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1
Wei, Gang, Kanghao Tan, Tenglong Liang, and Yinghong Qin. "A Comparative Study on Water and Gas Permeability of Pervious Concrete." Water 14, no. 18 (September 13, 2022): 2846. http://dx.doi.org/10.3390/w14182846.
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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.
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Cui, Shuheng, Qilin Wu, and Zixuan Wang. "Estimating the Influencing Factors of Gas–Water Relative Permeability in Condensate Gas Reservoirs under High-Temperature and High-Pressure Conditions." Processes 12, no. 4 (April 3, 2024): 728. http://dx.doi.org/10.3390/pr12040728.
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The gas–water relative permeability curve plays a crucial role in reservoir simulation and development for condensate gas reservoirs. This paper conducted a series of high-temperature and high-pressure analysis experiments on real gas cores from Wells A and B in Block L of the Yinggehai Basin to investigate the effects of temperature, pressure, and different types of gas media on gas–water seepage. The gas–water relative permeability was simulated in this experiment through variations in temperature, pressure, and gas composition. Temperature has a significant impact on both gas and water relative permeability, particularly on gas relative permeability. As temperature increases, gas relative permeability shows a substantial increase, while water relative permeability remains relatively unchanged. Under the same effective stress, increasing pressure causes downward shifts in both the gas and water relative permeability curves; however, there is a more pronounced decrease in gas relative permeability. Gas composition has minimal influence on the gas–water relative permeability except at higher water saturation where differences become apparent. When water saturation ranges from 80% to 50%, there is no significant variation observed in the measured relative permeability of different displacement gases. However, as water saturation exceeds 80%, distinctions gradually emerge. The relative permeability of nitrogen is approximately 92% lower than that of mixed gas when the bound water saturation reaches 80%. This investigation provides valuable insights into the characteristics of gas–water relative permeability in high-temperature and high-pressure condensate reservoirs within Yinggehai Basin, thereby offering significant contributions to development strategies for similar reservoirs.
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Tanikawa, W., and T. Shimamoto. "Klinkenberg effect for gas permeability and its comparison to water permeability for porous sedimentary rocks." Hydrology and Earth System Sciences Discussions 3, no. 4 (July 7, 2006): 1315–38. http://dx.doi.org/10.5194/hessd-3-1315-2006.
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Abstract. The difference between gas and water permeabilities is significant not only for solving gas-water two-phase flow problems, but also for quick measurements of permeability using gas as pore fluid. We have measured intrinsic permeability of sedimentary rocks from the Western Foothills of Taiwan, using nitrogen gas and distilled water as pore fluids, during several effective-pressure cycling tests at room temperature. The observed difference in gas and water permeabilities has been analyzed in view of the Klinkenberg effect. This effect is due to slip flow of gas at pore walls which enhances gas flow when pore sizes are very small. Experimental results show (1) that gas permeability is larger than water permeability by several times to one order of magnitude, (2) that gas permeability increases with increasing pore pressure, and (3) that water permeability slightly increases with increasing pore-pressure gradient across the specimen. The results (1) and (2) can be explained by Klinkenberg effect quantitatively with an empirical power law for Klinkenberg constant. Thus water permeability can be estimated from gas permeability. The Klinkenberg effect is important when permeability is lower than 10−18 m2 and at low differential pore pressures, and its correction is essential for estimating water permeability from the measurement of gas permeability. A simple Bingham-flow model of pore water can explain the overall trend of the result (3) above. More sophisticated models with a pore-size distribution and with realistic rheology of water film is needed to account for the observed deviation from Darcy's law.
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Lei, Gang, Cai Wang, Zisen Wu, Huijie Wang, and Weirong Li. "Theory study of gas–water relative permeability in roughened fractures." Proceedings of the Institution of Mechanical Engineers, Part C: Journal of Mechanical Engineering Science 232, no. 24 (February 8, 2018): 4615–25. http://dx.doi.org/10.1177/0954406218755185.
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It has been shown that gas–water relative permeability in fracture or fractured porous media plays an important role in determination of flow characteristics for gas–water two-phase flow. The accurate prediction of gas–water two-phase flow in fracture or fractured media is hence highly important. In most recent analytical models for gas–water relative permeability in fracture, the fracture is conceptualized as smooth wall. Reliable characterization of roughened fracture surface is severely limited. The analytical models for gas–water two-phase relative permeability in roughened fracture are scarce, thus, it is desirable to develop an analytical model for gas–water relative permeability in fracture with roughened surface. The goal of this work is to present an analytical model for gas–water relative permeability in roughened fracture. The rough surface topography of roughened fracture can be addressed by fractal theory. In addition, the proposed model is modified by considering the influence of tortuosity to study the gas–water relative permeability in fractured porous media. The proposed gas–water relative permeability is found to be a function of the structural parameters of roughened fracture. The predictions of relative permeability by the proposed model have similar variation trend with available experimental data, which verifies the theoretical models. We also conduct several sensitivity studies. These proposed analytical models provides a more realistic representation of gas–water two-phase flow in roughened fracture and fractured porous media, and gives rise to more reliable gas–water relative permeability curves that can be used for analyzing gas–water two-phase flow characteristic in fractured reservoirs.
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Villar, M. V., P. L. Martín, F. J. Romero, V. Gutiérrez-Rodrigo, and J. M. Barcala. "Gas and water permeability of concrete." Geological Society, London, Special Publications 415, no. 1 (November 14, 2014): 59–73. http://dx.doi.org/10.1144/sp415.6.
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Wei, Benchi, Xiangrong Nie, Zonghui Zhang, Jingchen Ding, Reyizha Shayireatehan, Pengzhan Ning, Ding-tian Deng, and Jiao Xiong. "Zoning Productivity Calculation Method of Fractured Horizontal Wells in High-Water-Cut Tight Sandstone Gas Reservoirs under Complex Seepage Conditions." Processes 11, no. 12 (November 27, 2023): 3308. http://dx.doi.org/10.3390/pr11123308.
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Tight sandstone gas reservoirs generally contain water. Studying the impact of water content on the permeability mechanism of tight gas reservoirs is of positive significance for the rational development of gas reservoirs. Selected cores from a tight sandstone gas reservoir in the Ordos Basin were used to establish the variation in its seepage mechanism under different water saturations. The experimental results show that the gas slip factor in tight water-bearing gas reservoirs decreases as the water saturation increases. The stress sensitivity coefficient and the threshold pressure gradient (TPG) increase with increasing water saturation, characterizing the relationships between stress sensitivity coefficients, TPG, permeability, and water saturation. As the water saturation gradually increases, the relative gas phase permeability of tight sandstone gas reservoirs will sharply decrease. When the water saturation exceeds 80%, the gas phase permeability becomes almost zero, resulting in gas almost ceasing to flow. Through the analysis of experimental results, we defined high-water-cut tight sandstone gas reservoirs and analyzed the permeability characteristics of high-water-cut tight sandstone gas reservoirs in different regions. Combining stress sensitivity coefficients and the TPG with permeability and water saturation relationships, we established a zoning productivity calculation method of fractured horizontal wells in high-water-cut tight sandstone gas reservoirs under complex seepage conditions and validated the practicality of the model through example calculations.
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Li, Qi, Li You Ye, and Wei Guo An. "Gas Seepage Law in Condition of Bound Water of Low Permeability and Tight Sandstone Gas Reservoir." Advanced Materials Research 1094 (March 2015): 385–88. http://dx.doi.org/10.4028/www.scientific.net/amr.1094.385.
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In condition of bound water, bound water is distributed on surface of pore throat in the form of water film in low permeability and tight sandstone gas reservoir, so bound water reduces the seepage space of the gas and makes gas to occur Special seepage law. This article design physical simulation research experiment about gas seepage law in containing water reservoir. Experimental results explain: Gas seepage curve existed obvious non-linear seepage region in low permeability reservoir, gas slippage effect happens in the low-pressure region, and high-speed non-Darcy seepage happens in the high-pressure region. With the limit of water and pore throat in tight reservoir, gas hardly occurs specific non-linear seepage phenomenon. The critical water saturation which causes gas effective permeability sudden changing is around 30% in low permeability and tight reservoir. The research result has important theoretical significance on establishing corresponding percolation model of single well productivity and efficient development of low permeability and tight sandstone gas reservoir.
