Search Results (21)

The Late Permian coal-bearing strata in western Guizhou Province, South China, are developed with multiple coal seams and rich in coalbed methane (CBM) resources. Controlled by the sealing layers within the coal-bearing strata, multiple vertically superposed independent CBM systems were formed, which complicates the CBM accumulation characteristics and limits CBM development. Through systematic sampling of the main coal seams and different lithologic strata in Borehole 101 on the southeastern limb of the Agong Syncline in western Guizhou, mercury intrusion porosimetry (MIP) and Klinkenberg permeability experiments were conducted on coal and rock samples. The results show that the coal samples have an average pore volume of 0.0417 mL/g, an average porosity of 5.37%, an average mercury withdrawal efficiency of 69.79%, and an average well test permeability of 0.3743 mD; the rock samples have an average pore volume of 0.0064 mL/g, an average porosity of 1.43%, an average mercury withdrawal efficiency of 7.88%, and an average Klinkenberg permeability of 0.0128 mD. The pore and permeability conditions of rock layers are significantly poorer than those of coal seams, which favorably contributes to the formation of effective sealing layers between coal seams and facilitates the CBM preservation. Mudstone and argillaceous siltstone in the coal-bearing strata, characterized by their low porosity and permeability, are suitable as effective gas and water barriers between coal seams. Based on a comprehensive analysis of the vertical variations in permeability, porosity, and gas-bearing characteristics of Borehole 101, the Upper Permian coal-bearing strata are preliminarily divided into four independent CBM-bearing systems. These systems are separated by tight rock layers with extremely low permeability and porosity, and their division aligns closely with the third-order sequence stratigraphic framework. The findings can provide a theoretical basis for deepening the understanding of CBM accumulation mechanisms in multi-seam regions and optimizing the orderly CBM development models. Full article

Underground hydrogen storage (UHS) in depleted oil and gas reservoirs is regarded as a highly promising subsurface option due to its large storage capacity. In such reservoirs, the pore structure provides the primary space for hydrogen storage and governs matrix flow and diffusion. Tree-shaped fracture networks generated by hydraulic fracturing or cycling injection–production typically exhibit much higher transmissivity and serve as the dominant pathways. In this study, the geometry of multilevel branching fractures was parameterized, and two classes of tree-shaped fracture configurations were constructed, including point–line-type (PLTSF) and disc-shaped (DSTSF) networks. Analytical models were developed to evaluate the equivalent permeability of tree-shaped fracture networks with either elliptical or rectangular cross-sections. The Klinkenberg slip correction and a gas-type factor associated with molecular kinetic diameter were incorporated. The apparent equivalent permeability of hydrogen (k_app,H2) was quantified and compared with those of nitrogen and methane under identical conditions. The main findings were as follows: (1) the fracture width ratio (β) was identified as the primary factor controlling network conductivity, while the height ratio (α) amplified or attenuated this effect at a given β; (2) as the main-fracture aspect ratio, the branching order (n) or branching angle (θ) increased, the rectangular cross-sections were more favorable for maintaining higher permeability compared to the elliptical cross-section; (3) under typical operating pressures of 5–30 MPa, the apparent permeability of hydrogen was approximately 2–9% higher than that of methane and nitrogen; and (4) by introducing the fracture volume fraction, the REV-scale equivalent-permeability expression was derived for fractured rock masses containing tree-shaped fracture networks. The proposed framework provides a theoretical basis and parametric support for quantifying fracture flow capacity for UHS in depleted reservoirs. Full article

