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Relevant bibliographies by topics / Water and gas permeability

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Academic literature on the topic 'Water and gas permeability'

Author: Grafiati

Published: 18 May 2024

Last updated: 19 October 2024

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Journal articles on the topic "Water and gas permeability"

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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2

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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3

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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4

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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5

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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6

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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7

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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8

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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9

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.

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Dissertations / Theses on the topic "Water and gas permeability"

1

Mulyadi, Henny. "Determination of residual gas staturation and gas-water relative permeability in water-driven gas reserviors /." Full text available, 2002. http://adt.curtin.edu.au/theses/available/adt-WCU20030702.131009.

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2

Mulyadi, Henny. "Determination of residual gas saturation and gas-water relative permeability in water-driven gas reservoirs." Thesis, Curtin University, 2002. http://hdl.handle.net/20.500.11937/1294.

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The research on Determination of Residual Gas Saturation and Gas-Water Relative Permeability in Water-Driven Gas Reservoirs is divided into four stages: literature research, core-flooding experiments, development and application of a new technique for reservoir simulation. Overall, all stages have been completed successfully with several breakthroughs in the areas of Special Core Analysis (SCAL), reservoir engineering and reservoir simulation technology.Initially, a literature research was conducted to survey all available core analysis techniques and their individual characteristics. The survey revealed that there are several core analysis techniques for measuring residual gas saturation (Sgr) and hence, the lack of a commonly agreed method for measuring Sgr. The often-used core analysis techniques are steady-state displacement, co-current imbibition, centrifuge and counter-current imbibition. In this research, all centrifuge tests were performed with a decane-brine system to investigate the possibility of replacing gas with a 'model fluid' to minimise errors due to gas compressibility. Furthermore, Sgr is a function of testing temperature and pressure, types of fluid, wettability, viscosity, flow rate and overburden pressure. Consequently, large uncertainties are associated with measured Sgr and the recoverable gas reserves for water-driven gas reservoirs.Due to the lack of a common method for measuring Sgr, the first important step is to clarify which is the most representative core analysis technique for measuring Sgr. In Stage 2 of the research, core analysis experiments were performed with uniform fluids and ambient temperature. In the core flooding experiments, four different sets of core plugs from various gas reservoirs were selected to cover a wide range of permeability and porosity. Finally, all measured Sgr from the various common core analysis techniques were compared.The evidence suggested that steady-state displacement and co-current imbibition tests are the most representative techniques for reservoir application. Steady-state displacement also yields the complete relative permeability (RP) data but it requires long stabilisation times and is costly.In the third stage, a new technique was successfully developed for determining both Sgr and gas-water RP data. The new method consists of an initial co-current imbibition experiment followed by the newly developed correlation (Mulyadi, Amin and Kennaird correlation). Co-current imbibition is used to measure the end-point data, for example, initial water saturation (Swi) and Sgr. The MAK correlation was developed to extend the co-current imbibition test by generating gas-water relative permeability data. Unlike previous correlations, MAK correlation is unique because it incorporates and exhibits the formation properties, reservoir conditions and fluid properties (for example, permeability, porosity, interfacial tension and gas density) to generate the RP curves. The accuracy and applicability of MAK correlations were investigated with several sets of gas-water RP data measured by steady-state displacement tests for various gas reservoirs in Australia, New Zealand, South-East Asia and U.S.A. The MAK correlation proved superior to previously developed correlations to demonstrate its robustness.The purpose of the final stage was to aggressively pursue the possibility of advancing the application of the new technique beyond special core analysis (SCAL). As MAK correlation is successful in describing gas water RP in a core plug scale, it is possible to extend its application to describe the overall reservoir flow behaviour. This investigation was achieved by implementing MAK correlation into a 3-D reservoir simulator (MoReS) and performing simulations on a producing field.The simulation studies were divided into two categories: pre and post upscaled application.The case studies were performed on two X gas-condensate fields: X1 (post upscaled) and X2 (pre upscaled) fields. Since MAK correlation was developed for gas-water systems, several modifications were required to account for the effect of the additional phase (oil) on gas and water RP in gas-condensate systems. In this case, oil RP data was generated by Corey's equations. Five different case studies were performed to investigate the individual and combination effect of implementing MAK correlation, alternative Swi and Sgr correlations and refining porosity and permeability clustering. Moreover, MAK correlation has proven to be effective as an approximation technique for cell by cell simulation to advance reservoir simulation technology.

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3

Mulyadi, Henny. "Determination of residual gas saturation and gas-water relative permeability in water-driven gas reservoirs." Curtin University of Technology, Department of Petroleum Engineering, 2002. http://espace.library.curtin.edu.au:80/R/?func=dbin-jump-full&object_id=12957.

