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Knight, Rosemary, Jack Dvorkin, and Amos Nur. "Acoustic signatures of partial saturation." GEOPHYSICS 63, no. 1 (January 1998): 132–38. http://dx.doi.org/10.1190/1.1444305.
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The relationship between elastic wave velocities and water saturation in a water/gas reservoir depends strongly on whether saturation is heterogeneous (patchy) or homogeneous. Heterogeneity in saturation may result from lithologic heterogeneity because under conditions of capillary equilibrium, different lithologies within a reservoir can have different saturations, depending on their porosities and permeabilities. We investigate this phenomenon by generating models of a reservoir in which we control the distribution of lithologic units and theoretically determine the corresponding velocity‐saturation relationship. We assume a state of capillary equilibrium in the reservoir and determine the saturation level of each region within the reservoir from the corresponding capillary pressure curve for the lithologic unit at that location. The velocities we calculate for these models show that saturation heterogeneity, caused by lithologic variation, can lead to a distinct dependence of velocity on saturation. In a water‐gas saturated reservoir, a patchy distribution of the different lithologic units is found to cause P-wave velocity to exhibit a noticeable and almost continuous velocity variation across the entire saturation range. This is in distinct contrast to the response of a homogeneous reservoir where there is only a large change in velocity at water saturations close to 100%.
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Graue, Arne, Martin A. Fernø, Robert W. Moe, Bernard A. Baldwin, and Riley Needham. "Water Mixing During Waterflood Oil Recovery: The Effect of Initial Water Saturation." SPE Journal 17, no. 01 (November 30, 2011): 43–52. http://dx.doi.org/10.2118/149577-pa.
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Summary This work studies the mixing of injected water and in-situ water during waterfloods and demonstrates that the mixing process is sensitive to the initial water saturation. The results illustrate differences between a waterflooded zone and a preflooded zone during, for example, water-based EOR displacement processes. The mixing of in-situ, or connate, water and injected water during laboratory waterfloods in a strongly water-wet chalk core sample was determined at different initial water saturations. Dynamic 1D fluid-saturation profiles were determined with nuclear-tracer imaging (NTI) during waterfloods, distinguishing between the oil phase, connate water, and injected water. The mixing of connate and injected water during waterfloods, with the presence of an oil phase, resulted in a displacement of all connate water from the core plug. During displacement, connate water banked in front of the injecting water, separating (or partially separating) the injected water from the mobile oil phase. This may impact the ability of chemicals dissolved in the injected water to contact the oil during secondary recovery and EOR processes. The effect of the connate-water-bank separation was sensitive to the initial water saturation (Swi). The time difference between breakthrough of connate water and breakthrough of injected water at the outlet showed a linear correlation to the initial water saturation Swi. The results obtained in chalk confirmed earlier findings in sandpacks (Brown 1957) and thus demonstrated the generality in the results.
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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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Li, Kewen, Kevin Chow, and Roland N. Horne. "Influence of Initial Water Saturation on Recovery by Spontaneous Imbibition in Gas/Water/Rock Systems and the Calculation of Relative Permeability." SPE Reservoir Evaluation & Engineering 9, no. 04 (August 1, 2006): 295–301. http://dx.doi.org/10.2118/99329-pa.
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Summary It has been a challenge to understand why recovery by spontaneous imbibition could both increase and decrease with initial water saturation. To this end, mathematical models were developed with porosity, permeability, viscosity, relative permeability, capillary pressure, and initial water saturation included. These equations foresee that recovery and imbibition rate can increase, remain unchanged, or decrease with an increase in initial water saturation, depending on rock properties, the quantity of residual gas saturation, the range of initial water saturation, and the units used in the definitions of gas recovery and imbibition rate. The theoretical predictions were verified experimentally by conducting spontaneous water imbibition at five different initial water saturations, ranging from 0 to approximately 50%. The effects of initial water saturation on residual saturation, relative permeability, capillary pressure, imbibition rate, and recovery in gas/water/rock systems by cocurrent spontaneous imbibition were investigated both theoretically and experimentally. Water-phase relative permeabilities and capillary pressures were calculated with the experimental data of spontaneous imbibition. Experimental results in different rocks were compared. Introduction Spontaneous water imbibition is an important mechanism during water injection. Prediction of recovery and imbibition rate by spontaneous water imbibition is essential to evaluate the feasibility and the performance of water injection. For example, is water injection effective in the case of high initial water saturation in reservoirs? Answers to such a question may be found by investigating the effect of initial water saturation on spontaneous water imbibition. It has been observed experimentally that initial water saturation affects recovery and production rate significantly (Blair 1964; Zhou et al. 2000; Viksund et al. 1998; Cil et al. 1998; Tong et al. 2001; Li and Firoozabadi 2000; Akin et al. 2000). However, the experimental observations from different authors (Zhou et al. 2000; Cil et al. 1998; Li and Firoozabadi 2000; Akin et al. 2000) are not consistent. On the other hand, few studies have investigated the effect of initial water saturation on recovery and imbibition rate theoretically, especially in gas reservoirs. Using numerical-simulation techniques, Blair (1964) found that the quantity and the rate of oil produced after a given period of imbibition increased with a decrease in initial water saturation for countercurrent spontaneous imbibition. Zhou et al. (2000) found that both imbibition rate and final oil recovery in terms of oil originally in place (OOIP) increased with an increase in initial water saturation, whereas oil recovery by waterflooding decreased. Viksund et al. (1998) found that the final oil recovery (OOIP) by spontaneous water imbibition in Berea sandstone showed little variation with a change in initial water saturation from 0 to approximately 30%. For the chalk samples tested by Viksund et al. (1998), the imbibition rate first increased with an increase in initial water saturation and then decreased slightly as initial water saturation increased above 34%.Cil et al. (1998) reported that the oil recovery (in terms of recoverable oil reserves) for zero and 20% initial water saturation showed insignificant differences in behavior. However, the oil recovery for initial water saturation above 20% increased with an increase in initial water saturation. Li and Firoozabadi (2000) found that the final gas recovery in the units of gas originally in place (GOIP) by spontaneous imbibition decreased with an increase in initial water saturation in both gas/oil/rock and gas/water/rock systems. The imbibition rate (GOIP/min) increased with an increase in initial water saturation at early time but decreased at later time. Akin et al. (2000) found that the residual oil saturation was unaffected significantly by initial water saturation. In this study, equations, derived theoretically, were used to study the effect of initial water saturation on gas recovery and imbibition rate. The equations correlate recovery, imbibition rate, initial water saturation, rock/fluid properties, and other parameters. Experiments of spontaneous water imbibition in gas-saturated rocks were conducted to confirm the theoretical predictions. The effect of rock properties on gas recovery and imbibition rate was also studied. An X-ray CT scanner was used to monitor the distribution of the initial water saturation to confirm that the initial distribution of the water saturation was uniform. In this study, we only focused on cocurrent spontaneous imbibition. It was assumed that there were no chemical reactions or mass transfer between gas and liquid.