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Zhang, Yurong, Shengxuan Xu, Zhaofeng Fang, Junzhi Zhang, and Chaojun Mao. "Permeability of Concrete and Correlation with Microstructure Parameters Determined by 1H NMR." Advances in Materials Science and Engineering 2020 (May 14, 2020): 1–11. http://dx.doi.org/10.1155/2020/4969680.
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Water and gas permeability coefficients of concrete with different water-binder (w/b) ratios and admixtures were measured by a self-designed test device based on the steady-state flow method for liquid and the method of differential pressure in stability for gas, respectively. In addition, the micropore structure of concrete was determined by 1H nuclear magnetic resonance (NMR). Results indicated that there are good correlations between water and gas permeability of concrete with different w/b ratios, with correlation coefficient greater than 0.90. Better correlations between water permeability and segmental contributive porosity ranged from 10 to 100 nm and 100 to 1000 nm can be identified, but the gas permeability is more relevant to the segmental contributive porosity ranging from 100 to 1000 nm. Moreover, the correlation between water permeability and contributive porosity for each pore diameter is always better than that of gas permeability. The influence of admixtures on the relationship between permeability and pore size distribution of concrete is significant. Moreover, water permeability coefficient is one or two orders of magnitude lower than the gas permeability coefficient.
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Li, Yilong, Hao Yang, Xiaoping Li, Mingqing Kui, and Jiqiang Zhang. "Experiments on Water-Gas Flow Characteristics under Reservoir Condition in a Sandstone Gas Reservoir." Energies 16, no. 1 (December 21, 2022): 36. http://dx.doi.org/10.3390/en16010036.
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For gas reservoirs that contain water, investigating characteristics of water–gas seepage is crucial to the formulation of gas field development plans and predicting the production capacity and water breakthrough of gas wells. For the purposes of such an investigation, the process of water invasion into a water-containing gas reservoir was studied based on four sandstone samples whose physical properties differed quite vastly (permeability: 0.112–192.251 mD; porosity: 8.33–20.60%). Gas–water relative permeability experiments were conducted on the gas-driven water in the reservoir conditions (temperature: 135 °C; pressure: 75 MPa). Starting with the sandstone samples’ microstructural characteristics, particular attention was paid to the impacts of throat radius and clay content on the water–gas seepage characteristics. It was found that the basic physical properties, microscopic characteristics, and mineral composition of the sandstone samples all affected the water–gas seepage characteristics. The larger the pore-throat radius, the stronger the ability of sandstone samples to allow fluid through under the same water saturation and the greater the relative permeability of gas and water phases. Furthermore, the wider the throat radius and the lower the clay content, the greater the gas–water relative permeability. Isotonic water saturation and irreducible water saturation were found to be negatively to throat radius and positively with clay content. Furthermore, When sandstone samples have similar clay content, the average throat radius is four times larger, its irreducible water saturation is decreased by 1.63%, its residual gas saturation is decreased by 1.00%, and the gas permeability under irreducible water saturation increases by more than 400 times. Water intrusion showed a more significant impact on the gas–water flow characteristics of the low-permeability sandstone samples, and it severely restricted the flow capacity of the gas phase.
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Wang, Huimin, Jianguo Wang, Xiaolin Wang, and Bowen Hu. "An Improved Relative Permeability Model for Gas-Water Displacement in Fractal Porous Media." Water 12, no. 1 (December 19, 2019): 27. http://dx.doi.org/10.3390/w12010027.
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Many researchers have revealed that relative permeability depends on the gas-water-rock interactions and ultimately affects the fluid flow regime. However, the way that relative permeability changes with fractal porous media has been unclear so far. In this paper, an improved gas-water relative permeability model was proposed to investigate the mechanism of gas-water displacement in fractal porous media. First, this model took the complexity of pore structure, geometric correction factor, water film, and the real gas effect into account. Then, this model was compared with two classical models and verified against available experimental data. Finally, the effects of structural parameters (pore-size distribution fractal dimension and tortuosity fractal dimension) on gas-water relative permeability were investigated. It was found that the sticking water film on the surface of fracture has a negative effect on water relative permeability. The increase of geometric correction factor and the ignorance of real gas effect cause a decrease of gas relative permeability.
11
Shahverdi, H., and M. Sohrabi. "Relative Permeability Characterization for Water-Alternating-Gas Injection in Oil Reservoirs." SPE Journal 21, no. 03 (June 15, 2016): 0799–808. http://dx.doi.org/10.2118/166650-pa.
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Summary Large quantities of oil usually remain in oil reservoirs after conventional waterfloods. A significant part of this remaining oil can still be economically recovered by water-alternating-gas (WAG) injection. WAG injection involves drainage and imbibition processes taking place sequentially; therefore, the numerical simulation of the WAG process requires reliable knowledge of three-phase relative permeability (kr) accounting for cyclic-hysteresis effects. In this study, the results of a series of unsteady-state two-phase displacements and WAG coreflood experiments were used to investigate the behavior of three-phase kr and hysteresis effects in the WAG process. The experiments were performed on two different cores with different characteristics and wettability conditions. An in-house coreflood simulator was developed to obtain three-phase relative permeability values directly from unsteady-state WAG experiments by history matching the measured recovery and differential-pressure profiles. The results show that three-phase gas relative permeability is reduced in consecutive gas-injection cycles and consequently the gas mobility and injectivity drop significantly with successive gas injections during the WAG process, under different rock conditions. The trend of hysteresis in the relative permeabilty of gas (krg) partly contradicts the existing hysteresis models available in the literature. The three-phase water relative permeability (krw) of the water-wet (WW) core does not exhibit considerable hysteresis effect during different water injections, whereas the mixed-wet (MW) core shows slight cyclic hysteresis. This may indicate a slight increase of the water injectivity in the subsequent water injections in the WAG process under MW conditions. Insignificant hysteresis is observed in the oil relative permeability (kro) during different gas-injection cycles for both WW and MW rocks. However, a considerable cyclic-hysteresis effect in kro is observed during water-injection cycles of WAG, which is attributed to the reduction of the residual oil saturation (ROS) during successive water injections. The kro of the WW core exhibits much-more cyclic-hysteresis effect than that of the MW core. No models currently exist in reservoir simulators that can capture the observed cyclic-hysteresis effect in oil relative permeability for the WAG process. Investigation of relative permeability data obtained from these displacement tests at different rock conditions revealed that there is a significant discrepancy between two-phase and three-phase relative permeability of all fluids. This highlights that not only the three-phase relative permeability of the intermediate phase (oil), but also the three-phase kr of the wetting phase (water) and nonwetting phase (gas) are functions of two independent saturations.
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Al-shajalee, Faaiz, Colin Wood, Quan Xie, and Ali Saeedi. "Effective Mechanisms to Relate Initial Rock Permeability to Outcome of Relative Permeability Modification." Energies 12, no. 24 (December 9, 2019): 4688. http://dx.doi.org/10.3390/en12244688.
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Excessive water production is becoming common in many gas reservoirs. Polymers have been used as relative permeability modifiers (RPM) to selectively reduce water production with minimum effect on the hydrocarbon phase. This manuscript reports the results of an experimental study where we examined the effect of initial rock permeability on the outcome of an RPM treatment for a gas/water system. The results show that in high-permeability rocks, the treatment may have no significant effect on either the water and gas relative permeabilities. In a moderate-permeability case, the treatment was found to reduce water relative permeability significantly but improve gas relative permeability, while in low-permeability rocks, it resulted in greater reduction in gas relative permeability than that of water. This research reveals that, in an RPM treatment, more important than thickness of the adsorbed polymer layer ( e ) is the ratio of this thickness on rock pore radius ( e r ).
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Munekata, Toshihisa, Takaji Inamuro, and Shi-aki Hyodo. "Gas Transport Properties in Gas Diffusion Layers: A Lattice Boltzmann Study." Communications in Computational Physics 9, no. 5 (May 2011): 1335–46. http://dx.doi.org/10.4208/cicp.301009.161210s.
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AbstractThe lattice Boltzmann method is applied to the investigations of the diffusivity and the permeability in the gas diffusion layer (GDL) of the polymer electrolyte fuel cell (PEFC). The effects of the configuration of water droplets, the porosity of the GDL, the viscosity ratio of water to air, and the surface wettability of the GDL are investigated. From the simulations under the PEFC operating conditions, it is found that the heterogeneous water network and the high porosity improve the diffusivity and the permeability, and the hydrophobic surface decreases the permeability.