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The research on Determination of Residual Gas Saturation and Gas-Water Relative Permeability in Water-Driven Gas Reservoirs is divided into four stages: literature research, core-flooding experiments, development and application of a new technique for reservoir simulation. Overall, all stages have been completed successfully with several breakthroughs in the areas of Special Core Analysis (SCAL), reservoir engineering and reservoir simulation technology.Initially, a literature research was conducted to survey all available core analysis techniques and their individual characteristics. The survey revealed that there are several core analysis techniques for measuring residual gas saturation (Sgr) and hence, the lack of a commonly agreed method for measuring Sgr. The often-used core analysis techniques are steady-state displacement, co-current imbibition, centrifuge and counter-current imbibition. In this research, all centrifuge tests were performed with a decane-brine system to investigate the possibility of replacing gas with a 'model fluid' to minimise errors due to gas compressibility. Furthermore, Sgr is a function of testing temperature and pressure, types of fluid, wettability, viscosity, flow rate and overburden pressure. Consequently, large uncertainties are associated with measured Sgr and the recoverable gas reserves for water-driven gas reservoirs.Due to the lack of a common method for measuring Sgr, the first important step is to clarify which is the most representative core analysis technique for measuring Sgr. In Stage 2 of the research, core analysis experiments were performed with uniform fluids and ambient temperature. In the core flooding experiments, four different sets of core plugs from various gas reservoirs were selected to cover a wide range of permeability and porosity. Finally, all measured Sgr from the various common core analysis techniques ++
were compared.The evidence suggested that steady-state displacement and co-current imbibition tests are the most representative techniques for reservoir application. Steady-state displacement also yields the complete relative permeability (RP) data but it requires long stabilisation times and is costly.In the third stage, a new technique was successfully developed for determining both Sgr and gas-water RP data. The new method consists of an initial co-current imbibition experiment followed by the newly developed correlation (Mulyadi, Amin and Kennaird correlation). Co-current imbibition is used to measure the end-point data, for example, initial water saturation (Swi) and Sgr. The MAK correlation was developed to extend the co-current imbibition test by generating gas-water relative permeability data. Unlike previous correlations, MAK correlation is unique because it incorporates and exhibits the formation properties, reservoir conditions and fluid properties (for example, permeability, porosity, interfacial tension and gas density) to generate the RP curves. The accuracy and applicability of MAK correlations were investigated with several sets of gas-water RP data measured by steady-state displacement tests for various gas reservoirs in Australia, New Zealand, South-East Asia and U.S.A. The MAK correlation proved superior to previously developed correlations to demonstrate its robustness.The purpose of the final stage was to aggressively pursue the possibility of advancing the application of the new technique beyond special core analysis (SCAL). As MAK correlation is successful in describing gas water RP in a core plug scale, it is possible to extend its application to describe the overall reservoir flow behaviour. This investigation was achieved by implementing MAK correlation into a 3-D reservoir simulator (MoReS) and performing simulations on a producing ++
field.The simulation studies were divided into two categories: pre and post upscaled application.The case studies were performed on two X gas-condensate fields: X1 (post upscaled) and X2 (pre upscaled) fields. Since MAK correlation was developed for gas-water systems, several modifications were required to account for the effect of the additional phase (oil) on gas and water RP in gas-condensate systems. In this case, oil RP data was generated by Corey's equations. Five different case studies were performed to investigate the individual and combination effect of implementing MAK correlation, alternative Swi and Sgr correlations and refining porosity and permeability clustering. Moreover, MAK correlation has proven to be effective as an approximation technique for cell by cell simulation to advance reservoir simulation technology.

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4

Al-Kharusi, Badr Soud. "Relative permeability of gas-condensate near wellbore, and gas-condensate-water in bulk of reservoir." Thesis, Heriot-Watt University, 2000. http://hdl.handle.net/10399/1098.

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5

Al-Shajalee, Faaiz Hadi Rasheed. "Relative Permeability Modification in Gas Wells with Excessive Water Production- An Experimental Investigation." Thesis, Curtin University, 2021. http://hdl.handle.net/20.500.11937/89365.

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Polymers have been used as relative permeability modifiers (RPM) to selectively reduce water production with minimum effect on the hydrocarbon phase. The experimental results show that initial rock permeability can be used as an important screening parameter in planning an RPM treatment. The relative pore size alteration due to the RPM treatment impacts on RPM performance. The RPM performance is also significantly fluid flow rate dependent. Therefore, flow rate should be considered during RPM design.

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6

Sidiq, Hiwa. "Advance water abatement in oil and gas reservoir." Thesis, Curtin University, 2007. http://hdl.handle.net/20.500.11937/191.

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The control of excessive water production in oil and gas producing wells is of increasing importance to the field operator, primarily when trying to maintain the survivability of a mature field from shut in. During the last two decades many chemicals have been studied and applied under the name of relative permeability modifier (RPM) to combat this problem. These chemicals were mostly bullheaded individually into the affected zones, consequently their application resulted in low to medium success, particularly in treating reservoirs suffering from matrix flow. It has been found that the disproportionate permeability reduction depends on the amount of polymer dispersed or absorbed by the porous rock. If single polymers are employed to treat excessive water production in a matrix reservoir they cannot penetrate deep into the formation rock because the polymer will start to build as a layer on the surface of the rock grains. As a result the placement of polymer into the formation will no be piston like and the dispersion over the rock pores will be uneven. To improve water shutoff technology a method of injecting chemicals sequentially is recommended provided that the chemical’s viscosity is increasing successively with the chemicals injected.Experimentally confirmed, injecting chemicals sequentially provides better results for conformance control. The value of post treatment water mobility is conspicuously lowered by the method of applying injecting chemicals sequentially in comparison with the single chemical injection method. For instance, the residual resistance factor to water (Frrw) at the first cycle of brine flushing for this method is approximately five times higher than the Frrw obtained by injecting only one single chemical. Furthermore, for the second cycle of brine flushing Frrw is still higher by a ratio of about 2.5. In addition to this improvement residual resistance factor to oil Frro for this method is less than two which has been considered as the upper limit for conformance control in matrix reservoir. Accordingly injecting chemical sequentially can be applied for enhancing relative permeability modifier performance in matrix reservoir.