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Johnson, Raymond H., and Eileen P. Poeter. "Iterative use of the Bruggeman-Hanai-Sen mixing model to determine water saturations in sand." GEOPHYSICS 70, no. 5 (September 2005): K33—K38. http://dx.doi.org/10.1190/1.2049348.
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The accuracy of the Bruggeman-Hanai-Sen (BHS) mixing model has been previously demonstrated for two-material mixtures during BHS model development. Using permittivities determined from modeling ground-penetrating radar (GPR) data, the BHS model has been iteratively applied to three-material mixtures of water, sand, and a dense, nonaqueous-phase liquid (DNAPL). However, the accuracy of this application has not been verified. A 10-cm air-line system driven by a network analyzer is used to measure bulk permittivitities when the water saturations in a sand are varied (frequency range of 20 to 200 MHz). Through iterative use of the BHS mixing model, the measured permittivities are used to calculate water saturations, which are compared to known saturation values. An iterative BHS mixing model for an air/water/sand system must consider which two-material end member (air/sand or water/sand) represents the matrix term in the original two-material BHS model. An air/sand matrix provides the best accuracy for low water saturations, and a water/sand matrix provides the best accuracy for high water saturations; thus, a new weighted model is developed. For a given porosity and a measured bulk permittivity, water saturation is most accurately determined by proportionally weighting the water saturation values determined using air/sand as the matrix and water/sand as the matrix in the BHS model.
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Tao, Wei-Kuo, Joanne Simpson, and Michael McCumber. "An Ice-Water Saturation Adjustment." Monthly Weather Review 117, no. 1 (January 1989): 231–35. http://dx.doi.org/10.1175/1520-0493(1989)117<0231:aiwsa>2.0.co;2.
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Alharthi, A., and J. Lange. "Soil water saturation: Dielectric determination." Water Resources Research 23, no. 4 (April 1987): 591–95. http://dx.doi.org/10.1029/wr023i004p00591.
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Meng, Mianmo, Yinghao Shen, Hongkui Ge, Xiaosong Xu, and Yang Wu. "The Effect of Fracturing Fluid Saturation on Natural Gas Flow Behavior in Tight Reservoirs." Energies 13, no. 20 (October 12, 2020): 5278. http://dx.doi.org/10.3390/en13205278.
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Hydraulic fracturing becomes an essential method to develop tight gas. Under high injection pressure, fracturing fluid entering into the formation will reduce the flow channel. To investigate the influence of water saturation on gas flow behavior, this study conducted the gas relative permeability with water saturation and the flow rate with the pressure gradient at different water saturations. As the two dominant tight gas-bearing intervals, the Upper Paleozoic Taiyuan and Shihezi Formations deposited in Ordos Basin were selected because they are the target layers for holding vast tight gas. Median pore radius in the Taiyuan Formation is higher than the one in the Shihezi Formation, while the most probable seepage pore radius in the Taiyuan Formation is lower than the one in the Shihezi Formation. The average irreducible water saturation is 54.4% in the Taiyuan Formation and 61.6% in the Shihezi Formation, which indicates that the Taiyuan Formation has more movable water. The average critical gas saturation is 80.4% and 69.9% in these two formations, respectively, which indicates that the Shihezi Formation has more movable gas. Both critical gas saturation and irreducible water saturation have a negative relationship with porosity as well as permeability. At the same water saturation, the threshold gradient pressure of the Taiyuan Formation is higher than the one in the Shihezi Formation, which means that water saturation has a great influence on the Taiyuan Formation. Overall, compared with the Shihezi Formation, the Taiyuan Formation has a higher median pore size and movable water saturation, but water saturation has more influence on its gas flow capacity. Our research is conducive to understanding the effect of fracturing fluid filtration on the production of natural gas from tight reservoirs.
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Carpenter, Chris. "Reconciling Log-Derived Water-Saturation and Saturation-Height Function Results." Journal of Petroleum Technology 68, no. 08 (August 1, 2016): 65–66. http://dx.doi.org/10.2118/0816-0065-jpt.
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Namdar Zanganeh, M., S. I. I. Kam, T. C. C. LaForce, and W. R. R. Rossen. "The Method of Characteristics Applied to Oil Displacement by Foam." SPE Journal 16, no. 01 (August 19, 2010): 8–23. http://dx.doi.org/10.2118/121580-pa.