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Shahverdi, Hamidreza, and Mehran Sohrabi. "Modeling of Cyclic Hysteresis of Three-Phase Relative Permeability During Water-Alternating-Gas Injection." SPE Journal 20, no. 01 (June 27, 2014): 35–48. http://dx.doi.org/10.2118/166526-pa.
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Summary Multiphase flow takes place in many petroleum reservoirs—in particular, mature fields and reservoirs under fluid [e.g., gas, water-alternating-gas (WAG)] injection. The numerical simulation of such reservoirs requires knowledge of flow functions (i.e., relative permeability and capillary pressure). Because experimental measurement of fluid permeabilities (in particular) under three-phase-flow conditions is very time-consuming and difficult, many correlations and models were developed and these are widely used instead of measured data. In this study, we have used the results of a comprehensive set of WAG-injection coreflood experiments performed under different wettability conditions and core-permeability values to obtain relative permeabilites of oil, water, and gas under reservoir pressure and temperature. Three-phase relative permeability of each phase was obtained by history matching the measured production and differential pressure obtained in the laboratory. The results of the experiments revealed significant cyclic hysteresis effects in gas and oil relative permeability. We proposed new formulations and methodology for the modeling of cyclic hysteresis of three-phase relative permeability during WAG injection. This technique is a direct method that uses measured three-phase kr data obtained from the first cycle of WAG injection to predict the relative permeability of the subsequent cycles. The integrity of this technique was validated against the three-phase kr data obtained from our WAG experiments. We also assess the validity of the WAG-injection hysteresis model available in reservoir simulators against our three-phase relative permeability data to evaluate its performance.
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Cao, Renyi, Liyou Ye, Qihong Lei, Xinhua Chen, Y. Zee Ma, and Xiao Huang. "Gas-Water Flow Behavior in Water-Bearing Tight Gas Reservoirs." Geofluids 2017 (2017): 1–16. http://dx.doi.org/10.1155/2017/9745795.
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Some tight sandstone gas reservoirs contain mobile water, and the mobile water generally has a significant impact on the gas flowing in tight pores. The flow behavior of gas and water in tight pores is different than in conventional formations, yet there is a lack of adequate models to predict the gas production and describe the gas-water flow behaviors in water-bearing tight gas reservoirs. Based on the experimental results, this paper presents mathematical models to describe flow behaviors of gas and water in tight gas formations; the threshold pressure gradient, stress sensitivity, and relative permeability are all considered in our models. A numerical simulator using these models has been developed to improve the flow simulation accuracy for water-bearing tight gas reservoirs. The results show that the effect of stress sensitivity becomes larger as water saturation increases, leading to a fast decline of gas production; in addition, the nonlinear flow of gas phase is aggravated with the increase of water saturation and the decrease of permeability. The gas recovery decreases when the threshold pressure gradient (TPG) and stress sensitivity are taken into account. Therefore, a reasonable drawdown pressure should be set to minimize the damage of nonlinear factors to gas recovery.
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Ren, Xiaoxia, Aifen Li, and Asadullah Memon. "Experimental Study on Gas–Water Relative Permeability Characteristics of Tight Sandstone Reservoir in Ordos Basin." Geofluids 2022 (June 8, 2022): 1–8. http://dx.doi.org/10.1155/2022/1521837.
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Accurate measurement of relative permeability curve is the basis for evaluating gas reservoir performance. The unsteady-state method could bring significant measurement error for low-permeability cores. However, it is difficult to control the constant gas flow rate in the traditional steady-state method, which obstacles the experimental operation. In this study, an improved steady-state method was proposed. First, the pressure value obtained from the experiment, when the gas permeability no longer changed with the average pressure on the rock core, was set as the testing pressure. Then, the gas was injected under constant pressure, and the water was injected with a constant flow rate. Finally, the relative permeability values of gas and water phases were calculated based on Darcy’s law. Comparative analysis of the results of the relative permeability curves under formation pressure and pressure with negligible slip effect indicates that the relative permeability curves are the same in gas and water phases, proving the feasibility of the new method. Further, the results were compared with those of the test method at normal pressure, the water-phase relative permeability showed no significant change, the relative permeability of gas phase was larger, the two-phase flow area became wider, and the irreducible water saturation was lower than that at the normal pressure. This result reflects that pressure does not significantly affect the flow of wetting phase but tremendously influences the nonwetted phase under low pressure. The relationship between relative permeability and water saturation is linear in the semilogarithmic coordinate diagram and can be described by using the following relationship: ln k rg / k rw = a S w + ln b . With the decrease in the core permeability, relative permeability curve, and isotonic point moved to the right, irreducible water saturation gradually increased, and residual gas saturation decreased, indicating that the smaller permeability induced a lower gas-phase flow capacity.
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Cao, Xiaopeng, Tongjing Liu, Qihong Feng, Lekun Zhao, Jiangfei Sun, Liwu Jiang, Jinju Liu, and Baochen Fu. "Experimental Study of the Dynamic Water–Gas Ratio of Water and Gas Flooding in Low-Permeability Reservoirs." Energies 17, no. 5 (February 26, 2024): 1108. http://dx.doi.org/10.3390/en17051108.
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WAG flooding is a dynamic process of continuous reservoir flow field reconstruction. The unique advantages of WAG flooding cannot be utilized, due to the fixed water–gas ratio. Therefore, we must investigate the dynamic adjustment of the water–gas ratio for WAG flooding. Using nine cases of long-core displacement experiments in low-permeability reservoirs, the development effects of three different displacement methods, namely, continuous gas flooding, WAG flooding with a fixed water–gas ratio, and WAG flooding with a dynamic water–gas ratio, were investigated after elastic development, water flooding, and gas flooding. This study shows that for early elastic development in low-permeability reservoirs, WAG flooding can significantly improve oil recovery, but WAG flooding with a dynamic water–gas ratio is not conducive to the control of the water cut rise and gas channeling. As a result, it is more suitable to adopt WAG flooding with a fixed water–gas ratio. For early water flooding in low-permeability reservoirs, WAG flooding more clearly improves oil recovery and suppresses gas channeling, but WAG flooding with a dynamic water–gas ratio exhibits a higher oil recovery and thus is recommended. For early gas flooding in low-permeability reservoirs, whether the development effect of WAG flooding can improve oil recovery and inhibit gas channeling strongly depends on whether the water–gas ratio is adjusted. The development effect of WAG flooding with a dynamic water–gas ratio is significantly better than that with a fixed water–gas ratio. Therefore, WAG flooding with a dynamic water–gas ratio is recommended to achieve the best displacement effect. This research has important practical significance for further improving the development effect of WAG flooding in low-permeability reservoirs.
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Wang, Jiulong, Hongqing Song, Tianxin Li, Yuhe Wang, and Xuhua Gao. "Simulating gas-water relative permeabilities for nanoscale porous media with interfacial effects." Open Physics 15, no. 1 (August 3, 2017): 517–24. http://dx.doi.org/10.1515/phys-2017-0059.
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AbstractThis paper presents a theoretical method to simulate gas-water relative permeability for nanoscale porous media utilizing fractal theory. The comparison between the calculation results and experimental data was performed to validate the present model. The result shows that the gas-water relative permeability would be underestimated significantly without interfacial effects. The thinner the liquid film thickness, the greater the liquid-phase relative permeability. In addition, both liquid surface diffusion and gas diffusion coefficient can promote gas-liquid two-phase flow. Increase of liquid surface diffusion prefer to increase liquid-phase permeability obviously as similar as increase of gas diffusion coefficient to increase gas-phase permeability. Moreover, the pore structure will become complicated with the increase of fractal dimension, which would reduce the gas-water relative permeability. This study has provided new insights for development of gas reservoirs with nanoscale pores such as shale.
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Hu, Yong, Xizhe Li, Weijun Shen, Changmin Guo, Chunyan Jiao, Xuan Xu, and Yuze Jia. "Study on the Water Invasion and Its Effect on the Production from Multilayer Unconsolidated Sandstone Gas Reservoirs." Geofluids 2021 (July 26, 2021): 1–9. http://dx.doi.org/10.1155/2021/5135159.