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7

Sidiq, Hiwa. "Advance water abatement in oil and gas reservoir." Curtin University of Technology, Department of Chemical Engineering, 2007. http://espace.library.curtin.edu.au:80/R/?func=dbin-jump-full&object_id=17578.

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The control of excessive water production in oil and gas producing wells is of increasing importance to the field operator, primarily when trying to maintain the survivability of a mature field from shut in. During the last two decades many chemicals have been studied and applied under the name of relative permeability modifier (RPM) to combat this problem. These chemicals were mostly bullheaded individually into the affected zones, consequently their application resulted in low to medium success, particularly in treating reservoirs suffering from matrix flow. It has been found that the disproportionate permeability reduction depends on the amount of polymer dispersed or absorbed by the porous rock. If single polymers are employed to treat excessive water production in a matrix reservoir they cannot penetrate deep into the formation rock because the polymer will start to build as a layer on the surface of the rock grains. As a result the placement of polymer into the formation will no be piston like and the dispersion over the rock pores will be uneven. To improve water shutoff technology a method of injecting chemicals sequentially is recommended provided that the chemical’s viscosity is increasing successively with the chemicals injected.
Experimentally confirmed, injecting chemicals sequentially provides better results for conformance control. The value of post treatment water mobility is conspicuously lowered by the method of applying injecting chemicals sequentially in comparison with the single chemical injection method. For instance, the residual resistance factor to water (Frrw) at the first cycle of brine flushing for this method is approximately five times higher than the Frrw obtained by injecting only one single chemical. Furthermore, for the second cycle of brine flushing Frrw is still higher by a ratio of about 2.5. In addition to this improvement residual resistance factor to oil Frro for this method is less than two which has been considered as the upper limit for conformance control in matrix reservoir. Accordingly injecting chemical sequentially can be applied for enhancing relative permeability modifier performance in matrix reservoir.

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8

Sagbana, Perekaboere Ivy. "Effect of surfactant on three phase relative permeability in water-alternating-gas flooding experiment." Thesis, London South Bank University, 2017. http://researchopen.lsbu.ac.uk/1848/.

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Three-phase flow occurs in petroleum reservoirs during tertiary enhanced oil recovery processes such as water-alternating-gas flooding (WAG). WAG process is used to improve the efficiency of gas flooding by controlling gas mobility. Water traps gas in the reservoir when injected alternatively in WAG. Continuous gas trapping causes a blocking effect that prevents the oil from being contacted by the water. Surfactants are introduced in WAG processes to decrease this water blocking effect and improve oil recovery. This technique of introducing surfactant in WAG processes is known as surfactant-alternating-gas flooding (SAG). One of the important parameters to accurately model complex processes such as SAG is the relative permeability to each of the flowing fluids. However, relative permeability in SAG processes become extremely complicated due to different flow mechanisms and fluid interactions involved. Several researches in the open literature are based on three-phase relative permeability in WAG using three-phase empirical correlations for prediction. Few researchers have conducted experiments on SAG flooding, but their research focused on the aspect of oil recovery only. The aim of this research project is to obtain a better understanding of surfactant interaction in three-phase flow. To do so, a surfactant formulation compatible with the oil and brine was selected by conducting aqueous stability test, surfactant phase behaviour and surfactant adsorption experiments. Water/oil interfacial tension was measured to determine the initial interfacial tension before surfactant injection. Surfactant/oil interfacial tension was calculated using Huh’s correlation. This was followed by two and three-phase core flooding experiments. The results showed that alcohol alkoxy sulphate and internal olefin surfactant blend is most suitable formulation compatible with the brine and oil by reducing water/oil interfacial tension from 22.7 mN/m to 1 x 10- ³ mN/m and having very low adsorption of 0.00135 mg/g adsorption on the core sample. Two-phase water/oil, gas/oil and gas/water experiments were conducted with and without surfactants to evaluate the effect of surfactants when only two fluids are present in the porous media. Sigmund and McCaffery correlation was used in Sendra software to history match experimental differential pressure and oil production data to obtain relative permeability curves. The results showed that in water/oil displacement experiment, the presence of surfactant increases oil relative permeability but did not have any effect on water relative permeability. The cross point of the relative permeability curves moved further to the right indicating that surfactant increases the water wetness of the core sample causing oil to flow freely. Oil production increased in the presence of surfactant, this increase in oil production is because of the reduction in water/oil interfacial tension and decrease in pressure gradient during the experiment. There was an increase in oil production and oil relative permeability also in gas/oil displacement experiment in the presence of surfactant when compared to gas/oil displacement experiment without surfactant. While in gas/water displacement experiment, a significant decrease in gas relative permeability occurred in the presence of surfactant when compared to gas/water displacement experiment with no surfactant. To study surfactant effect on three-phase relative permeability, WAG and SAG core flooding experiments were conducted. The extension of JBN/Welge theory by Grader and O’Meara was applied to calculate three phase relative permeability. Eclipse reservoir simulation software was used to simulate surfactant WAG to predict surfactant effect on three-phase relative permeability using the three-phase correlations such as Stone 1, Stone 2, saturated weighted interpolation, linear interpolation and Stone exponent present in the software. Results from three-phase displacement experiments showed that the presence of surfactant does not have any effect on water relative permeability in three-phase flow. Oil relative permeability was affected by the presence of surfactant and gas. Oil relative permeability and recovery factor were higher in SAG when compared to WAG. In three-phase flow, gas relative permeability was lower in SAG compared to WAG. Gas breakthrough in the presence surfactant occurred at 0.48pore volume while in WAG breakthrough occurred at 0.34 pore volume. The decrease in gas relative permeability was because of foam creation with gas interaction with the surfactant. None of the three-phase relative permeability correlations could accurately predict the effect surfactant on three-phase relative permeability in WAG.