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Summary Solutions obtained by the method of characteristics (MOC) provide key insights into complex foam enhanced-oil-recovery (EOR) displacements and the simulators that represent them. Most applications of the MOC to foam have excluded oil. We extend the MOC to foam flow with oil, where foam is weakened or destroyed by oil saturations above a critical oil saturation and/or weakened or destroyed at low water saturations, as seen in experiments and represented in foam simulators. Simulators account for the effects of oil and capillary pressure on foam using algorithms that bring foam strength to zero as a function of oil or water saturation, respectively. Different simulators use different algorithms to accomplish this. We examine SAG (surfactant-alternating-gas) and continuous foam-flood (coinjection of gas and surfactant solution) processes in one dimension, using both the MOC and numerical simulation. We find that the way simulators express the negative effect of oil or water saturation on foam can have a large effect on the calculated nature of the displacement. For instance, for gas injection in a SAG process, if foam collapses at the injection point because of infinite capillary pressure, foam has almost no effect on the displacement in the cases examined here. On the other hand, if foam maintains finite strength at the injection point in the gas-injection cycle of a SAG process, displacement leads to implied success in several cases. However, successful mobility control is always possible with continuous foam flood if the initial oil saturation in the reservoir is below the critical oil saturation above which foam collapses. The resulting displacements can be complex. One may observe, for instance, foam propagation predicted at residual water saturation, with zero flow of water. In other cases, the displacement jumps in a shock past the entire range of conditions in which foam forms. We examine the sensitivity of the displacement to initial oil and water saturations in the reservoir, the foam quality, the functional forms used to express foam sensitivity to oil and water saturations, and linear and nonlinear relative permeability models.
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Zhou, Y., J. O. Helland, and D. G. Hatzignatiou. "Computation of Three-Phase Capillary Pressure Curves and Fluid Configurations at Mixed-Wet Conditions in 2D Rock Images." SPE Journal 21, no. 01 (February 18, 2016): 152–69. http://dx.doi.org/10.2118/170883-pa.
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Summary In this study, we present a three-phase, mixed-wet capillary bundle model with cross sections obtained from a segmented 2D rock image, and apply it to simulate gas-invasion processes directly on images of Bentheim sandstone after two-phase saturation histories consisting of primary drainage, wettability alteration, and imbibition. We calculate three-phase capillary pressure curves, corresponding fluid configurations, and saturation paths for the gas-invasion processes and study the effects of mixed wettability and saturation history by varying the initial water saturation after primary drainage and simulating gas invasion from different water saturations after imbibition. In this model, geometrically allowed gas/oil, oil/water, and gas/water interfaces are determined in the pore cross sections by moving two circles in opposite directions along the pore/solid boundary for each of the three fluid pairs separately. These circles form the contact angle with the pore walls at their front arcs. For each fluid pair, circle intersections determine the geometrically allowed interfaces. The physically valid three-phase fluid configurations are determined by combining these interfaces systematically in all permissible ways, and then the three-phase capillary entry pressures for each valid interface combination are calculated consistently on the basis of free-energy minimization. The valid configuration change is given by the displacement with the most favorable (the smallest) gas/oil capillary entry pressure. The simulation results show that three-phase oil/water and gas/oil capillary pressure curves are functions of two saturations at mixed wettability conditions. We also find that oil layers exist in a larger gas/oil capillary pressure range for mixed-wet conditions than for water-wet conditions, even though a nonspreading oil is considered. Simulation results obtained in sandstone rock sample images show that gas-invasion paths may cross each other at mixed-wet conditions. This is possible because the pores have different and highly complex, irregular shapes, in which simultaneous bulk-gas and oil-layer invasion into water-filled pores occur frequently. The initial water saturation at the end of primary drainage has a significant effect on the gas-invasion processes after imbibition. Small initial water saturations yield more-oil-wet behavior, whereas large initial water saturations show more-water-wet behavior. However, in both cases, the three-phase capillary pressure curves must be described by a function of two saturations. For mixed-wet conditions, in which some pores are water-wet and other pores are oil-wet, the gas/oil capillary pressure curves can be grouped into two curve bundles that represent the two wetting states. Finally, the results obtained in this work demonstrate that it is important to describe the pore geometry accurately when computing the three-phase capillary pressure and related saturation paths in mixed-wet rock.
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Liu, Zhidi, and Jingzhou Zhao. "An Experimental Study of Velocity-Saturation Relationships in Volcanic Rocks." Open Petroleum Engineering Journal 8, no. 1 (March 31, 2015): 142–52. http://dx.doi.org/10.2174/1874834101508010142.
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In this paper, experiments are carried out under different pressures and water saturations using core samples of volcanic rocks from the Junggar Basin in China to understand how water saturation affects P- and S-wave velocities. The results show that water saturated rocks exhibit significantly higher P- and S-wave velocities than gas saturated rocks. In addition, the P- and S-wave velocity ratio declines with increasing water saturation. Furthermore, a P- and S-wave velocity ratio vs. resistivity cross plot is created to identify gas reservoirs in the volcanic rocks in the Junggar Basin.
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Ghedan, Shawket G., Bertrand M. Thiebot, and Douglas A. Boyd. "Modeling Original Water Saturation in the Transition Zone of a Carbonate Oil Reservoir." SPE Reservoir Evaluation & Engineering 9, no. 06 (December 1, 2006): 681–87. http://dx.doi.org/10.2118/88756-pa.