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Water invasion is a common occurrence in multilayer unconsolidated gas reservoirs, which results in excessive water production and reduces the economic life of gas wells. However, due to multiple layers, active edge water, and strong heterogeneity, the mechanism of water invasion and its effect in the unconsolidated sandstone gas reservoir require understanding in order to improve efficiency and minimize economic cost. In this study, an experimental study on edge water invasion of the multilayer commingled production in unconsolidated sandstone gas reservoirs was conducted to understand the water invasion process along with different permeability layers. The results show that the edge water invasion in the commingling production is mainly affected by two major factors including reservoir permeability and gas production rate, which jointly control the encroaching water advance path and speed. The nonuniform invade of edge water may occur easily and water prefers to invade toward the gas well along with high permeability layers when the commingling production is in the condition of large permeability gradient and high production rate. The bypass flow will occur when there are high permeability channels between the layers, which causes water blocking to low-permeability layers and periphery reservoirs far away from gas wells. The findings of this study can help for a better understanding of water invasion and the effects of reservoir properties so as to optimize extraction conditions and predict gas productivity in unconsolidated sandstone gas reservoirs.
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Lin, Xiaoying, Jianhui Zeng, Jian Wang, and Meixin Huang. "Natural Gas Reservoir Characteristics and Non-Darcy Flow in Low-Permeability Sandstone Reservoir of Sulige Gas Field, Ordos Basin." Energies 13, no. 7 (April 7, 2020): 1774. http://dx.doi.org/10.3390/en13071774.
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In order to reveal the gas–water distribution and formation mechanism of the low-permeability sandstone gas reservoir, the gas reservoir distribution and the formation mechanism in a low-permeability sandstone gas reservoir are investigated using data obtained from a physical simulation experiment of gas percolation. The exploration and experimenting for petroleum in the upper Paleozoic gas pool of the Sulige gas field in the Ordos basin in this paper. Results showed that the gas reservoir is characterized by low gas saturation, a complex distribution relationship of gas–water, and weak gas–water gravity differentiation. The characteristics of gas distribution are closely related to permeability, gas flow, and migration force. The capillary pressure difference is the main driving force of gas accumulation. There exists a threshold pressure gradient as gas flows in low-permeability sandstone. The lower that permeability, the greater the threshold pressure gradient. When the driving force cannot overcome the threshold pressure (minimal resistance), the main means of gas migration is diffusion; when the driving force is between minimal and maximal resistance, gas migrates with non-Darcy flow; when the driving force is greater than maximal resistance, gas migrates with Darcy flow. The complex gas migration way leads to complicated gas- water distribution relationship. With the same driving force, gas saturation increases with the improvement of permeability, thus when permeability is greater than 0.15 × 10−3 µ m2, gas saturation could be greater than 50%.
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Yan, Jin, Rongchen Zheng, Peng Chen, Shuping Wang, and Yunqing Shi. "Calculation Model of Relative Permeability in Tight Sandstone Gas Reservoir with Stress Sensitivity." Geofluids 2021 (December 10, 2021): 1–12. http://dx.doi.org/10.1155/2021/6260663.
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During the development of tight gas reservoir, the irreducible water saturation, rock permeability, and relative permeability change with formation pressure, which has a significant impact on well production. Based on capillary bundle model and fractal theory, the irreducible water saturation model, permeability model, and relative permeability model are constructed considering the influence of water film and stress sensitivity at the same time. The accuracy of this model is verified by results of nuclear magnetic experiment and comparison with previous models. The effects of some factors on irreducible water saturation, permeability, and relative permeability curves are discussed. The results show that the stress sensitivity will obviously reduce the formation permeability and increase the irreducible water saturation, and the existence of water film will reduce the permeability of gas phase. The increase of elastic modulus weakens the stress sensitivity of reservoir. The irreducible water saturation increases, and the relative permeability curve changes little with the increase of effective stress. When the minimum pore radius is constant, the ratio of maximum pore radius to minimum pore radius increases, the permeability increases, the irreducible water saturation decreases obviously, and the two-phase flow interval of relative permeability curve increases. When the displacement pressure increases, the irreducible water saturation decreases, and the interval of two-phase flow increases. These models can calculate the irreducible water saturation, permeability and relative permeability curves under any pressure in the development of tight gas reservoir. The findings of this study can help for better understanding of the productivity evaluation and performance prediction of tight sandstone gas reservoirs.
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FU, JINGANG, YULIANG SU, LEI LI, YONGMAO HAO, and WENDONG WANG. "PREDICTED MODEL OF RELATIVE PERMEABILITY CONSIDERING WATER DISTRIBUTION CHARACTERISTICS IN TIGHT SANDSTONE GAS RESERVOIRS." Fractals 28, no. 01 (February 2020): 2050012. http://dx.doi.org/10.1142/s0218348x20500127.
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A novel predictive model for calculating relative permeability was derived based on a capillary tube model with fractal theory. Different forms of immovable water including water film (WF) and microcapillary water were incorporated in the new model. Special immovable water called lost dynamic water (LDW) was introduced in the proposed model. The results of verification show that there is agreement between the calculated results and the published experimental data and analytical model. The results indicated that the effect of LDW, WF, and stress dependence had a significant influence on the relative permeability, which cannot be neglected. A larger LDW coefficient, more dead-end pores, and corners in porous media yielded a more complex pore structure. Therefore, more water was trapped in the pore and became connate water, resulting in higher gas relative permeability and lower water relative permeability at a given water saturation. Due to the microcapillary effect, the relative permeability of the water/gas increased/decreased as the drawdown pressure increased at the same water saturation. Higher effective stress was more likely to cause rock deformation, resulting in higher gas relative permeability and lower water relative permeability at a given water saturation. This study provides a significant reference for reservoir engineers conducting water and gas two-phase flow analysis. The theoretical model is beneficial for research into the interpolation of relative permeability via numerical simulation.
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Ibrahim, Ahmed Farid, and Hisham A. Nasr-El-Din. "Effects of Formation-Water Salinity, Formation Pressure, Gas Composition, and Gas-Flow Rate on Carbon Dioxide Sequestration in Coal Formations." SPE Journal 22, no. 05 (March 22, 2017): 1530–41. http://dx.doi.org/10.2118/185949-pa.
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Summary Carbon dioxide (CO2) sequestration in coal seams combines CO2 storage with enhancing methane (CH4) recovery. The efficiency of CO2 sequestration depends on the coal-formation properties and the operating conditions. This study investigated the effects of the sodium chloride (NaCl) salinity of coal-seam water, injection flow rate, injected-gas composition, and CO2 state (formation pressure) on CO2 sequestration in coal formations. Coreflood tests were conducted on nine coal cores to simulate the injection of CO2 into coal formations. The change in the effective water/coal permeability after CO2 injection was measured. A commercial simulator was used to match the pressure drop across the core from the experimental study by adjusting the relative permeability curves. Moreover, permeability dynamic measurements were conducted to estimate the absolute permeability reduction caused by coal swelling. The effective water permeability in the tested coal decreased during CO2 injection because of its adsorption onto the coal surface, coupled with a reduction in the relative water permeability. As salt concentration increased, the change in the pressure drop across the core increased, but this effect decreased as the formation pressure increased. Higher formation pressure and lower nitrogen (N2) concentrations led to further permeability reduction as a result of the higher CO2 adsorption onto the coal surface. Furthermore, as the injection flow rate increased, the contact time of CO2 at the coal surface decreased. Hence, the CO2 adsorption to the coal matrix decreased, and thus the difference in the effective water permeability slightly decreased. CO2 injectivity in fully water-saturated formations increased initially as the gas relative permeability increased, then the injectivity decreased as a result of matrix swelling and absolute permeability reduction. Moreover, the water salinity in coal formations decreased the overall gas relative permeability and increased the water relative permeability. Similar behavior occurred in the presence of N2. It is derived from these observations that the injection of CO2 into highly volatile bituminous coal seams for CO2 sequestration purpose is more efficient as the salt concentration increases, especially at high injection pressures.
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Zhang, Xianyong, Shuangjin Zheng, and Kai Bai. "The Effect of Drilling Fluid on Coal’s Gas-Water Two-Phase Seepage." Geofluids 2022 (June 16, 2022): 1–7. http://dx.doi.org/10.1155/2022/7943696.