Large-scale underground hydrogen storage in saline aquifers requires an understanding of hydrogen–brine two-phase flow properties, particularly relative permeability, which influences reservoir injectivity and hydrogen recovery. However, such hydrogen–brine relative permeability data remain scarce, hindering the predictive modeling of hydrogen injection and withdrawal. In this study, steady-state hydrogen–brine co-injection coreflood experiments were conducted on an Austin Chalk core sample to measure the relative permeabilities. Klinkenberg slip corrections were applied to the gas flow measurements to determine the intrinsic (slip-free) hydrogen permeability. The core’s brine permeability was 13.2 mD, and the Klinkenberg-corrected hydrogen gas permeability was 13.8 mD (approximately a 4.5% difference). Both raw and slip-corrected hydrogen relative permeability curves were obtained, showing that the gas-phase conductivity increased as the water saturation decreased. Gas slippage caused higher apparent gas permeability in the raw data, and slip correction significantly reduced hydrogen relative permeability at lower hydrogen saturations. The core’s irreducible water saturation was 39%, at which point the hydrogen relative permeability reached 0.8 (dropping to 0.69 after slip correction), which is indicative of strongly water-wet behavior. These results demonstrate a measurable impact of gas slippage on hydrogen flow behavior and highlight the importance of accounting for slip effects when evaluating hydrogen mobility in brine-saturated formations. Full article

Fossil fuels, such as coal and hydrocarbons, are major drivers of global warming and are primarily responsible for worldwide greenhouse gas emissions, including carbon dioxide CO₂. The storage of CO₂ in deep saline reservoirs is acknowledged as one of the top practical and promising methods to reduce CO₂ emissions and meet climate goals. The North Dakota Industrial Commission (NDIC) recently approved the fourth Class VI permit for a carbon capture and storage project in the Williston basin of North Dakota for the geological CO₂ storage in the Broom Creek formation. The current research aimed to conduct a comprehensive petrophysical characterization and rock physics modeling of the Broom Creek deep saline reservoir to unravel the mineralogical distribution and to understand the variations in petrophysical and elastic properties across the formation. This study utilized geophysical well logs, routine core analysis, and advanced core analysis to evaluate the Broom Creek formation. Multimineral petrophysical analysis calibrated with X-ray diffraction results reveals that this formation primarily comprises highly porous clean sandstone intervals with low-porosity interspersed with dolomite, anhydrite, and silt/clay layers. The formation exhibits varying porosities up to 0.3 and Klinkenberg air permeabilities up to ∼2600 mD. The formation water resistivity using Archie’s equation is approximately 0.055 ohm-m at 150 °F, corresponding to around 63,000 ppm NaCl salinity, which is consistent with prior data. The pore throat distribution in the samples from clean sandstone intervals is primarily situated in the macro-mega scales. However, the presence of anhydrite and dolomite impedes both porosity and pore throat sizes. The accurate prediction of effective elastic properties was achieved by developing a rock physics template. Dry rock moduli were modeled using Hill’s average, while Berryman’s self-consistent scheme was employed for modeling saturated moduli. Full article

The Chiltan formation is a potential hydrocarbon-producing reservoir in the Indus Basin, Pakistan. However, its diagenetic alterations and heterogeneous behavior lead to significant challenges in accurately characterizing the reservoir and production performance. This manuscript aims to utilize six carbonate core samples of the Chiltan limestone to conduct an in-depth analysis of the diagenetic impacts on reservoir quality. The comprehensive formation evaluation was carried out through thin-section analysis, SEM-EDS, and FTIR investigation, as well as plug porosity and permeability measurements under varying stress conditions. In result, petrography revealed three microfacies of intraclastic packestone (MF1), bioclastic pelliodal packestone (MF2), and bioclastic ooidal grainstone (MF3), with distinct diagenetic features and micro-nano fossil assemblages. The MF1 microfacies consist of bioclasts, ooids, pellets, and induced calcite, while the MF2 microfacies contain micrite cemented peloids, algae, and gastropods. Although, the MF3 grainstone microfacies contains key features of bioclasts, milliods, bivalves, echinoderms, and branchiopods with intense micritization. Diagenesis has a significant impact on petrophysical properties, leading to increased reservoir heterogeneity. The specified depositional environment exposed the alteration of the Chiltan formation during distinct diagenetic phases in marine, meteoric, and burial settings. Marine diagenesis involves biogenic carbonates and micro-nano fossils, while meteoric diagenesis involves mineral dissolution, reprecipitation, secondary porosity, compaction, cementation, and stylolite formation. Pore morphology and mineralogy reveal a complex pore network within the formation, including a micro-nano pore structure, inter–intra particle, moldic, vuggy, and fenestral pores with variations in shape, connectivity, and distribution. Various carbonate mineral phases in the formation samples were analyzed, including the calcite matrix and dolomite crystals, while silica, calcite, and clay minerals were commonly observed cement types in the analysis. The core samples analyzed showed poor reservoir quality, with porosity values ranging from 2.02% to 5.31% and permeability values from 0.264 mD to 0.732 mD, with a standard deviation of 1.21. Stress sensitivity was determined using Klinkenberg-corrected permeability at increasing pore pressure conditions, which indicated around 22%–25% reduction in the measured gas permeability and 7% in Klinkenberg permeability due to increasing the net confining stress. In conclusion, the Chiltan formation possesses intricate reservoir heterogeneity and varied micropore structures caused by diagenesis and depositional settings. The formation exhibits nonuniform pore geometry and low petrophysical properties caused by the diverse depositional environment and various minerals and cement types that result in a low-quality reservoir. Stress sensitivity further decreases the permeability with varying stress levels, emphasizing the need of stress effects in reservoir management. The results of this study provide a solid foundation in reservoir characterization and quality assessment that has implications for predicting fluid flow behavior, providing insight into geological evolution and its impact on reservoir quality and leading to improving resource exploration and production strategies. Full article