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Summary Accurately modeling water-saturation variation in transition zones is important to reservoir simulation for predicting recoverable oil and guiding field-development plans. The large transition zone of a heterogeneous Middle East reservoir was challenging to model. Core-calibrated, log-derived water saturations were used to generate saturation-height-function groups for nine reservoir-rock types. To match the large span of log water saturation (Sw) in the transition zone from the free-water level (FWL) to minimum Sw high in the oil column, three saturation-height functions per rock type (RT) were developed, one each for the low-, medium-, and high-porosity range. Though developed on a different scale from the simulation-model cells, the saturation profiles generated are a good statistical match to the wireline-log-interpreted Sw, and bulk volume of water (BVW) and fluid volumetrics agree with the geological model. RT-guided saturation-height functions proved a good method for modeling water saturation in the simulation model. The technique emphasizes the importance of oil/brine capillary pressures measured under reservoir conditions and of collecting an adequate number of Archie saturation and cementation exponents to reduce uncertainties in well-log interpretation. Introduction The heterogeneous carbonate reservoir in this study is composed of both limestone and dolomite layers frequently separated by non-reservoir anhydrite layers (Ghedan et al. 2002). Because of its heterogeneity, this reservoir, like other carbonate reservoirs, contains long saturation-transition zones of significant sizes. Transition zones are conventionally defined as that part of the reservoir between the FWL and the level at which water saturation reaches a minimum near-constant (irreducible water saturation, Swirr) high in the reservoir (Masalmeh 2000). For the purpose of this paper, however, we define transition zones as those parts of the reservoir between the FWL and the dry-oil limit (DOL), where both water and oil are mobile irrespective of the saturation level. Both water and oil are mobile in the transition zone, while only oil is mobile above the transition zone. By either definition, the oil/water transition zone contains a sizable part of this field's oil in place. Predicting the amount of recoverable oil in a transition zone through simulation depends on (among other things) the distribution of initial oil saturation as a function of depth as well as the mobility of the oil in these zones (Masalmeh 2000). Therefore, the characterization of transition zones in terms of original water and oil distribution has a potentially large effect on reservoir recoverable reserves and, in turn, reservoir economics.
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Yan, Weichao, Jianmeng Sun, Jinyan Zhang, Naser Golsanami, and Shuyan Hao. "A novel method for estimation of remaining oil saturations in water-flooded layers." Interpretation 5, no. 1 (February 1, 2017): SB9—SB23. http://dx.doi.org/10.1190/int-2016-0074.1.
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After long-term production by water injection, the conductivity features of oil reservoirs are changed, leading to difficulties in calculating remaining oil saturation by traditional well-logging techniques. There are some specific phenomena relating to petrophysical properties in water-flooded layers, and a deep investigation of them could help us understand resistivity changes of rocks during the water-injection process. We compared traditional mixed-fluid resistivity methods and determined their drawbacks. In addition, we revised the theoretical models and came up with a novel method to calculate mixed-fluid resistivity. The displacement process was divided into three stages: non-water-flooded stage, low and medium water-flooded stage, and high water-flooded stage. To study the relationships between rock resistivities and water saturations when injecting fresh-/saltwater, we used digital rock numerical methods. We first constructed 3D digital rock models based on the process-based method, and then we obtained oil and water distributions in the pore space by the pore morphology method. When resistivities of every component in digital rock models were assigned, rock resistivities could be calculated in different water saturations by the finite-element method. We found that in the case of freshwater injection, the relationship between water saturations and rock resistivities formed an S-shaped curve, but in the case of saltwater injection, if the injection water salinity was higher, the rock resistivity would be decreased by increasing the water saturation. In different rock heterogeneity and wettability conditions, these curves showed similar shapes and trends. Combined with resistivity logging data, this novel approach was used in the interpretation of a real oil well. Compared with the existing models in the interpretation practices, this new model better matched the real-field saturations and improved the accuracy of saturation interpretation in the studied water-flooded oil reservoir.
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Fauria, Kristen E., and Michael Manga. "Pyroclast cooling and saturation in water." Journal of Volcanology and Geothermal Research 362 (August 2018): 17–31. http://dx.doi.org/10.1016/j.jvolgeores.2018.07.002.
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Kornyshev, Alexei A., and Godehard Sutmann. "Nonlocal Dielectric Saturation in Liquid Water." Physical Review Letters 79, no. 18 (November 3, 1997): 3435–38. http://dx.doi.org/10.1103/physrevlett.79.3435.
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Mladenov, E., S. Staykov, and G. Cholakov. "Water saturation limit of transformer oils." IEEE Electrical Insulation Magazine 25, no. 1 (January 2009): 23–30. http://dx.doi.org/10.1109/mei.2009.4795466.
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Lenhard, Robert, John Rayner, and J. García-Rincón. "Testing an Analytical Model for Predicting Subsurface LNAPL Distributions from Current and Historic Fluid Levels in Monitoring Wells: A Preliminary Test Considering Hysteresis." Water 11, no. 11 (November 15, 2019): 2404. http://dx.doi.org/10.3390/w11112404.
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Knowledge of subsurface light nonaqueous phase liquid (LNAPL) saturation is important for developing a conceptual model and a plan for addressing LNAPL contaminated sites. Investigators commonly predict LNAPL mobility and potential recoverability using information such as LNAPL physical properties, subsurface characteristics, and LNAPL saturations. Several models exist that estimate the LNAPL specific volume and transmissivity from fluid levels in monitoring wells. Commonly, investigators use main drainage capillary pressure–saturation relations because they are more frequently measured and available in the literature. However, main drainage capillary pressure–saturation relations may not reflect field conditions due to capillary pressure–saturation hysteresis. In this paper, we conduct a preliminary test of a recent analytical model that predicts subsurface LNAPL saturations, specific volume, and transmissivity against data measured at a LNAPL contaminated site. We call our test preliminary because we compare only measured and predicted vertical LNAPL saturations at a single site. Our results show there is better agreement between measured and predicted LNAPL saturations when imbibition capillary pressure–saturation relations are employed versus main drainage capillary pressure–saturation relations. Although further testing of the model for different conditions and sites is warranted, the preliminary test of the model was positive when consideration was given to capillary pressure–saturation hysteresis, which suggests the model can yield reasonable predictions that can help develop and update conceptual site models for addressing subsurface LNAPL contamination. Parameters describing capillary pressure–saturation relations need to reflect conditions existing at the time when the fluid levels in a well are measured.