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9

Calisgan, Huseyin. "Comprehensive Modelling Of Gas Condensate Relative Permeability And Its Influence On Field Performance." Phd thesis, METU, 2005. http://etd.lib.metu.edu.tr/upload/12606667/index.pdf.

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The productivity of most gas condensate wells is reduced significantly due to condensate banking when the bottom hole pressure falls below the dew point. The liquid drop-out in these very high rate gas wells may lead to low recovery problems. The most important parameter for determining condensate well productivity is the effective gas permeability in the near wellbore region, where very high velocities can occur. An understanding of the characteristics of the high-velocity gas-condensate flow and relative permeability data is necessary for accurate forecast of well productivity. In order to tackle this goal, a series of two-phase drainage relative permeability measurements on a moderate permeability North Marmara &ndash
1 gas well carbonate core plug sample, using a simple synthetic binary retrograde condensate fluid sample were conducted under reservoir conditions which corresponded to near miscible conditions. As a fluid system, the model of methanol/n-hexane system was used as a binary model that exhibits a critical point at ambient conditions. The interfacial tension by means of temperature and the flow rate were varied in the laboratory measurements. The laboratory experiments were repeated for the same conditions of interfacial tension and flow rate at immobile water saturation to observe the influence of brine saturation in gas condensate systems. The laboratory experiment results show a clear trend from the immiscible relative permeability to miscible relative permeability lines with decreasing interfacial tension and increasing velocity. So that, if the interfacial tension is high and the flow velocity is low, the relative permeability functions clearly curved, whereas the relative permeability curves straighten as a linear at lower values of the interfacial tension and higher values of the flow velocity. The presence of the immobile brine saturation in the porous medium shows the same shape of behavior for relative permeability curves with a small difference that is the initial wetting phase saturations in the relative permeability curve shifts to the left in the presence of immobile water saturation. A simple new mathematical model is developed to compute the gas and condensate relative permeabilities as a function of the three-parameter. It is called as condensate number
NK so that the new model is more sensitivity to temperature that represents implicitly the effect of interfacial tension. The new model generated the results were in good agreement with the literature data and the laboratory test results. Additionally, the end point relative permeability data and residual saturations satisfactorily correlate with literature data. The proposed model has fairly good fitness results for the condensate relative permeability curves compared to that of gas case. This model, with typical parameters for gas condensates, can be used to describe the relative permeability behavior and to run a compositional simulation study of a single well to better understand the productivity of the field.

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Sole, Joshua David. "Investigation of Water Transport Parameters and Processes in the Gas Diffusion Layer of PEM Fuel Cells." Diss., Virginia Tech, 2008. http://hdl.handle.net/10919/27538.

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Constitutive relationships are developed to describe the water transport characteristics of the gas diffusion layer (GDL) of proton exchange membrane fuel cells (PEMFCs). Additionally, experimental fixtures and procedures for the determination of the constitutive relationships are presented. The water transport relationships are incorporated into analytical models that assess the impact of the water transport relations and that make PEMFC performance predictions. The predicted performance is then compared to experimental results. The new constitutive relationships are significantly different than the currently popular relationships used in PEMFC modeling because they are derived from experiments on actual PEMFC gas diffusion layer materials. In prior work, properties of the GDL materials such as absolute permeability, liquid water relative permeability, porosity, and capillary behavior are often assumed or used as adjustment parameters in PEMFC models to simplify the model or to achieve good fits with polarization data. In this work, the constitutive relations are not assumed but are determined via newly developed experimental techniques. The experimental fixtures and procedures were used to characterize common GDL materials including carbon papers and carbon cloths, and to investigate common treatments applied to these materials such as the bulk application of a hydrophobic polymer within the porous structure. A one-dimensional model is developed to contrast results based on the new constitutive relations with results based on commonly used relationships from the PEMFC literature. The comparison reveals that water transport relationships can have a substantial impact on predicted GDL saturation, and consequently a significant impact on cell performance. The discrepancy in saturation between cases can be nearly an order of magnitude. A two-dimensional model is also presented that includes the impact of the compressed GDL region under the shoulder of a bipolar plate. Results show that the compression due to the bipolar plate shoulder causes a significant increase in liquid saturation, and a significant reduction in oxygen concentration and current density for the paper GDL. In contrast, compression under the shoulder has a minimal impact on the cloth GDL. Experimental inputs to the 2-D model include: absolute permeability, liquid water relative permeability, the slope of the capillary pressure function with saturation, total porosity, GDL thickness, high frequency resistance, and appropriate Tafel parameters. Computational polarization curve results are compared to experimental polarization behavior and good agreement is achieved.
Ph. D.

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Books on the topic "Water and gas permeability"

1

A, Tomazic William, and United States. National Aeronautics and Space Administration., eds. Effect of water on hydrogen permeability. [Washington, D.C: National Aeronautics and Space Administration, 1987.