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In the process of coal bed methane (CBM) production, the output of CBM is mainly related to the relative permeability of gas and water in coal seams. However, during the drilling process, the invasion of drilling fluid into CBM reservoirs changes the wettability, which may cause the gas and water’s redistribution through the pores and cracks, further changing their two-phase seepage characteristics and influencing CBM production. Therefore, studying the effect of drilling fluid on coal’s gas-water two-phase seepage has practical implications. Using a steady-state method, the influence of changing wettability and reducing the solution’s interfacial tension on relative permeability is investigated by adding different surfactants. The increase in coal’s hydrophilicity exhibits an impact on its relative gas-water permeability. At the same water saturation level, the relative gas permeability decreases and the relative water permeability increases. The hydrophilicity of coal was enhanced after adding anionic surfactants, which reduced gas permeability. Cationic surfactants are difficult to adsorb to the surface of coal due to the fact that the interfacial tension of the water and coal surface is reduced when the coal seam water is added to the cationic surfactants. After adding cationic surfactants, the gas permeability increased in favor of CBM production. The findings of this study could help to better understand the influence of drilling fluid intrusion on coal’s gas-water two-phase seepage and provide technical guidance for selecting better surfactants during the preparation of drilling fluids and help to increase CBM production.
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Wang, Yong, Yunqian Long, Yeheng Sun, Shiming Zhang, Fuquan Song, and Xiaohong Wang. "Threshold Pore Pressure Gradients in Water-Bearing Tight Sandstone Gas Reservoirs." Energies 12, no. 23 (December 1, 2019): 4578. http://dx.doi.org/10.3390/en12234578.
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Tight gas reservoirs commonly occur in clastic formations having a complex pore structure and a high water saturation, which results in a threshold pressure gradient (TPG) for gas seepage. The micropore characteristics of a tight sandstone gas reservoir (Tuha oilfield, Xinjiang, China) were studied, based on X-ray diffraction, scanning electron microscopy and high pressure mercury testing. The TPG of gas in cores of the tight gas reservoir was investigated under various water saturation conditions, paying special attention to core permeability and water saturation impact on the TPG. A mathematical TPG model applied a multiple linear regression method to evaluate the influence of core permeability and water saturation. The results show that the tight sandstone gas reservoir has a high content of clay minerals, and especially a large proportion of illite–smectite mixed layers. The pore diameter is distributed below 1 micron, comprising mesopores and micropores. With a decrease of reservoir permeability, the number of micropores increases sharply. Saturated water tight cores show an obvious non-linear seepage characteristic, and the TPG of gas increases with a decrease of core permeability or an increase of water saturation. The TPG model has a high prediction accuracy and shows that permeability has a greater impact on TPG at high water saturation, while water saturation has a greater impact on TPG at low permeability.
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Lekia, S. D. L., and R. D. Evans. "A Water-Gas Relative Permeability Relationship for Tight Gas Sand Reservoirs." Journal of Energy Resources Technology 112, no. 4 (December 1, 1990): 239–45. http://dx.doi.org/10.1115/1.2905766.
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This paper presents a new approach for the analyses of laboratory-derived capillary pressure data for tight gas sands. The method uses the fact that a log-log plot of capillary pressure against water saturation is a straight line to derive new expressions for both wetting and nonwetting phase relative permeabilities. The new relative permeability equations are explicit functions of water saturation and the slope of the log-log straight line of capillary pressure plotted against water saturation. Relative permeabilities determined with the new expressions have been successfully used in simulation studies of naturally fractured tight gas sands where those determined with Corey-type expressions which are functions of reduced water saturation have failed. A dependence trend is observed between capillary pressure and gas permeability data from some of the tight gas sands of the North American Continent. The trend suggests that the lower the gas permeability, the higher the capillary pressure values at the same wetting phase saturation—especially for saturations less than 60 percent.
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Tsakiroglou, Christos D. "The correlation of the steady-state gas/water relative permeabilities of porous media with gas and water capillary numbers." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 74 (2019): 45. http://dx.doi.org/10.2516/ogst/2019017.
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The steady-state gas, k rg, and water, k rw, relative permeabilities are measured with experiments of the simultaneous flow, at varying flow rates, of nitrogen and brine (aqueous solution of NaCl brine) on a homogeneous sand column. Two differential pressure transducers are used to measure the pressure drop across each phase, and six ring electrodes are used to measure the electrical resistance across five segments of the sand column. The electrical resistances are converted to water saturations with the aid of the Archie equation for resistivity index. Both k rw and k rg are regarded as power functions of water, Caw, and gas, Cag, capillary numbers, the exponents of which are estimated with non-linear fitting to the experimental datasets. An analogous power law is used to express water saturation as a function of Caw, and Cag. In agreement to earlier studies, it seems that the two-phase flow regime is dominated by connected pathway flow and disconnected ganglia dynamics for the wetting fluid (brine), and only disconnected ganglia dynamics for the non-wetting fluid (gas). The water saturation is insensitive to changes of water and gas capillary numbers. Each relative permeability is affected by both water and gas capillary numbers, with the water relative permeability being a strong function of water capillary number and gas relative permeability depending strongly on the gas capillary number. The slope of the water relative permeability curve for a gas/water system is much higher than that of an oil/water system, and the slope of the gas relative permeability is lower than that of an oil/water system.
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Zhang, Chun Hui, and Xiao Pan Xu. "Testing Study on the Effects of Water Content on Permeability for Coal." Applied Mechanics and Materials 580-583 (July 2014): 201–4. http://dx.doi.org/10.4028/www.scientific.net/amm.580-583.201.
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To obtain the effects of water content on the permeability of coal, briquette specimen were obtained from Wulong Mine, Liaoning Province. The permeability of the air drying, bounding water and saturating specimens were tested with self-made equipment respectively, and the effects of water content on permeability for coal were studied. The results showed that: (1)The permeability of specimens decreases with confining pressure increasing, and the air drying and bounding water specimens take on obvious slippage effect. However the saturated specimens never take on slippage effects. It is because the channels of saturated coal sample are occupied by water. When the gas goes through specimens, gas never is absorbed. Collision between gas and the channel wall decreases, and the slippage effect disappears. (2) With water content increasing, the permeability of specimens decreases. (3)The permeability of specimens increases when pore pressure increases.
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Malinda, Marmora Titi, Sutopo Sutopo, and Muhammad Taufiq Fathaddin. "Improving Gas Recovery of Water Drive Gas Reservoir." Journal of Petroleum and Geothermal Technology 4, no. 2 (December 15, 2023): 71. http://dx.doi.org/10.31315/jpgt.v4i2.10261.
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A gas reservoir with bottom water drive has lower recovery factor compared to depletion drive gas reservoir. Along with the increase in gas demand and the majority of gas reservoirs are water-drive, a method that are still being developed to increase the recovey factor in water-drive gas reservoir is co-production method. This method reducing water influx by planned water production. In this study, a conceptual model of gas reservoir with depletion-drive and water-drive is build and being analyzed. Co-production technique is applied by adding one water production well to the water-drive gas reservoir. The recovery factor is being analyzed through some production scenarios. Sensitivity analysis are being done with parameters including: reservoir permeability, permeability anisotropy, aquifer volume, flow rate of water production, gas tubing head pressure, and gas well perforation interval Furthermore, experimental design, response surface methodology, and monte carlo simulation is used to analyze the influencing parameter of gas recovery factor. It is found from this study that co production increased gas recovery factor by 28% from water drive gas reservoir, with water production rate is the most influencing parameter.
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Rouf, Md A., Abdelmalek Bouazza, Rao M. Singh, Will P. Gates, and R. Kerry Rowe. "Gas flow unified measurement system for sequential measurement of gas diffusion and gas permeability of partially hydrated geosynthetic clay liners." Canadian Geotechnical Journal 53, no. 6 (June 2016): 1000–1012. http://dx.doi.org/10.1139/cgj-2015-0123.
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A gas flow unified measurement system (UMS-G) for sequential measurement of gas diffusion and gas permeability of geosynthetic clay liners (GCLs) under applied stress conditions (2 to 20 kPa) is described. Measurements made with the UMS-G are compared with measurements made with conventional experimental devices and are found to give similar results. The UMS-G removes the need to rely on two separate systems and increases further the reliability of the gas properties’ measurements. This study also shows that the gas diffusion and gas permeability reduce greatly with the increase of both gravimetric water content and apparent degree of saturation. The effect of applied stress on gas diffusion and gas permeability is found to be more pronounced at gravimetric water content greater than 60%. These findings suggest that at a nominal overburden stress of 20 kPa, the GCL used in the present investigation needs to be hydrated to 134% gravimetric water content (65% apparent degree of saturation) before gas diffusion and gas permeability drop to 5.5 × 10−11 m2·s−1 and 8.0 × 10−13 m·s−1, respectively, and to an even higher gravimetric water content (apparent degrees of saturation) at lower stress.