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Yang, Kai, Muhammed Basheer, Sreejith Nanukuttan, Yun Bai, and Adrian Long. "Effectiveness of two field methods of saturating near surface concrete on the water permeability of in situ concrete." MATEC Web of Conferences 289 (2019): 06004. http://dx.doi.org/10.1051/matecconf/201928906004.
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Determining the water permeability of concrete in structures remains a challenge because of difficulties in removing the influence of its moisture content. Saturating concrete with water could be one option, but this is not easy to achieve on site. This paper reports a testing programme carried out to assess the reliability and effectiveness of two field saturation methods, viz. vacuum saturation and ponding. The water permeability test results after applying the vacuum saturation and ponding were compared with that obtained after incremental immersion. It was found that ponding was unable to remove the influence of moisture, whilst vacuum saturation was effective for wet concretes. The results obtained from the electrical resistance measurements after incremental immersion suggested that the water permeability of concretes can be accurately determined by carrying out in situ permeability tests if the near surface region up to a depth of 25 mm is fully saturated.
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Kapil, J. C., Chandrika Prasher, Moiz Chasmai, and P. K. Satyawali. "A parallel-probe saturation profiler: a new technique for fast profiling of meltwater saturation in a seasonal snowpack." Journal of Glaciology 55, no. 193 (2009): 814–22. http://dx.doi.org/10.3189/002214309790152410.
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AbstractWe describe a parallel-probe saturation profiler (PPSP) for accurate and fast profiling of liquid-water saturations in a snowpack. This device utilizes the absorption of electrical energy, by water molecules under the action of an external electric field, due to instantaneous rotations from initially random orientations to the orientation of the applied electric field. Our observations show that the height of first peak signal (HFPS), i.e. the difference between the maxima and minima in the PPSP signal-response time series, is proportional to the liquid-water content and the water saturation of snow. The HFPS corresponding to different liquid-water contents were obtained from various naturally occurring snow types and were observed to be proportional to the water saturation of the snow, irrespective of snow types. For simultaneous measurements at corresponding depths in a snowpack, a position encoder supports the PPSP. This device was calibrated for various types of snow samples and was then tested on the snow covers under different climatic zones of the Himalaya. The operation of the PPSP is easy and fast. The distribution of liquid water within a large snow cover can be estimated speedily using the PPSP, with a vertical resolution of 7 mm.
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Cadoret, Thierry, Gary Mavko, and Bernard Zinszner. "Fluid distribution effect on sonic attenuation in partially saturated limestones." GEOPHYSICS 63, no. 1 (January 1998): 154–60. http://dx.doi.org/10.1190/1.1444308.
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Extensional and torsional wave‐attenuation measurements are obtained at a sonic frequency around 1 kHz on partially saturated limestones using large resonant bars, 1 m long. To study the influence of the fluid distribution, we use two different saturation methods: drying and depressurization. When water saturation (Sw) is higher than 70%, the extensional wave attenuation is found to depend on whether the resonant bar is jacketed. This can be interpreted as the Biot‐Gardner‐White effect. The experimental results obtained on jacketed samples show that, during a drying experiment, extensional wave attenuation is influenced strongly by the fluid content when Sw is between approximately 60% and 100%. This sensitivity to fluid saturation vanishes when saturation is obtained through depressurization. Using a computer‐assisted tomographic (CT) scan, we found that, during depressurization, the fluid distribution is homogeneous at the millimetric scale at all saturations. In contrast, during drying, heterogeneous saturation was observed at high water‐saturation levels. Thus, we interpret the dependence of the extensional wave attenuation upon the saturation method as principally caused by a fluid distribution effect. Torsional attenuation shows no sensitivity to fluid saturation for Sw between 5% and 100%.
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Marsh, Roger, Rafay Ansari, David Chace, and Keith Boyle. "Gas saturation measurement in low-porosity sands." APPEA Journal 51, no. 2 (2011): 744. http://dx.doi.org/10.1071/aj10124.
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Traditionally, pulsed neutron data has been used to calculate water saturation and/or monitor gas/water contacts in zones of high formation water salinity. In low or unknown salinities carbon/oxygen measurements have been used for oil saturation measurements in porosities greater than 15%. In tight gas sands, porosities are typically less than 10% and are too low for either method to work. In gas sands with low or unknown water salinities and porosities below 15%, neither Sigma or C/O measurements will work. New pulsed neutron instrumentation and methodology are available for through-casing gas saturation measurements. The new technology is independent of water salinity and enables gas saturation calculations to be made in porosities as low as 5%. The technique includes modelling that enables the tool response to be determined in advance. Modelling takes into account several factors, including: lithology, completion geometry, reservoir pressure, gas density, and gas composition (for example: methane or CO2). The measurements are sensitive to gas pressure in the reservoir, and this paper will discuss ways that the data can be used to infer the relative and, in some cases, absolute pressures of different zones. The data set presented straddles the gas/water contact in the borehole. The effects of re-invasion by the borehole fluids will be discussed with respect to the corresponding openhole and cased hole water saturations, from both inelastic and capture measurements.
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Zhang, Xi Wen, Guang Sheng Cao, Li Juan Niu, and Gui Long Wang. "Determination of Irreducible Water Saturation and its Application in Analysing Water Producing after Fracturing." Applied Mechanics and Materials 548-549 (April 2014): 1881–84. http://dx.doi.org/10.4028/www.scientific.net/amm.548-549.1881.