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Patenaude, Armand. Migration of water by capillarity. [Ottawa]: CMHC, 1993.

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Patenaude, Armand. Migration of water by capillarity. Ottawa, Ont: Canada Mortgage and Housing Corporation, 1993.

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Vilma, Ortiz, ed. Water: Liquid, solid, gas. Bothell, WA: Wright Group/McGraw-Hill, 2000.

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Frost, Helen. Water as a gas. Mankato, Minn: Pebble Books, 2000.

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Nissen-Petersen, Erik. Water from dry riverbeds. Nairobi: ASAL Consultants Ltd. for the Danish International Development Assistance, 2006.

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Emerson, Douglas G. Documentation of a heat and water transfer model for seasonally frozen soils with application to the precipitation-runoff model. Bismarck, N.D: U.S. Dept. of the Interior, U.S. Geological Survey, 1991.

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North Dakota State Water Commission and Geological Survey (U.S.), eds. Documentation of a heat and water transfer model for seasonally frozen soils with application to the precipitation-runoff model. Bismarck, N.D: U.S. Dept. of the Interior, U.S. Geological Survey, 1991.

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Juhani, Hartikainen, ed. Helium gas methods for rock characteristics and matrix diffusion. Helsinki: Posiva Oy, 1996.

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Burns, Karen. Gas permeation measurements on small polymer specimens: Final report. Norfolk, Va: Dept. of Chemical Sciences, College of Sciences, Old Dominion University, 1989.

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Book chapters on the topic "Water and gas permeability"

1

Sato, Shuichi, Sou Miyata, Shinji Kanehashi, and Kazukiyo Nagai. "Gas Permeability and Electrical Properties of 6FDA-Based Polyimide Membranes." In Sustainable Membrane Technology for Energy, Water, and Environment, 75–86. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2012. http://dx.doi.org/10.1002/9781118190180.ch7.

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Ng, Charles W. W., Chao Zhou, and Junjun Ni. "Retention characteristics and permeability functions for water and gas flows." In Advanced Unsaturated Soil Mechanics, 65–145. 2nd ed. London: CRC Press, 2024. http://dx.doi.org/10.1201/9781003480587-3.

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Cui, Yue-hua, Yi-fei Lan, Hui-hui Liu, Jin-cheng Wang, Xiao-ling Meng, and Zhun-bei Wang. "New Method of Gas and Water Layer Identification of Low Permeability Carbonate Gas Reservoir." In Springer Series in Geomechanics and Geoengineering, 2128–43. Singapore: Springer Singapore, 2021. http://dx.doi.org/10.1007/978-981-16-0761-5_200.

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Ouyang, Wei-ping, Yun-yi Zhang, and Mian Zhang. "Water Production Prediction in Tight and Low Pressure Gas Wells Considering the Dynamic Change of Gas-Water Permeability Relationship." In Springer Series in Geomechanics and Geoengineering, 1154–66. Singapore: Springer Singapore, 2021. http://dx.doi.org/10.1007/978-981-16-0761-5_108.

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Kerstiens, Gerhard. "Air Pollutants and Plant Cuticles: Mechanisms of Gas and Water Transport, and Effects on Water Permeability." In Air Pollutants and the Leaf Cuticle, 39–53. Berlin, Heidelberg: Springer Berlin Heidelberg, 1994. http://dx.doi.org/10.1007/978-3-642-79081-2_3.

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Zhao, Le-kun, Tong-jing Liu, Juan Ni, Fu-qiang Han, and Yue-dong Yao. "Research on Water Alternating Gas (WAG) Flooding Dynamic Adjustment of Water-Gas Ratio and Slug Sizes Method in Low Permeability Reservoir." In Springer Series in Geomechanics and Geoengineering, 912–26. Singapore: Springer Nature Singapore, 2024. http://dx.doi.org/10.1007/978-981-97-0264-0_82.

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Zhang, Chun, Chang-cheng Yang, Yue-yang Li, Chang-hai Xu, Jun Jiang, and Yu Pang. "Gas and Water Distribution Patterns and Development Suggestions for Low Permeability and Thick Bottom Water Gas Reservoirs with Low Amplitude Structures." In Springer Series in Geomechanics and Geoengineering, 663–74. Singapore: Springer Nature Singapore, 2024. http://dx.doi.org/10.1007/978-981-97-0468-2_50.

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Frenzel, H., W. Kessels, A. Hartmann, M. Lengnick, G. Zoth, and K. Nolting. "Determination of Gas Permeability by Interpreting Barometric Pressure Induced Water Level Variations in Boreholes." In Field Screening Europe, 81–84. Dordrecht: Springer Netherlands, 1997. http://dx.doi.org/10.1007/978-94-009-1473-5_19.

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Lv, Wei, Shi-tou Wang, Ming Liu, and Lei Wang. "Main Factors of Production with CO2 Water-Alternating-Gas Injection in Low Permeability Reservoirs." In Proceedings of the International Field Exploration and Development Conference 2021, 3363–77. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-2149-0_314.

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Shi, Hai-dong, Qing-sheng Wang, Sen-lin Bai, Chun-qiu Guo, Yue Zheng, Mu-wei Cheng, and Yu-zhong Xing. "Length Optimization for Horizontal Interval of Low Permeability Carbonate Gas Reservoir with Bottom Water." In Springer Series in Geomechanics and Geoengineering, 2184–91. Singapore: Springer Nature Singapore, 2023. http://dx.doi.org/10.1007/978-981-99-1964-2_186.