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Pairoys, Fabrice, and Cyril Caubit. "Water-Gas Imbibition Relative Permeability: Literature Review, Direct versus Indirect Methods and Experimental Recommendations." E3S Web of Conferences 367 (2023): 01007. http://dx.doi.org/10.1051/e3sconf/202336701007.
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When an active aquifer encroaches into a gas bearing reservoir or when an oil rim sweeps gas during late depletion of the gas cap, gas displacement by liquid is important for estimating the gas recovery. In the water displacing gas condition, the viscosity ratio is extremely favorable, resulting in a sharp waterfront in the reservoir matrix: it results that changing the relative permeability Kr shape has negligible effect, while endpoints water relative permeability Krw Max and residual gas saturation Sgr are much more important to understand gas flow performance for estimation of gas recovery with active aquifer or productivity decline after water breakthrough. Three main methods are used to determine water/gas relative permeability curves: imbibition unsteady-state, imbibition steady-state or indirect approaches such as co-current spontaneous imbibition if transient data are available. One of the other popular indirect methods is called Brooks-Corey approach: by measuring the drainage Pc curve using centrifuge or porous plate methods, it is possible to calculate a pore size distribution index c. This coefficient is used in a Brooks-Corey model to determine the drainage Kr curve. It is also required to measure and determine the relationship between the residual gas saturation Sgr and the initial gas saturation Sgi relationship. Finally, it is accepted that there is no hysteresis on the water relative permeability Krw curve, as water is always the wetting phase in the gas/water couple. As non-wetting phase, gas exhibits strong hysteresis between drainage and imbibition curves: it is therefore necessary to apply a correction on the drainage Krg curve to build the imbibition one using correcting models. The aim of this paper is to compare gas/water relative permeability of clastic rocks using direct waterflooding information and indirect approach using Brooks-Corey model. It is shown that using the indirect approach leads to results like those experimentally obtained. Also, additional numerical simulations are proposed to discuss the relevance of measuring the entire water-gas imbibition relative permeability curve using the steady-state approach.
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Wu, Yuedong, Yue Huang, Jian Liu, and Rui Chen. "A Temperature-Controlled Apparatus for Gas Permeability under Low Gas Pressure." Applied Sciences 13, no. 19 (October 3, 2023): 10943. http://dx.doi.org/10.3390/app131910943.
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The measurement of soil gas permeability is influenced by the temperature and pressure fluctuation in the low gas pressure region. In order to investigate these influences, a soil temperature-controlled apparatus connected to a low-gas-pressure supply equipment is proposed in this study. The low constant gas pressure is supplied by two Mariotte bottles, by which the airflow rate is measured. Meanwhile, the soil specimen is controlled by a temperature-controlled apparatus. During the test, the negative pore water pressure and volume change of the soil specimen are measured. Through the temperature-controlled apparatus, it is observed that as the temperature increases from 25 °C to 60 °C, there is a corresponding increase in soil sample porosity by 5.4%, while the negative pressure of pore water decreases by 11.1%. This can be attributed to the reduction in the surface tension of contractile skin caused by elevated temperatures. Furthermore, due to variations in gas viscosity with temperature, there was a significant decrease in the gas flow rate by 50.5%. And, the relationship between permeability and volumetric gas content at different temperatures in low-pressure regions well confirms the existing power-law model. In addition, the existence of a temperature-independent critical negative pore water pressure is observed, beyond which the intrinsic permeability remains constant. At 36 kPa of negative pore water pressure, the intrinsic permeability at 60 °C exhibits an 81.8% reduction compared to that at 25 °C. This decline in intrinsic permeability can be attributed to a diminished pore connectivity, resulting from elevated temperatures.
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Denney, Dennis. "Relative Permeability Hysteresis: Water-Alternating-Gas Injection and Gas Storage." Journal of Petroleum Technology 65, no. 08 (August 1, 2013): 90–92. http://dx.doi.org/10.2118/0813-0090-jpt.
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ZHANG, Tao, XiangFang LI, XiangZeng WANG, KaiYin HU, FengRui SUN, and Song HAN. "Gas-water relative permeability model for tight sandstone gas reservoirs." SCIENTIA SINICA Technologica 48, no. 10 (September 19, 2018): 1132–40. http://dx.doi.org/10.1360/n092017-00148.
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Lou, Yi, Yuliang Su, Ke Wang, Peng Xia, Wendong Wang, Wei Xiong, Linjie Shao, and Fuqin Yang. "Revealing the Effects of Water Imbibition on Gas Production in a Coalbed Matrix Using Affected Pore Pressure and Permeability." Atmosphere 13, no. 8 (August 18, 2022): 1314. http://dx.doi.org/10.3390/atmos13081314.
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The effect of water imbibition on characteristics of coalbed methane reservoirs, such as permeability, gas occurrence state, and gas production, is controversial. According to the mechanism of imbibition, gas and water distribution in blind pores is reconfigured during the fracturing process. Therefore, a new comprehensive model of pore pressure and permeability, based on the perfect gas equation and the weighted superposition of viscous flow and Knudsen diffusion, was established for micro- and nanoscale blind pores during water drainage. Using the numerical simulation module in the Harmony software, the effects of imbibition on coal pore pressure, permeability, and gas production were analyzed. The results showed that (1) water imbibition can increase pore pressure and reduce permeability, and (2) water imbibition is not always deleterious to gas production and estimated ultimate reserve (EUR), when the imbibition is constant, the thicker water film is deleterious to coalbed methane wells; when the thickness of water film is constant, more imbibition is beneficial to gas production and EUR. This research is beneficial to optimize the operation of well shut-ins after fracturing and provides methods for optimizing key parameters of gas reservoirs and insights into understanding the production mechanism of coalbed methane wells.
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Chen, Ze, Gao Li, Xu Yang, and Yi Zhang. "Experimental Study on Tight Sandstone Reservoir Gas Permeability Improvement Using Electric Heating." Energies 15, no. 4 (February 16, 2022): 1438. http://dx.doi.org/10.3390/en15041438.
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Although tight sandstone gas formations are abundant in China, their single-well productivities and exploitation efficiencies are restricted by water blocking from drilling and completion. At present, shut-in, chemical additive application, and hydraulic fracturing are the common approaches applied to handle this problem. However, these approaches are also characterized by low efficiencies or even cause secondary damage. In this study, the impact of high temperatures (of up to 800 °C) on the microstructure of a tight sandstone, including water blocking and gas permeability, are investigated through the electric heating of a simulated wellbore. The results show that the threshold temperature for fracturing of the tight sandstone is approximately 450 to 600 °C. Many secondary microcracks emerged near the wellbore beyond this temperature, improving the gas permeability, with some microcracks visible even after cooling. The gas permeability of the formation after heating to 800 °C increased by 456% and 3992% compared with the initial gas permeability and the water-blocking impacted gas permeability, respectively. This study demonstrates that electric heating is a potential method for improving the permeability of tight gas formations.
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Yan, Jian, Xiao Bing Liang, Qian Wu, and Qing Guo. "Stress Sensitivity of Low Permeable and Water-Bearing Gas Reservoir without Gas Slippage Effect." Advanced Materials Research 962-965 (June 2014): 570–73. http://dx.doi.org/10.4028/www.scientific.net/amr.962-965.570.
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Because of the gas slippage, the testing methods of stress sensitivity for gas reservoir should be different from that for oil reservoir. This text adopts the method that imposing back pressure on the outlet of testing core to weaken the gas slippage effect and tests the stress sensitivity of low permeability gas reservoirs, then analyzes the influence of permeability and water saturation on stress sensitivity. The results show that: low permeable and water-bearing gas reservoirs have strong stress sensitivity; the testing permeability has the power function relationship with net stress, compared to the exponential function, the fitting correlation coefficient is larger and more suited to the actual; the lower the permeability is and the higher water saturation is, the stronger the stress sensitivity is. The production of gas well is affected when considering the stress sensitivity, so the pressure dropping rate should be reasonable when low permeable gas reservoirs are developed. The results provide theoretical references for analyzing the well production and numerical simulation.
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Shi, Juntai, Xiangfang Li, Qian Li, Fanliao Wang, and Kamy Sepehrnoori. "Gas permeability model considering rock deformation and slippage in low permeability water-bearing gas reservoirs." Journal of Petroleum Science and Engineering 120 (August 2014): 61–72. http://dx.doi.org/10.1016/j.petrol.2014.04.019.