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Combining Semipermeable Diaphragm Method with Nonsteady State Method, Bound Water Saturation and Critical Water Saturation in Du 38 District of Daqing Fuyang Reservoir are Determined before and after Fracturing and Relationship between them is also Analyzed. the Results Show that the Fracture of Bound Water, have a Certain Influence Critical Water Saturation, and the Cracks of Bound Water, the Greater the Size Change the Greater the Value of Critical Water Saturation; Characteristics of Reservoir Microscopic Seepage is Analyzed, the Results Show that the Movable Water Potential Changes is the Main Cause of Oil well Water after Fracturing.
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Gkortsas, Vasileios-Marios, Lalitha Venkataramanan, Kamilla Fellah, David Ramsdell, Chang-Yu Hou, and Nikita Seleznev. "Comparison of different dielectric models to calculate water saturation and estimate textural parameters in partially saturated cores." GEOPHYSICS 83, no. 5 (September 1, 2018): E303—E318. http://dx.doi.org/10.1190/geo2018-0100.1.
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Accurate estimation of water saturation is central in predicting capillary pressure and relative permeability, under special core analysis in the laboratory. We have explored the use of dielectric measurements at different frequencies to estimate water saturation. In addition to water saturation, dielectric measurements are sensitive to the distribution of water and oil in a porous system, reflected by the apparent cementation factor [Formula: see text], which describes the water phase tortuosity. We have performed an experimental study to benchmark water saturation from dielectric measurements on eight carbonate cores and estimated their cementation exponent [Formula: see text] and saturation exponent [Formula: see text] in Archie’s equation from dielectric data. All cores went through a series of drainage/imbibition steps, creating varying saturations of brine/fluorocarbon. Fluorocarbon was chosen because it is invisible to proton nuclear magnetic resonance (NMR). Therefore,NMR porosity represents only the water-filled porosity and can be used to benchmark dielectric water-filled porosity. Three dielectric models were used for the comparison of the dielectric water-filled porosity with the one from NMR, i.e., the complex refractive index model (CRIM), bimodal model, and Stroud-Milton-De (SMD) model, and very good agreement of 1.5 porosity units on average is found. Despite its simplicity, CRIM predicted well the water-filled porosity in this experiment. However, it cannot provide information about the texture, which is captured by bimodal and SMD models. We also estimated [Formula: see text] and [Formula: see text] based on [Formula: see text] found from bimodal and SMD models, and good agreement with [Formula: see text] from resistivity data was shown. This is the first time to our knowledge that such a rich set of dielectric and NMR measurements was acquired at different saturation stages in a surface laboratory. This study is useful in benchmarking the water saturation from dielectrics, comparing different dielectric models, and demonstrating feasibility of estimating textural parameters.
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Xu, Jingling, Lei Xu, and Yuxing Qin. "Two effective methods for calculating water saturations in shale-gas reservoirs." GEOPHYSICS 82, no. 3 (May 1, 2017): D187—D197. http://dx.doi.org/10.1190/geo2016-0462.1.
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Water saturation is one of the most important parameters in petroleum exploration and development. However, its calculation has been limited by the insufficient logging data required by a new technique that further influences the calculation of the free gas content. The accuracy of water saturation estimates is also a critical issue because it controls whether or not we can obtain an accurate gas saturation estimate. Organic matter plays an important role in shale-gas reservoirs, and the total organic carbon (TOC) indirectly controls the gas content and gas saturation. Hence, water saturation is influenced by inorganic and organic components. After analyzing the relationship among TOC, core water saturation, and conventional gas saturation, considering the influence of TOC on gas saturation in organic-rich shale reservoirs, we developed two new methods to improve the accuracy of water saturation estimates: the revised water saturation-TOC method and the water saturation separation method, in which Archie water saturation, modified total shale water saturation, and TOC are integrated. According to case studies of Longmaxi-Wufeng shale, southeastern Sichuan Basin, China, the water saturation results from these two methods in shale reservoirs with different lithologies are consistent with those from core analysis. We concluded that these two methods can be evaluated quickly and they effectively evaluate the water saturation of shale reservoirs.
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Kantzas, Apostolos, Minghua Ding, and Jong Lee. "Residual Gas Saturation Revisited." SPE Reservoir Evaluation & Engineering 4, no. 06 (December 1, 2001): 467–76. http://dx.doi.org/10.2118/75116-pa.