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Conference papers on the topic "Water and gas permeability"

1

Dietzel, H. J., and G. A. Von Hantelmann. "Stimulating Water-Sensitive Formations at High Reservoir Temperature." In SPE/DOE Low Permeability Gas Reservoirs Symposium. Society of Petroleum Engineers, 1985. http://dx.doi.org/10.2118/13875-ms.

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Wang, Shuai, Ji Tian, Xianhong Tan, Ling Wang, and Shaohui Zhang. "Permeability Limits of Advanced Water Injection Technology in Low Permeability Reservoirs." In SPE Asia Pacific Oil & Gas Conference and Exhibition. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/182431-ms.

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Berry, J. F., A. J. H. Little, and R. C. Skinner. "Differences in Gas/Oil and Gas/Water Relative Permeability." In SPE/DOE Enhanced Oil Recovery Symposium. Society of Petroleum Engineers, 1992. http://dx.doi.org/10.2118/24133-ms.

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Liu, Renjing, Huiqing Liu, Xiusheng Li, Jing Wang, and Changting Pang. "Calculation of Oil and Water Relative Permeability for Extra Low Permeability Reservoir." In International Oil and Gas Conference and Exhibition in China. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/131388-ms.

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Liu, Xiaojuan, Jian Yan, and Yi Liu. "Gas Slippage Effect in Low Permeability Water-bearing Gas Reservoirs." In SPE Reservoir Characterisation and Simulation Conference and Exhibition. Society of Petroleum Engineers, 2011. http://dx.doi.org/10.2118/145803-ms.

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Zhang, Mengchuan, Yanwen Duan, Jiajun He, Leifeng Meng, Tianbo Liang, Hao Bai, and Fujian Zhou. "Dynamic Characterization of Water Blockage During Water-Gas Alternated Flooding in the Underground Gas Storage." In 56th U.S. Rock Mechanics/Geomechanics Symposium. ARMA, 2022. http://dx.doi.org/10.56952/arma-2022-2327.

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ABSTRACT: As the main type of underground gas storage, the depleted gas reservoir is susceptible to the formation water. Limited by the current in-situ characterization methods, it remains unknown how relative permeabilities and distribution of water and gas change during different injection-production cycles at the non-Darcy-flow condition. In this paper, an unsteady-state water-gas relative permeability measurement method is established based on the in-situ CT scans and modified JBN calculation method. The water-gas distribution and water-gas relative permeability variation under the influence of different injection-production schemes are systematically revealed. The coreholder is improved to meet the measurement requirements of at least 30cm long core. The gasdisplacing-water coreflood is carried out under CT scans to obtain the water saturation of each scanning section at different displacement times. The axial distribution of water fractional flow in the core at different displacement times is calculated according to the improved water phase partial flow calculation method, and then the water-gas relative permeability curve is obtained according to the improved unsteady water-gas relative permeability calculation method. Then, multiple cycles of water-gas alternate injection are carried out on the same core to understand the change of water-gas relative permeability and residual phase distributions under different injection and production cycles. Compared with the conventional method, the influence of capillary effects can be effectively reduced, and the measurement accuracy is improved by 30%.. With the increase of injection production cycles, the gas-phase relative permeability decreases and the water-phase relative permeability increases, meanwhile, reduced efficiency of gas-displacing-water in the co-permeability area, and the gas is easier to break through, resulting in a residual water saturation increase 6%. 1. INTRODUCTION Underground gas storage is the most important and irreplaceable means of natural gas storage and peaking, with the advantages of large storage capacity, wide peaking range, low gas storage cost and high safety factor (Ding et al., 2006). The relative permeability curve describes the relationship between the relative permeability of each phase of fluid and its phase saturation, which is a key parameter for multiphase porous flow calculation and dynamic analysis of oil and gas reservoirs. At the same time, it is also an important basis for capacity prediction of underground gas storage and optimization of cyclic injection and extraction system.

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Alarifi, Sulaiman A. "Oil-Water Relative Permeability Prediction Using Machine Learning." In Middle East Oil, Gas and Geosciences Show. SPE, 2023. http://dx.doi.org/10.2118/213336-ms.

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Abstract Relative permeability is one of the most significant reservoir characteristics in the petroleum industry. It captures the fluids behavior inside the porous space within the reservoir. It considers the effective permeability of the fluids in the reservoir which ultimately lead to the understanding of the fluid behavior inside the pores. Also, using relative permeability curves, we can estimate the reservoir's oil or gas recovery. Furthermore, enhanced oil recovery techniques utilize relative permeability curves to evaluate their performance. The well-known practice to develop any relative permeability curve is by conducting core flooding experiments which are relatively time consuming especially if it is needed to be done on several wells with different core samples. Also, it would be costly data set to acquire since it requires special lab sets and conditions. Time and cost are the main factors making relative permeability a very hard to obtain information for any reservoir. Several models and empirical relations have been built to calculate and present relative permeability without going through the lab experiments, each model has its uncertainty. This paper captures the approach to predict relative permeability curves (oil and water) from a set of data collected from one reservoir using machine learning. Data used is generated from special core analysis lab experiments (core flooding) of unsteady state oil and water relative permeability. Core flooding experiments represents several water saturations at which the core been flooded to, at every water saturation a water and an oil relative permeability value is obtained. To represent the reservoir efficiently and addressing several aspects of its 56 relative permeability curves (from 56 composites) have been collected from different wells in the same reservoir. Adding up to a total of more than 7,000 data sets (different water saturations). Two models have been built, one for predicting the relative permeability of oil at several water saturations and the second model is for the relative permeability of water. Main input data are water saturations, connate water saturation, residual oil saturation, porosity, oil viscosity, water viscosity, (several basic core properties) and wettability. The outcome for each model is one, either oil or water relative permeability. The main added value of this work is creating a workflow and models to predict water and oil relative permeability using main reservoir data with high accuracy and without conducting any special core analysis.

