples (non-matrix/fracture system), and application of the vapor sorption technique, results in a small amount of hysteresis.A laboratory-based method for measuring gas relative permeability of ultra-low-permeability reservoirs using crushed-rock samples is provided for the first time, with important applications to the energy and carbon capture industries.

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.

Gas relative permeability evaluation in tight rocks using rate-transient analysis (RTA) techniques

The evaluation of effective and relative gas permeability is critical for modeling hydrocarbon recovery from low-permeability (unconventional) reservoirs, and for evaluating the potential for clean energy pathways such as carbon capture and sequestration and hydrogen storage in subsurface. Nevertheless, due to the low flow rates and long experimental times associated with low-permeability (nanodarcy/microdarcy range) sample testing, measuring relative permeability through conventional techniques is technically challenging, time-consuming, and expensive. Additionally, and importantly, none of the routine laboratory techniques for measuring relative permeability can mimic the boundary conditions under which wells are produced from, or injected into, in the field.For the first time, effective and relative gas permeability of partially-saturated low-permeability sedimentary rocks were investigated using state-of-the-art core analysis techniques based on rate-transient analysis (RTA). Conventional and new straight-line analysis methods, commonly applied to production data in the field, were used to estimate effective gas permeability of core plugs under variable stress conditions and water saturations. Five low-permeability siltstone and organic/clay-rich samples, differing in mineralogy, porosity, and pore size distribution, were analyzed for proof-of-concept testing.The observed flow regimes consist of transient linear flow followed by boundary-dominated flow regimes, as previously reported for field data. Satisfactory correlation (average coefficient of variation less than 7%) between permeability estimates using different RTA techniques demonstrates the applicability of this method for effective and relative permeability assessment of partially-saturated ultra-tight reservoirs (down to less than 1.0∙10−5 md). Importantly, test times after the initiation of the production phase, were on the order of minutes, which is significantly shorter than those commonly achievable using conventional techniques (e.g., hours using pulse-decay gas permeability testing). Effective gas permeability (from 1.5∙10−3 to 7.5∙10−6 md), and slip factor (from 715 to −286 psia−1), decreased with increasing water saturation (0–53%), reflecting the lower contribution of slip flow to gas transport. Effective gas permeability decreased with increasing effective stress (500–4000 psia), likely due to reduced effective (transport) pore throat size and increased tortuosity. The reduction of slip factor and the observed stress dependency with water saturation is attributed to the channel flow mechanism.

Effect of Temperature on Two-Phase Gas/Oil Relative Permeability in Viscous Oil Reservoirs: A Combined Experimental and History-Matching-Based Analysis

Summary Thermal enhanced oil recovery (TEOR) is the most widely accepted method for exploiting the heavy oil reservoirs in North America. In addition to improving the mobility of oil due to its viscosity reduction, the high temperature down in the hole due to the injection of the vapor phase may significantly alter the fluid flow performance and behavior, as represented by the relative permeability to fluids in the formations. Therefore, in TEOR, the relative permeabilities can change with a change in temperature. Also, there is no model that accounts for the change in temperature on two-phase gas/oil relative permeability. Further, the gas/oil relative permeability and its dependence on temperature are required data for the numerical simulation of TEOR. Very few studies are available on this topic with no emerging consensus on a general behavior of such effects. The scarcity of such studies is mostly due to experimental problems to make reliable measurements. Therefore, the primary objective of this study was to overcome the experimental issues and investigate the effect of temperature on gas/oil relative permeability. Oil displacement tests were carried out in a 45-cm-long sandpack at temperatures ranging from 64°C to 210°C using a viscous mineral oil (PAO-100), deionized water, and nitrogen gas. It was found that the unsteady-state method was susceptible to several experimental artifacts in viscous oil systems due to a very adverse mobility ratio. However, despite such experimental artifacts, a careful analysis of the displacement data led to obtaining meaningful two-phase gas/oil relative permeability curves. These curves were used to interpret the relative permeability curves for gas/heavy oil systems using the experimentally obtained displacement results. We noted that at the end of gasflooding, the “final” residual oil saturation (Sor) still eluded us even after several pore volumes (PVs) of gas injection. This rendered the experimentally determined endpoint gas relative permeability (krge) and Sor unreliable. In contrast, the irreducible water saturation (Swir) and the endpoint oil relative permeability (kroe) were experimentally achievable. The complete two-phase gas/heavy oil relative permeability curves are inferred with a newly developed systematic history-matching algorithm in this study. This systematic history-matching technique helped us to determine the uncertain parameters of the oil/gas relative permeability curves, such as the two exponents of the Corey equation (No and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted, except these four parameters (i.e., Corey exponents, true residual oil saturation, and gas endpoint relative permeability) were interpreted from simulations rather than from experiments. Based on our findings, a new correlation has been proposed to model the effect of temperature on two-phase gas/heavy oil relative permeability.