Borehole pre-drainage is an important technical means to control a coal mine gas disaster. In order to determine the optimal pre-drainage parameters of Dashucun mine, a coal damage permeability evolution model was established based on coal damage deformation, considering gas adsorption and desorption and the Klinkenberg effect, and a damage fluid-structure coupling model of coal seam containing gas was established by combining the coal seam deformation equation and the mass conservation equation. COMSOL software was used to simulate the influence of factors such as the initial permeability of coal seam, negative pumping pressure, aperture and pumping time on the effective pumping radius of pre-drainage borehole. The results show that the effect of negative pressure on the effective extraction radius can be ignored. The effect of borehole aperture, initial permeability of coal seam and extraction time on effective extraction radius is great, which conforms to the power function relationship, and the coefficient correlation value is high. The optimal extraction parameters of Dashucun mine are determined as borehole diameter 113 mm, coal seam permeability 1 × 10⁻¹⁷ m², negative extraction pressure 30 kPa and extraction time 180 d. The research results can provide theoretical reference for the pre-drainage of gas in Dashucun mine. Full article

An improvement of the pulse decay method of rock permeability measurement is presented. The technique is based on fitting experimental data to analytical and numerical solutions of the filtration equations derived with regard to the variation of flowing gas properties with temperature and pressure. A special apparatus and software for the implementation of this method were developed. A single experiment in which gas is used as a flowing medium enables determining both the permeability of a sample to water and the Klinkenberg constant. The permeability measurements on the samples of different types of rock with various reservoir properties were carried out and demonstrated satisfactory accuracy and efficiency of the method. An effective method for anisotropic permeability measurement is proposed as a development of this technique. Full article

The water and gas permeability of pervious concrete play essential roles in rainwater infiltration and plant root respiration. In this study, the gas and water permeability of pervious concrete samples were measured and compared. The water permeability was tested using the constant water head method and several water heads were measured for inspection, in which the permeability varied with the application of the pressure gradient. The permeability of gas was measured using a new simple gas permeameter, which was specially manufactured for measuring the gas permeability of pervious concrete under a stable pressure difference. A series of different gas pressure gradients was applied to test whether the gas permeability was a function of the applied pressure. Both the gas and water permeability of pervious concrete were found to decrease with an increased applied pressure gradient, which did not conform to the Klinkenberg effect (gas slippage effect). When comparing the gas permeability and water permeability of pervious concrete, we found that the water permeability was 4–5 times larger than the gas permeability. Full article