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Wan, Teng, Shenglai Yang, Lu Wang, and Liting Sun. "Experimental investigation of two-phase relative permeability of gas and water for tight gas carbonate under different test conditions." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 74 (2019): 23. http://dx.doi.org/10.2516/ogst/2018102.
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Currently, tight carbonate gas reservoir has received little attention due to few discoveries of them. In this study, gas–water two-phase relative permeability was measured under two different conditions: High Temperature High Pore Pressure (HTHPP – 80 °C, 38 MPa), as well as Ambient Condition (AC), using whole core samples of tight gas carbonate. Relative permeability curves obtained at HTHPP showed two contrary curve profiles of gas relative permeability, corresponding to the distinctive micro-pore structure acquired from CT-Scanning. Then, based on Klinkenberg theory and a newly developed slip factor model for tight sandstone, slippage effect under AC is calibrated and the overestimation of gas relative permeability prove up to 41.72%–52.34% in an assumed heterogeneity. In addition, relative permeability curves obtained at HTHPP switch to higher gas saturation compared to that under AC with the rock wettability change from water-wet to less water-wet. And the wettability alteration is believed to be caused by charge change on mineral surface.
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Zhan, T. L. T., Y. B. Yang, R. Chen, C. W. W. Ng, and Y. M. Chen. "Influence of clod size and water content on gas permeability of a compacted loess." Canadian Geotechnical Journal 51, no. 12 (December 2014): 1468–74. http://dx.doi.org/10.1139/cgj-2014-0126.
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The northwestern region of China is mainly semi-arid to arid and loess is ubiquitous. This natural resource has considerable potential to be transformed into earthen final covers for local landfills, but first its suitability must be ascertained through extensive tests. In this study, a device was developed to measure the gas permeability of unsaturated compacted loess specimens. Experiments were carried out to investigate the influence of clod size, compaction water content, and post-compaction water content on the gas permeability of the compacted loess. To maintain an identical soil structure, the post-compaction water content was changed using the osmotic technique. It was found that the compaction water content and resultant soil clod size exerted a combined effect on the gas permeability such that, at low water contents, the gas permeability remained fairly constant, but at high water contents the clods became relatively large, and the effect of the clod size dominated the water blockage effect from increasing water content. For specimens with identical soil structure, the gas permeability decreased with the increasing post-compaction degree of saturation at an accelerated rate. A power function is proposed to predict the relationship between the gas permeability normalized by the porosity function of the Kozeny–Carmen model and the post-compaction degree of saturation. Analysis of the experimental data indicates that the parameters for the power function still depend on the porosity of the compacted loess, particularly at high degrees of saturation.
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Pang, Mingkun, Hongyu Pan, Hang Zhang, and Tianjun Zhang. "Experimental Investigation of the Effect of Groundwater on the Relative Permeability of Coal Bodies around Gas Extraction Boreholes." International Journal of Environmental Research and Public Health 19, no. 20 (October 20, 2022): 13609. http://dx.doi.org/10.3390/ijerph192013609.
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Water infiltration in boreholes is a common problem in mine gas pre-extraction, where water infiltration can significantly reduce the efficiency of gas extraction and curtail the life cycle of the borehole. It is important to evaluate the effect of groundwater on the permeability of the coal body around a gas extraction borehole. In order to determine the seepage parameters of the fractured coal body system around the borehole, a water–gas two-phase seepage test was designed to determine the relative seepage parameters of the fractured coal media seepage system. The main conclusion is that the relative permeability of gas can be effectively increased by increasing the negative extraction pressure at the early stage of extraction to accelerate drainage to reduce the water saturation of the coal seam. Under the combined effect of porosity and seepage pressure, the relative permeability of gas and water in the fractured coal rock body shows three stages. The dependence of the total permeability on the effective stress is closely related to the stages in the evolution of the pore structure, and the total effective permeability decreases with the increase in the effective stress. A decrease in porosity can lead to a decrease in permeability and an increase in the non-Darcy factor. Through an in-depth analysis of the damage and permeability pattern of the coal body around the perimeter of the dipping borehole, the efficient and safe extraction of gas from dipping boreholes in water-rich mines is thus ensured.
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Ma, Jian, Yunlong Zhang, Jiakun Lv, and Kun Yu. "Experimental Study on Permeability Characteristics of Mudstone under High Temperature Overburden Condition." Processes 11, no. 10 (September 25, 2023): 2828. http://dx.doi.org/10.3390/pr11102828.
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High-temperature treatment significantly impacts the permeability of mudstone. The permeability of mudstone after exposure to high temperatures is closely influenced by the temperature it experiences and the stress state it is subjected to. This study examines the change in macroscopic physico-mechanical properties of mudstone with temperature following high-temperature treatment. Additionally, we conducted experimental research on the gas and water seepage behavior of mudstone specimens from the top of the coal seam of Taiyuan Group–Shanxi Group in the Ordos Basin. The coal-rock mechanics-permeability test system TAWD-2000 was employed for this purpose. Subsequently, we analyzed the evolution of mudstone permeability after high-temperature treatment with consideration to temperature, axial pressure, and other influencing factors. The findings reveal that gas permeability of mudstone gradually increases with increasing temperature, while water permeability initially decreases and subsequently increases. Furthermore, both gas and water permeability of mudstone exhibit a trend of decreasing and then increasing with rising stress levels after undergoing the same high-temperature treatment. We constructed a quadratic mathematical model with a goodness of fit of 99.4% and 89.2% to describe the relationship between temperature–stress coupling and mudstone gas and water permeability. This model underscores the significance of temperature–stress coupling on mudstone permeability and provides valuable guidance for numerically calculating the gas–water transport law of peripheral rock in the underground coal gasification process and its practical application in engineering.
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Dzhafarov, Denis, and Benjamin Nicot. "Towards Relative Permeability Measurements in Tight Gas Formations." E3S Web of Conferences 146 (2020): 05001. http://dx.doi.org/10.1051/e3sconf/202014605001.
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Relative permeability is a concept used to convey the reduction in flow capability due to the presence of multiple fluids. Relative permeability governs the multiphase flow, therefore it has a significant importance in understanding the reservoir behavior. These parameters are routinely measured on conventional rocks, however their measurement becomes quite challenging for low permeability rocks such as tight gas formations. This study demonstrates a methodology for relative permeability measurements on tight gas samples. The gas permeability has been measured by the Step Decay method and two different techniques have been used to vary the saturations: steady state flooding and vapor desorption. Series of steady-state gas/water simultaneous injection have been performed on a tight gas sample. After stabilization at each injection ratio, NMR T2, NMR Saturation profile and low pressure Step Decay gas permeability have been measured. In parallel, progressive desaturation by vapor desorption technique has been performed on twin plugs. After stabilization at each relative humidity level the NMR T2 and Step Decay gas permeability have been measured in order to compare and validate the two approaches. The techniques were used to gain insight into the tight gas two phase relative permeability of extremely low petrophysical properties (K<100 nD, phi < 5 pu) of tight gas samples of Pyrophyllite outcrop. The two methods show quite good agreement. Both methods demonstrate significant permeability degradation at water saturation higher than irreducible. NMR T2 measurements for both methods indicates bimodal T2-distributions, and desaturation first occurs on low T2 signal (small pores). Comparison of humidity drying and steady-state desaturation technique has shown a 12-18 su difference between critical water saturation (Swc) measured in gas/water steady-state injection and irreducible saturation (Swirr) measured by vapor desorption.
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Mahadevan, Jagannathan, Mukul Mani Sharma, and Yannis C. Yortsos. "Evaporative Cleanup of Water Blocks in Gas Wells." SPE Journal 12, no. 02 (June 1, 2007): 209–16. http://dx.doi.org/10.2118/94215-pa.