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Summary The determination of residual gas saturation in gas reservoirs from long spontaneous and forced-imbibition tests is addressed in this paper. It is customarily assumed that when a gas reservoir is overlaying an aquifer, water will imbibe into the gas-saturated zone with the onset of gas production. The process of gas displacement by water will lead to forced imbibition in areas of high drawdown and spontaneous imbibition in areas of low drawdown. It is further assumed that in the bulk of the reservoir, spontaneous imbibition will prevail and the reservoir will be water-wet. A final assumption is that the gas behaves as an incompressible fluid. All these assumptions are challenged in this paper. A series of experiments is presented in which it is demonstrated that the residual gas saturation obtained by a short imbibition test is not necessarily the correct residual gas saturation. Imbibition tests by different methods yield very different results, while saturation history and core cleaning also seem to have a strong effect on the determination of residual gas saturation. It was found, in some cases, that the residual gas by spontaneous imbibition was unreasonably high. This was attributed to weak wetting conditions of the core (no water pull by imbibition). It is expected that this work will shed some new light on an old, but not-so-well-understood, topic. Introduction When a porous medium is partially or fully saturated with a nonwetting phase, and a wetting phase is allowed to invade the porous medium, the process is called imbibition. For the problem addressed in this work, the nonwetting phase is assumed to be gas, and the wetting phase is assumed to be the aquifer water. If the medium is dry and the water is imbibing, then the imbibition is primary (Swi=0). If the water is already in the medium, the imbibition is secondary (Swi>0). If there is no driving force other than the affinity to wet, the imbibition is spontaneous. If there is any other positive pressure gradient, the imbibition is called forced. Numerous papers have been written on the subject of residual oil saturation from imbibition, but fewer have been prepared on the subject of residual gas saturation from imbibition. The common perception is that many of the principles that cover oil and gas reservoirs are the same. Agarwal1 addressed the relationship between initial and final gas saturation from an empirical perspective. He worked with 320 imbibition experiments and segmented the database to develop curve fits for common rock classifications. Land2 noted that available data seemed to fit very well to an empirical functional form given asEquation 1 In this model, the only free parameter is the maximum observable trapped nonwetting phase saturation corresponding to Sgr (Sgi=1). This expression does not predict residual phase saturation, only how residual saturation scales with initial saturation. Zhou et al.3 studied the effect of wettability, initial water saturation, and aging time on oil recovery by spontaneous imbibition and waterflooding. A correlation between water wetness and oil recovery by waterflooding and spontaneous imbibition was observed. Geffen et al.4 investigated some factors that affect the residual gas saturation, such as flooding rate, static pressure, temperature, sample size, and saturation conditions before flooding. They found that water imbibition on dry-plug experiments was different from waterflooding experiments with connate water. However, they concluded that the residual gas saturation from the two types of experiments was essentially the same. Keelan and Pugh5 concluded that trapped gas saturation existed after gas displacement by wetting-phase imbibition in carbonate reservoirs. Their experiments showed that the trapped gas varied with initial gas in place and that it was a function of rock type. Fishlock et al.6 investigated the residual gas saturation as a function of pressure. They focused on the mobilization of residual gas by blowdown. Apparently, the trapped gas did not become mobile immediately as it expanded. The gas saturation had to increase appreciably to a critical value for gas remobilization. Tang and Morrow7 introduced the effect of composition on the microscopic displacement efficiency of oil recovery by waterflooding and spontaneous imbibition. They concluded that the cation valency was important to crude/oil/rock interactions. Chierici et al.8 tested whether a reliable value of reserves could be obtained from reservoir past-production performance by analyzing results from six gasfield experiments. They concluded that different gas reservoir aquifer systems could show the same pressure performance in response to a given production schedule. Baldwin and Spinler9 investigated residual oil saturation starting from different initial water saturation using magnetic resonance imaging (MRI). They concluded that at low initial water saturation, the presence of a significant waterfront during spontaneous water imbibition indicated that the rate of water transport was less than that of oil. At high initial water saturation, the more uniform saturation change during spontaneous water imbibition indicated that the rate of water transport was greater than that of oil. The pattern of spontaneous imbibition depended on sample wettability, with less effect from frontal movement in less water-wet samples. Pow et al.10 addressed the imbibition of water in fractured gas reservoirs. Field and laboratory information suggested that a large amount of gas was trapped through fast water imbibition through the fractures and premature water breakthrough. The postulation was made that such gas reservoirs would produce this gas if and when the bypassed gas was allowed to flow to the production intervals under capillary-controlled action. The question of whether the rate of imbibition could enhance the production of this trapped gas was raised. Preliminary experiments on full-diameter core pieces showed that the rates of imbibition were extremely slow and that if the different imbibition experiments were performed in full-diameter plugs, the duration of the experiments would be prohibitively long. These experiments formulated the experimental strategy presented in the following sections.
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Berg, Charles. "An effective medium algorithm for calculating water saturations at any salinity or frequency." GEOPHYSICS 72, no. 2 (March 2007): E59—E67. http://dx.doi.org/10.1190/1.2432261.
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An algorithmic approach is used to mix the conductivities and geometric factors of the disperse components (the rock and hydrocarbon particles) with the host conductivity (formation water). The theoretical basis for the algorithm is the Hanai-Bruggeman (HB) equation, which itself incorporates only one disperse component. The new approach, the incremental model, accommodates geometric factors such as sand and shale porosity exponents, saturation exponent, and also accommodates the associated grain conductivities. Its advantage over previous methods is that it works at any water salinity or tool frequency while allowing saturation and porosity exponents to have values other than 1.5. The algorithm is general and is written to accommodate simultaneous mixing of up to three disperse components and the formation water, but it can be extended to accommodate any number of disperse components. In its application to shaley sands, hydrocarbon and sand elements are set to zero conductivity at low frequency, but they can be nonzero for calculating saturations at higher frequencies. The reason for this is that hydrocarbon and sand conductivities are real and very close to zero at low frequencies, but at high frequencies the dielectric constants become significant, making the complex conductivities nonzero. The incremental model compared well with the Waxman-Smits model on multiple water-conductivity saturation data from two published experimental data sets. The model is adaptable to other rock conductivity problems such as vuggy porosity, vuggy water saturation, and clay-coated sand grains. The potential exists for the algorithm to be part of a comprehensive computer program for calculating rock conductivities and saturations using many different combinations of rock fabrics and compositions.
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Kim, Mina, Joseph Gillen, Bennett A. Landman, Jinyuan Zhou, and Peter C. M. van Zijl. "Water saturation shift referencing (WASSR) for chemical exchange saturation transfer (CEST) experiments." Magnetic Resonance in Medicine 61, no. 6 (April 8, 2009): 1441–50. http://dx.doi.org/10.1002/mrm.21873.
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Tang, Guo-Qing, and Abbas Firoozabadi. "Effect of Pressure Gradient and Initial Water Saturation on Water Injection in Water-Wet and Mixed-Wet Fractured Porous Media." SPE Reservoir Evaluation & Engineering 4, no. 06 (December 1, 2001): 516–24. http://dx.doi.org/10.2118/74711-pa.