The pre-drainage of coalbed methane through boreholes in the bottom drainage roadway (BDR) is the key measure to prevent and control coal and gas outburst. Different arrangement layers in the BDR will make a difference in the range of drilling angle and affect the gas extraction effect. In this paper, the mathematical model of the rock loose circle area around elliptical drilling was constructed. Meanwhile, the fluid–solid coupling model is constructed by using COMSOL software, the dynamic response of coal permeability and volumetric strain with gas pressure and the Klinkenberg effect of gas are considered, and the effect of the change of the elliptical drilling angle on the pressure relief effect of the coal seam is studied. The results showed that the distance between the layer in the BDR and the pre-drainage coal seam would decrease, and the effective extraction length at the same point of gas extraction in the coal seam increases. The area of the rock loose circle and permeability around the drilling decayed negatively and exponentially with the increase in drilling angle. As the drilling angle decreased, the stress in the major axis of the ellipse at the drilling cross-section increased, so the drilling was prone to collapse, and the gas extraction was hindered. Finally, an optimal method of determining the layer in the BDR under the coupling effect of multiple factors was established by combining the measured ground stress. Through field measurement, the drilling extraction rate of the optimized scheme is 60% higher than that of the original scheme. Full article

The permeability characteristics of natural fracture systems are crucial to the production potential of shale gas wells. To investigate the permeability behavior of a regional fault that is located within the Wufeng Formation, China, the gas permeability of shale samples with natural micro-fractures was measured at different confining pressures and complemented with helium pycnometry for porosity, computed micro-tomographic (µCT) imaging, and a comparison with well testing data. The cores originated from a shale gas well (HD-1) drilled at the Huayingshan anticline in the eastern Sichuan Basin. The measured Klinkenberg permeabilities are in the range between 0.059 and 5.9 mD, which roughly agrees with the permeability of the regional fault (0.96 mD) as estimated from well HD-1 productivity data. An extrapolation of the measured permeability to reservoir pressures in combination with the µCT images shows that the stress sensitivity of the permeability is closely correlated to the micro-fracture distribution and orientation. Here, the permeability of the samples in which the micro-fractures are predominantly oriented along the flow direction is the least stress sensitive. This implies that tectonic zones with a large fluid potential gradient can define favorable areas for shale gas exploitation, potentially even without requirements for hydraulic fracture treatments. Full article

Klinkenberg-corrected permeability (k_∞) or water permeability (k_w) is an important input parameter for hydrocarbon reservoir simulation studies. The theoretical concept that a core sample’s k_∞ is comparable to its k_w is flawed and has to be verified, since experimental evidence indicates that k_∞ and k_w are clearly different. Thus, a series of gas and water permeability measurements were conducted on eight carbonate core plug samples from Sarawak, Malaysia to develop a correlation between both permeability values. The new k_∞ vs. k_w correlation clearly proved the differences between both permeability values for all samples. The findings were in agreement with FESEM-EDX and total suspended solids (TSS) analysis, which proved the migration of fines and clay particles that blocked the pore throats, thus reducing k_w values. The new k_∞ vs. k_w correlation was validated using four different samples from the PETRONS-2 well using its k_∞ values and comparing them with the respective measured k_w values. The new correlation will reduce the amount of time and cost needed to obtain absolute liquid permeability values but may be further improved by conducting permeability measurements on more samples from the PETRONS field, which will improve the accuracy of hydrocarbon reservoir simulation of the PETRONS field. Full article

Nonuniform proppant distribution is fairly common in hydraulic fractures, and different closure behaviors of the propped and unpropped fractures have been observed in lots of physical experiments. However, the modeling of partially propped fracture closure is rarely performed, and its effect on gas production is not well understood as a result of previous studies. In this paper, a fully coupled fluid flow and geomechanics model is developed to simulate partially propped fracture closure, and to examine its effect on gas production in fractured shale reservoirs. Specifically, an efficient hybrid model, which consists of a single porosity model, a multiple porosity model and the embedded discrete fracture model (EDFM), is adopted to model the hydro-mechanical coupling process in fractured shale reservoirs. In flow equations, the Klinkenberg effect is considered in gas apparent permeability, and adsorption/desorption is treated as an additional source term. In the geomechanical domain, the closure behaviors of propped and unpropped fractures are described through two different constitutive models. Then, a stabilized extended finite element method (XFEM) iterative formulation, which is based on the polynomial pressure projection (PPP) technique, is developed to simulate a partially propped fracture closure with the consideration of displacement discontinuity at the fracture interfaces. After that, the sequential implicit method is applied to solve the coupled problem, in which the finite volume method (FVM) and stabilized XFEM are applied to discretize the flow and geomechanics equations, respectively. Finally, the proposed method is validated through some numerical examples, and then it is further used to study the effect of partially propped fracture closures on gas production in 3D fractured shale reservoir simulation models. This work will contribute to a better understanding of the dynamic behaviors of fractured shale reservoirs during gas production, and will provide more realistic production forecasts. Full article