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Gruber, N. G. "Water Block Effects In Low Permeability Gas Reservoirs." In Annual Technical Meeting. Petroleum Society of Canada, 1996. http://dx.doi.org/10.2118/96-92.

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Mulyadi, H., R. Amin, and A. F. Kennaird. "Practical Approach to Determine Residual Gas Saturation and Gas-Water Relative Permeability." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2001. http://dx.doi.org/10.2118/71523-ms.

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Su, Kun, Jorge Torres, Yonatan Sanz Perl, Pierre Barlet, and Sandrine Vidal-Gilbert. "Tests of Fracture Water and Gas Permeability on Vaca Muerta Gas Shale." In Unconventional Resources Technology Conference. Tulsa, OK, USA: American Association of Petroleum Geologists, 2017. http://dx.doi.org/10.15530/urtec-2017-2671318.

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Reports on the topic "Water and gas permeability"

1

Coyner, K., T. J. Katsube, M. E. Best, and M. Williamson. Gas and water permeability of tight shales from the Venture gas field, offshore Nova Scotia. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 1993. http://dx.doi.org/10.4095/134279.

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Terry Brown, Jeffrey Morris, Patrick Richards, and Joel Mason. Effects of Irrigating with Treated Oil and Gas Product Water on Crop Biomass and Soil Permeability. Office of Scientific and Technical Information (OSTI), September 2010. http://dx.doi.org/10.2172/1007996.

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Lacerda Silva, P., G. R. Chalmers, A. M. M. Bustin, and R. M. Bustin. Gas geochemistry and the origins of H2S in the Montney Formation. Natural Resources Canada/CMSS/Information Management, 2022. http://dx.doi.org/10.4095/329794.

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The geology of the Montney Formation and the geochemistry of its produced fluids, including nonhydrocarbon gases such as hydrogen sulfide were investigated for both Alberta and BC play areas. Key parameters for understanding a complex petroleum system like the Montney play include changes in thickness, depth of burial, mass balance calculations, timing and magnitudes of paleotemperature exposure, as well as kerogen concentration and types to determine the distribution of hydrocarbon composition, H2S concentrations and CO2 concentrations. Results show that there is first-, second- and third- order variations in the maturation patterns that impact the hydrocarbon composition. Isomer ratio calculations for butane and propane, in combination with excess methane estimation from produced fluids, are powerful tools to highlight effects of migration in the hydrocarbon distribution. The present-day distribution of hydrocarbons is a result of fluid mixing between hydrocarbons generated in-situ with shorter-chained hydrocarbons (i.e., methane) migrated from deeper, more mature areas proximal to the deformation front, along structural elements like the Fort St. John Graben, as well as through areas of lithology with higher permeability. The BC Montney play appears to have hydrocarbon composition that reflects a larger contribution from in-situ generation, while the Montney play in Alberta has a higher proportion of its hydrocarbon volumes from migrated hydrocarbons. Hydrogen sulphide is observed to be laterally discontinuous and found in discrete zones or pockets. The locations of higher concentrations of hydrogen sulphide do not align with the sulphate-rich facies of the Charlie Lake Formation but can be seen to underlie areas of higher sulphate ion concentrations in the formation water. There is some alignment between CO2 and H2S, particularly south of Dawson Creek; however, the cross-plot of CO2 and H2S illustrates some deviation away from any correlation and there must be other processes at play (i.e., decomposition of kerogen or carbonate dissolution). The sources of sulphur in the produced H2S were investigated through isotopic analyses coupled with scanning electron microscopy, energy dispersive spectroscopy, and mineralogy by X-ray diffraction. The Montney Formation in BC can contain small discrete amounts of sulphur in the form of anhydrite as shown by XRD and SEM-EDX results. Sulphur isotopic analyses indicate that the most likely source of sulphur is from Triassic rocks, in particular, the Charlie Lake Formation, due to its close proximity, its high concentration of anhydrite (18-42%), and the evidence that dissolved sulphate ions migrated within the groundwater in fractures and transported anhydrite into the Halfway Formation and into the Montney Formation. The isotopic signature shows the sulphur isotopic ratio of the anhydrite in the Montney Formation is in the same range as the sulphur within the H2S gas and is a lighter ratio than what is found in Devonian anhydrite and H2S gas. This integrated study contributes to a better understanding of the hydrocarbon system for enhancing the efficiency of and optimizing the planning of drilling and production operations. Operators in BC should include mapping of the Charlie Lake evaporites and structural elements, three-dimensional seismic and sulphate ion concentrations in the connate water, when planning wells, in order to reduce the risk of encountering unexpected souring.

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Carter, T. R., C. E. Logan, J K Clark, H. A. J. Russell, E. H. Priebe, and S. Sun. A three-dimensional bedrock hydrostratigraphic model of southern Ontario. Natural Resources Canada/CMSS/Information Management, 2022. http://dx.doi.org/10.4095/331098.