An improved gas–liquid–solid coupling model with plastic failure for hydraulic flushing in gassy coal seam and application in borehole arrangement

Hydraulic flushing can increase the efficiency of gas extraction by artificially modifying the coal reservoir. Considering the plastic failure of coal mass, an improved gas–liquid–solid coupling model for hydraulic flushing and gas extraction is constructed. The parameter evolution in the hydraulic flushing process was numerically investigated to determine the optimal borehole arrangement of hydraulic flushing. The results show that the relative permeability of gas gradually increases with the initial dewatering. The gas rates of both regular extraction and hydraulic flushing enhanced extraction show an increasing–decreasing trend. An increased and delayed peak gas rate is observed comparing with the regular extraction, caused by the hydraulic flushing induced new fractures. The area around of borehole is divided into the failure zone, the plastic softening zone, and the elastic zone after hydraulic flushing. The failure zone has the greatest increase in coal permeability, followed by the plastic softening zone, while the elastic zone keeps no significant change. The larger difference between the horizontal stress and vertical stress, the more obvious the elliptical shape of the permeability change area near the borehole, as well as the pressure drop in the elliptical zone. With the increase in the hydraulic flushing radius, the permeability increasing zone and gas pressure decreasing zone gradually increase. Subsequently, the equivalent effective radius and equivalent influencing radius were obtained, as well as the optimal borehole spacing for hydraulic flushing by cross-layer drilling. Finally, the optimal borehole spacing is obtained for different borehole diameters and efficient extraction times. These provide a theoretical guidance for field application of hydraulic flushing in a low-permeable coal seam.

Wettability Alteration to Reduce Water Blockage in Low-Permeability Sandstone Reservoirs

This study is a continuation of our previous work, which focused on a near-wellbore water blockage alleviation by applying a thermally cured silane-functionalized benzoxazine to modify rock wettability. In this new analysis, we have demonstrated that the resin can be applied in low-permeability sandstones (approximately 15 mD as opposed to 100 to 200 mD in the previous study) to change the rock surface wettability from water-wet to intermediate gas-wet. We have also demonstrated that curing temperatures as low as 125 °C (as opposed to 180 °C in our previous study) can significantly change wettability, indicating surface functionalization through the silane moiety and ring-opening polymerization of the benzoxazine moiety. In drainage core flooding experiments at 2.5 wt.% resin loading, compared to untreated samples, brine recovery increments of 6.3 to 6.9% were obtained for curing temperatures of 125 to 180 °C, respectively. A maximum 20% increment in the end-point relative gas permeability was achieved at a curing temperature of 180 °C. A coupled experimental and numerical study, conducted at core and wellbore scales, demonstrates the potential effectiveness of our chemical treatment in improving gas productivity at the field scale. Reservoir simulations indicate a 2.9 to 10.6% improvement in gas deliverability for a treatment radius of 4 to 16 m, respectively.