The optimum design of gas drainage boreholes is crucial for energy security and sustainability in coal mining. Therefore, the construction of fluid–solid coupling models and numerical simulation analyses are key problems for gas drainage boreholes. This work is based on the basic theory of fluid–solid coupling, the correlation definition between coal porosity and permeability, and previous studies on the influence of adsorption expansion, change in pore free gas pressure, and the Klinkenberg effect on gas flow in coal. A mathematical model of the dynamic evolution of coal permeability and porosity is derived. A fluid–solid coupling model of gas-bearing coal and the related partial differential equation for gas migration in coal are established. Combined with an example of the measurement of the drilling radius of the bedding layer in a coal mine, a coupled numerical solution under negative pressure extraction conditions is derived by using COMSOL Multiphysics simulation software. Numerical simulation results show that the solution can effectively guide gas extraction and discharge during mining. This study provides theoretical and methodological guidance for energy security and coal mining sustainability. Full article

Gases can potentially generate in a deep geological repository (DGR) for the long-term containment of radioactive waste. Natural and engineered barriers provide containment of the waste by mitigating contaminant migration. However, if gas pressures exceed the mechanical strength of these barriers, preferential flow pathways for both the gases and the porewater could form, providing a source of potential exposure to people and the environment. Expansive soils, such as bentonite-based materials, are widely considered as sealing materials. Understanding the long-term performance of these seals as barriers against gas migration is an important component in the design and the long-term safety assessment of a DGR. This study proposes a hydro-mechanical mathematical model for migration of gas through a low-permeable swelling geomaterial based on the theoretical framework of poromechanics. Using the finite element method, the model is used to simulate 1D flow through a confined cylindrical sample of near-saturated low-permeable soil under a constant volume boundary stress condition. The study expands upon previous work by the authors by assessing the influence of heterogeneity, the Klinkenberg “slip flow” effect, and a swelling stress on flow behavior. Based on the results, this study provides fundamental insight into a number of factors that may influence two-phase flow. Full article

The Klinkenberg slippage theory has widely been used to obtain gas permeability in low-permeability porous media. However, recent research shows that there is a deviation from the Klinkenberg slippage theory for tight reservoir cores under low-pressure conditions. In this research, a new experimental device was designed to carry out the steady-state gas permeability test with high pressure and low flowrate. The results show that, unlike regular low-permeability cores, the permeability of tight cores is not a constant value, but a variate related to a fluid-dynamic parameter (flowrate). Under high-pressure conditions, the relationship between flowrate and apparent permeability of cores with low permeability is consistent with Klinkenberg slippage theory, while the relationship between flowrate and apparent permeability of tight cores is contrary to Klinkenberg slip theory. The apparent permeability of tight core increases with increasing flowrate under high-pressure conditions, and it is significantly lower than the Klinkenberg permeability predicted by Klinkenberg slippage theory. The difference gets larger when the flowrate becomes lower (back pressure increases and pressure difference decreases). Therefore, the Klinkenberg permeability which is obtained by the Klinkenberg slippage theory by using low-pressure experimental data will cause significant overestimation of the actual gas seepage capacity in the tight reservoir. In order to evaluate the gas seepage capacity in a tight reservoir precisely, it is necessary to test the permeability of the tight cores directly at high pressure and low flowrate. Full article