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A hydrostratigraphic framework has been developed for southern Ontario consisting of 15 hydrostratigraphic units and 3 regional hydrochemical regimes. Using this framework, the 54 layer 3-D lithostratigraphic model has been converted into a 15 layer 3-D hydrostratigraphic model. Layers are expressed as either aquifer or aquitard based principally on hydrogeologic characteristics, in particular the permeability and the occurrence/absence of groundwater when intersected by a water well or petroleum well. Hydrostratigraphic aquifer units are sub-divided into up to three distinct hydrochemical regimes: brines (deep), brackish-saline sulphur water (intermediate), and fresh (shallow). The hydrostratigraphic unit assignment provides a standard nomenclature and definition for regional flow modelling of potable water and deeper fluids. Included in the model are: 1) 3-D hydrostratigraphic units, 2) 3-D hydrochemical fluid zones within aquifers, 3) 3-D representations of oil and natural gas reservoirs which form an integral part of the intermediate to deep groundwater regimes, 4) 3-D fluid level surfaces for deep Cambrian brines, for brines and fresh to sulphurous groundwater in the Guelph Aquifer, and the fresh to sulphurous groundwater of the Bass Islands Aquifer and Lucas-Dundee Aquifer, 5) inferred shallow karst, 6) base of fresh water, 7) Lockport Group TDS, and 8) the 3-D lithostratigraphy. The 3-D hydrostratigraphic model is derived from the lithostratigraphic layers of the published 3-D geological model. It is constructed using Leapfrog Works at 400 m grid scale and is distributed in a proprietary format with free viewer software as well as industry standard formats.

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Brydie, Dr James, Dr Alireza Jafari, and Stephanie Trottier. PR-487-143727-R01 Modelling and Simulation of Subsurface Fluid Migration from Small Pipeline Leaks. Chantilly, Virginia: Pipeline Research Council International, Inc. (PRCI), May 2017. http://dx.doi.org/10.55274/r0011025.

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The dispersion and migration behavior of hydrocarbon products leaking at low rates (i.e. 1bbl/day and 10 bbl/day) from a pipeline have been studied using a combination of experimental leakage tests and numerical simulations. The focus of this study was to determine the influence of subsurface engineered boundaries associated with the trench walls, and the presence of a water table, upon the leakage behavior of a range of hydrocarbon products. The project numerically modelled three products including diesel, diluted bitumen (dilbit) and gasoline; which were chosen to span a range of fluid types and viscosities. Laboratory simulations of leakage were carried out for the most viscous product (i.e. dilbit) in order to capture plume dispersion in semi-real time, and to allow numerical predictions to be assessed against experimental data. Direct comparisons between observed plume dimensions over time and numerically predicted behavior suggested a good match under low moisture conditions, providing confidence that the numerical simulation was sufficiently reliable to model field-scale applications. Following a simulated two year initialization period, the leakage of products, their associated gas phase migration, thermal and geomechanical effects were simulated for a period of 365 days. Comparisons between product leakage rate, product type and soil moisture content were made and the spatial impacts of leakage were summarized. Variably compacted backfill within the trench, surrounded by undisturbed and more compacted natural soils, results porosity and permeability differences which control the migration of liquids, gases, thermal effects and surface heave. Dilbit migration is influenced heavily by the trench, and also its increasing viscosity as it cools and degases after leakage. Diesel and gasoline liquid plumes are also affected by the trench structure, but to a lesser extent, resulting in wider and longer plumes in the subsurface. In all cases, the migration of liquids and gases is facilitated by higher permeability zones at the base of the pipe. Volatile Organic Compounds (VOCs) migrate along the trench and break through at the surface within days of the leak. Temperature changes within the trench may increase due liquid migration, however the change in predicted temperature at the surface above the leak is less than 0.5�C above background. For gasoline, the large amount of degassing and diffusion through the soil results in cooling of the soil by up to 1�C. Induced surface displacement was predicted for dilbit and for one case of diesel, but only in the order of 0.2cm above baseline. Based upon the information gathered, recommendations are provided for the use and placement of generic leak detection sensor types (e.g liquid, gas, thermal, displacement) within the trench and / or above the ground surface. The monitoring locations suggested take into account requirements to detect pipeline leakage as early as possible in order to facilitate notification of the operator and to predict the potential extent of site characterization required during spill response and longer term remediation activities.

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Levine, J. R. Permeability changes in coal resulting from gas desorption. Office of Scientific and Technical Information (OSTI), January 1991. http://dx.doi.org/10.2172/6012022.

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Levine, J. R. Permeability changes in coal resulting from gas desorption. Office of Scientific and Technical Information (OSTI), January 1991. http://dx.doi.org/10.2172/6012028.

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Levine, J. R., and F. Tsay. Permeability changes in coal resulting from gas desorption. Office of Scientific and Technical Information (OSTI), December 1990. http://dx.doi.org/10.2172/7273045.

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Levine, J. R., and F. Tsay. Permeability changes in coal resulting from gas desorption. Office of Scientific and Technical Information (OSTI), November 1989. http://dx.doi.org/10.2172/7080892.

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Levine, J. R., and F. Tsay. Permeability changes in coal resulting from gas desorption. Office of Scientific and Technical Information (OSTI), January 1990. http://dx.doi.org/10.2172/7080900.

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