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Summary The flow of a gas toward the wellbore of a production well will result in the evaporative cleanup of water blocks, if the latter exist. This occurs primarily due to gas expansion. This paper presents for the first time a model to calculate the rate at which such water blocks are removed, for either fractured or unfractured gas wells. The model allows us to compute the impact of evaporative cleaning on well productivity. The removal of water first occurs by gas displacement. Evaporative cleanup is caused by gas expansion. The resulting saturation profile is qualitatively different for low- or high-permeability rocks. As a consequence, the increase in gas relative permeability, or the well productivity, with time can vary depending on the rock permeability and the well drawdown. High-permeability (e.g. fractured) rocks clean up significantly faster. By contrast, low-permeability unfractured wells may require a very long time to clean up. Large pressure drawdowns, as well as the use of more volatile fluids, such as alcohols, also result in faster cleanup. A distinctive feature of the work presented is that the model equations are formulated and solved completely without the assumption of skin factors for the damage zone. Thus, the prediction of cleanup rates can be made more accurately. Introduction Water blocks in low-permeability rocks clean up much more slowly than those of higher permeability because of the smaller pore sizes and the consequent higher capillary entry pressures (Mahadevan et al. 2003). In particular, water blocks in tight gas sands are not easily cleaned up, especially in cases where the reservoir pressures are too low to initiate flow. Past studies (Tannich 1975; Holditch 1979, Parekh and Sharma 2004) have reported the effect of water displacement by gas in the cleanup of water blocks in gas wells. They showed that when the drawdown in the gas well is significantly larger than the capillary pressure, cleanup is faster. However, in cases where the drawdown becomes comparable to the capillary pressure, as is the case in depleted tight gas reservoirs, displacement alone is not sufficient to remove water from the near-wellbore region. Subsequent water removal occurs by evaporation. The flow of a fully saturated compressible gas through a water-saturated porous rock induces evaporation. Roughly, this is because the volume of the gas, and hence its capacity for water content, increases as pressure declines. In past studies, the impact of evaporation caused by the flow of gas has been neglected. The focus of this paper is precisely on this regime in gas wells, in which the drawdown is comparable in magnitude to the capillary entry pressure, and cleanup of water blocks is by evaporation.
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ZHANG, QI, XINYUE WU, QINGBANG MENG, YAN WANG, and JIANCHAO CAI. "FRACTAL MODELS FOR GAS–WATER TRANSPORT IN SHALE POROUS MEDIA CONSIDERING WETTING CHARACTERISTICS." Fractals 28, no. 07 (November 2020): 2050138. http://dx.doi.org/10.1142/s0218348x20501388.
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Complicated gas–water transport behaviors in nanoporous shale media are known to be influenced by multiple transport mechanisms and pore structure characteristics. More accurate characterization of the fluid transport in shale reservoirs is essential to macroscale modeling for production prediction. This paper develops the analytical relative permeability models for gas–water two-phase in both organic and inorganic matter (OM and IM) of nanoporous shale using the fractal theory. Heterogeneous pore size distribution (PSD) of the shale media is considered instead of the tortuous capillaries with uniform diameters. The gas–water transport models for OM and IM are established, incorporating gas slippage described by second-order slip condition, water film thickness in IM, surface diffusion in OM, and the total organic carbon. Then, the presented model is validated by experimental results. After that, sensitivity analysis of gas–water transport behaviors based on pore structure properties of the shale sample is conducted, and the influence factors of fluid transport behaviors are discussed. The results show that the gas relative permeability is larger than 1 at the low pore pressure and water saturation. The larger pore pressure causes slight effect of gas slippage and surface diffusion on the gas relative permeability. The larger PSD fractal dimension of IM results in larger gas relative permeability and smaller water relative permeability. Besides, the large tortuosity fractal dimension will decrease the gas flux at the same water saturation, and the surface diffusion decreases with the increase of tortuosity fractal dimension of OM and pore pressure. The proposed models can provide an approach for macroscale modeling of the development of shale gas reservoirs.
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Xin, Xin, Bo Yang, Tianfu Xu, Yingli Xia, and Si Li. "Effect of Hydrate on Gas/Water Relative Permeability of Hydrate-Bearing Sediments: Pore-Scale Microsimulation by the Lattice Boltzmann Method." Geofluids 2021 (October 25, 2021): 1–14. http://dx.doi.org/10.1155/2021/1396323.
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As a clean energy source with ample reserves, natural gas hydrate is studied extensively. However, the existing hydrate production from hydrate deposits faces many challenges, especially the uncertain mechanism of complex multiphase seepage in the sediments. The relative permeability of hydrate-bearing sediments is key to evaluating gas and water production. To study such permeability, a set of pore-scale microsimulations were carried out using the Lattice Boltzmann Method. To account for the differences between hydrate saturation and hydrate pore habit, we performed a gas-water multiphase flow simulation that combines the fluids’ fundamental properties (density ratio, viscosity ratio, and wettability). Results show that the Lattice Boltzmann Method simulation is valid compared to the pore network simulation and analysis models. In gas and water multiphase flow systems, the viscous coupling effect permits water molecules to block gas flow severely due to viscosity differences. In hydrate-bearing sediments, as hydrate saturation increases, the water saturation S w between the continuous and discontinuous gas phase decreases from 0.45 to 0.30 while hydrate saturation increases from 0.2 to 0.6. Besides, the residual water and gas increased, and the capillary pressure increased. Moreover, the seepage of gas and water became more tedious, resulting in decreased relative permeability. Compared with different hydrate pore habits, pore-filling thins the pores, restricting the gas flow than the grain-coating. However, hydrate pore habit barely affects water relative permeability.
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Huang, Xiao Liang, Zhi Lin Qi, Deng Sheng Lei, and Zhi Jun Li. "Research the Degree Damage of Reverse Imbibitions to Low Permeability Water Flooding Gas Reservoir." Advanced Materials Research 524-527 (May 2012): 1203–8. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1203.
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Abstract. Low permeability water-flooding gas reservoir easy to cause the well bottom effusion in the middle of development,Effusion was often can't take out.Then with the function of capillary forces，the effusion will be absorbed in pore of rocks around the bottom well,and the Porous Medium part was block, The gas phase circulation pore canal becomes small,finally gas-phase effective permeability will be influence in the rocks,reduced pore channel permeability,made the productivity decline。The paper,the base of special experiment,analysis relation between the rate of damage about core permeability and imbibitions water saturation,and Introducing the correlation coefficient to the capacity formula of reverse imbibitions gas reservoir ,then get the capacity formula of the water flooding gas reservoir for realize the similar gas reservoir reverse imbibitions damage degree provides the basis.
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Tatur, I. R., and F. S. Bogdanova. "Research of gas permeability of protective liquids of hot water supply tanks." World of petroleum products 06 (2021): 22–26. http://dx.doi.org/10.32758/2782-3040-2021-0-6-22-26.
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The gas permeability of protective (sealing) liquids is the most important operational indicator, which determines the permeability of air oxygen through the coating film and the evaporation of water from under their layer. The results of the study of the evaporation of water located under a layer of sealing liquid are presented. The dependence of water evaporation on the composition and thickness of the sealing liquid layer on the water surface is established. It is shown that the sealing liquids, which include polyisobutylene of the P-200 brand, have the lowest gas permeability. The interrelation of gas permeability of sealing liquids with other operational indicators – thermal and oxidative stability, surface and protective properties is revealed.
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Zhang, Xian Tang, Kang Ning Gao, Xiao Chen Zhou, and Hong Li Wang. "Studies on Influence of Mineral Admixtures on High Performance Concrete Gas Permeability." Applied Mechanics and Materials 99-100 (September 2011): 762–67. http://dx.doi.org/10.4028/www.scientific.net/amm.99-100.762.
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There is a close relationship between the gas permeability of modern high strength concrete and the concrete durability. Through the Cembureau method, gas permeability coefficients of ordinary concrete and concrete with admixtures under different maintenance periods were tested. We studied the influence of fly ash and slag on high performance concrete gas permeability, and analysed the rules of gas permeability changing with mineral admixtures and the water-binder ratio, and gave the reasonable range of mineral admixtures and the water-binder ratio. The results from the paper may have the certain reference value to practical application.
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Xu, Chun Mei, Xing Hong Wang, and Fang Yuan Guo. "Water Locking Mechanics Characteristics and Countermeasures of Low Permeability Gas Reservoir." Advanced Materials Research 680 (April 2013): 307–11. http://dx.doi.org/10.4028/www.scientific.net/amr.680.307.
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The research goal of this paper is reducing damage of low permeability gas reservoir, utilizing the natural cores which from low permeability gas reservoir as ex-periment model, based on similarity theory conducting the fluid-structure interaction experiment of reservoir fluid and injection working fluid with cores, the experimental results show that the effect of gas well reservoir fluid and external fluid with cores, it is inevitable to produce water locking mechanical for the cores which from low permeability gas reservoir, and carry out the corresponding control measures experiment research, and put forward that add alcohol to injection fluid can inhibit water locking.