Experimental study on coal fines migration and effects on conductivity of hydraulic fracture during entire coalbed methane production period

During the dewatering and gas producing stages in coalbed methane (CBM) development, the migration of coal fines in hydraulic fractures substantially threatens the stability and high yield of the gas production process. In this study, three factors—coal fines concentration, coal fines size, and fluid flow rate—were considered to experimentally investigate the migration of coal fines in hydraulic fractures and determine their influence on fracture conductivity during the entire CBM production period. To mitigate the coal fine migration, we experimentally investigated the effectiveness of two types of treatments: physical multistage sand fracturing technology that prevents the coal fines from entering the fracture by utilizing the coal fines barrier, and chemical additives that serve as dispersants or fixed agents. Moreover, a new core preparation method and an efficient fine-coal-fines preparation method were proposed. After injecting the gas bubble in the experiment, a typical strip-type coal-fines distribution was observed in the sand pack, which negatively influenced the gas permeability and gas relative permeability at the gas production stage. Specifically, the conductivity of the sand pack was inversely dependent on the amount of coal fines entering it, and the conductivity rapidly decreased as the mass ratio of the injected coal fines to sand reached 0.625% in the experiment. At the gas production stage, the conductivity of the sand pack injected with a suspension of fine coal fines (<20 μm) was only ∼20% of that injected with a suspension of large coal fines (>20 μm), i.e., finer coal fines could comfortably enter the sand pack and severely reduce its conductivity. Furthermore, a high fluid-flow rate deteriorated the conductivity by driving coal fines through smaller pores, where the possibility of blockage is higher and the formation of coal fines agglomerates is facilitated. Overall, at the gas production stage, the conductivity of the sand pack with a coal fine barrier was 500% higher than that without a coal fine barrier, and the multistage sand fracturing technology delivered appropriate performance in alleviating the conductivity reduction by preventing the migration of finer coal fines into the hydraulic fracture. However, the chemical additives suggested in references, including sodium bicarbonate (NaHCO3) that can affix the coal fines and the fine dispersant sodium lignin sulfonate, delivered inferior performance and even aggravated the conductivity deterioration.

Experiment on the Gas Permeability and Gas–Water Relative Permeability in High-Rank Coal with a Self-Developed Device

Water saturation, displacement pressure, and gas type are essential factors affecting the seepage characteristic of fluid in coal due to the swelling induced by gas adsorption. However, the understanding of the seepage behavior of water, CH4, and CO2 in coal seams is still poor owing to the lack of research. In this work, a series of gas permeability and gas–water relative permeability experiments were conducted by our self-developed device. The results can be summarized as follows: (1) with the increase in water saturation, the gas permeability decreased rapidly at first and then reduced sharply again after a period of slow decline; (2) the two-phase flow span showed no significant difference for He–water and CH4–water systems under different displacement pressures, but it increased for CO2-water system. The different behaviors of the two-phase flow span suggested that the effect of displacement pressure on relative permeability properties is dependent on the gas type. (3) The CO2–water relative permeability showed a sizeable two-phase flow span compared to the He–water or CH4–water system under the same displacement pressure, and the gas relative permeability decreased obviously in the following sequence: He > CH4 > CO2. The concept of relative permeability surface was proposed based on the experimental results. A parametric interpolation method was applied to determine the relative permeability surface, which could be used to accurately describe the flow characteristics of fluids in a mixed gas–water system.

Novel Discrete Fracture Network Model for Multiphase Flow in Coal

Multiphase flow intensely affects the movement and accumulation of other fluids in coal and plays an essential role in predicting the permeability of coal during coalbed methane (CBM) production. Fractures have played a decisive role in the transport of CBM after hydraulic fracturing has occurred. In this study, a multiscale pore network model (PNM) was constructed on the basis of focused ion beam scanning electron microscopy (FIB-SEM) image results. Additionally, a novel discrete fracture network model, fracture–pore network model (F–PNM), was proposed to investigate the effect of fracture density, fracture developing direction, and wettability on multiphase flow. The results reveal that the permeability of F–PNM increases with the increase of the fracture density, which could be the result of the predominance of snap off. The permeability decreases as the angle between the fracture and flow direction increases; initially, the permeability decreases steeply and then it tends to remain stable; and for angles between 0° and 15°, the permeability decreased by as much as 61.8%. Moreover, the wettability of coal has limited impact on its water relative permeability; however, it has a measurable effect on gas relative permeability, which could be owing to water accumulation on the coal surface under different wettability conditions. A good wetting performance would have a negative effect on the CBM production and reduce flowback efficiency.