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Summary A systematic study of the effect of wettability and initial water saturation on water injection and imbibition is made in Kansas outcrop chalk samples. (Kansas outcrop chalk is very similar to the rock matrix of the North Sea fractured chalk reservoirs.) Water-injection tests were conducted at different pressure gradients to simulate the effect of gravity (that is, negative Pc) on recovery. Based on a large number of carefully conducted tests, the following conclusions are drawn:Initial water saturation has a pronounced effect on water injection in an intermediate-wet chalk. This effect is much less pronounced for a strongly water-wet chalk. The effects are also in opposite directions.Pressure gradients (which simulate the negative Pc effect) have a very strong effect on water-injection performance in an intermediate-wet chalk. Our interpretation of these experiments leads to the conclusion that recovery from the chalk reservoirs may be nearly independent of wettability state. The results from the experiments also reveal that there is no relation between laboratory measurements of spontaneous imbibition and field performance of mixed-wet reservoirs, even when the wettability state is perfectly restored in the laboratory. Introduction Wettability state and its effect on oil recovery has been the subject of numerous studies since 1928.1–8 However, major issues of oil recovery related to wettability remain unresolved. A major parameter of wettability is contact angle. Some authors have even questioned the usefulness of contact angle in defining wettability.5 The state of wettability in some reservoirs can vary significantly with depth and rock properties. Jerauld and Rathmell4 presented data showing that there is a clear dependence of residual oil saturation upon depth. In the Prudhoe Bay reservoirs, residual oil saturation to waterflood decreases with depth while the reservoir wettability changes from less-water-wet to more-water-wet conditions with an increase in depth. In the Ekofisk field, which is similar to the Prudhoe Bay reservoirs, there is a systematic change of wettability with depth; water-wetting increases with depth. Spontaneous water imbibition in the laboratory shows poor recovery in the cores from the upper part of the reservoir. However, field data from a long period of waterflooding reveal a low water cut. The openhole logging results on sidetracks also show oil recoveries in excess of the laboratory imbibition measurements.9 Despite wettability variation in the Ekofisk field, residual oil saturation is low and independent of the depth. In the Ekofisk field, from the commencement of water injection in 1987, the oil rate has increased from approximately 75,000 B/D to approximately 250,000 B/D in 1997.10 Research concerning the effect of gravity forces on water injection in fractured reservoirs is rather limited. In 1968, Hamon11 found that oil recovery by water drainage in oil-wet fractured porous media could be significant depending on matrix permeability. Similar results were reported recently by Putra et al.12 Zhou et al.13 observed that a decrease in water-wetness of Berea sandstone by adsorption of polar oil components could increase oil recovery by waterflooding. Graue et al.14 obtained similar results for low permeability chalk. The effect of initial water saturation on oil recovery remains controversial. Brown15 studied the effect of initial water saturation on waterflood efficiency. He emphasized that connate water (retained as water film and in small pores) could become re-mobilized when water is invading. His experimental results showed that flow of connate water improves waterflood recovery. Skauge et al.16 studied the influence of connate water on oil recovery by gas gravity drainage using chalk samples. The maximum oil recovery was obtained at approximately 30% initial water saturation. Viksund et al.17 carried out spontaneous imbibition tests with strongly water-wet chalk. A maximum oil recovery was obtained at approximately 34% of initial water saturation. However, results from Narahara et al.18 are much different. They measured gas and oil relative permeability in water-wet and mixed-wet Berea at various initial water saturations and found that gas and oil relative permeabilities are independent of initial water saturation. Zhou et al.19 observed that for a crude-oil/brine/rock system, imbibition recovery increased with initial water saturation, but waterflood recovery decreased with initial water saturation. A long induction time (ranging from 10 to 1,000 minutes) was observed in imbibition tests after the cores were aged with crude oil at T=88°C for 10 days. The main objective of this work is to understand the mechanisms that lead to a vast difference between laboratory spontaneous imbibition measurements and field performance. For this purpose, we have conducted an extensive set of laboratory measurements on Kansas outcrop chalk with a porosity of approximately 30% and a permeability of some 0.5 md. Waterflood and spontaneous imbibition performances of the Kansas outcrop chalk are studied before and after wettability alteration. We have used Kansas chalk because of its similarity to the chalk matrix rock from the Ekofisk chalk field. In this paper, we present the experimental results that include wettability alteration by chemical adsorption, water injection, and spontaneous imbibition in strongly water-wet and weakly water-wet chalks. In some of the experiments, an initial water saturation was present. In the injection experiments, the pressure gradient is varied to simulate the effect of gravity on recovery. Materials and Experimental Setup Fluids and Chemicals. Normal decane (n-C10) with a density of 0.73 g/cm3 and a viscosity of 0.92 cp at 24°C is used as the oil phase. Stearic acid (octadecanoic acid), purchased from Sigma with a purity of 99% and a molecular weight of 284.5, is used as a surfactant to alter the chalk wettability. This chemical is dissolved in oil (n-C10) to prepare the stearic acid solution. Solubility tests at room temperature show that stearic acid dissolves in oil when the concentration is less than 2,000 ppm, but it hardly dissolves in water. NaCl and CaCl2 are used to prepare the 0.1% NaCl+0.1% CaCl2 brine solution, which is used both for injection water and for the establishment of initial water saturation. The viscosity and density of the brine are 1.0 cp and 1.02 g/cm3 at 24°, respectively. Fluids and Chemicals. Normal decane (n-C10) with a density of 0.73 g/cm3 and a viscosity of 0.92 cp at 24°C is used as the oil phase. Stearic acid (octadecanoic acid), purchased from Sigma with a purity of 99% and a molecular weight of 284.5, is used as a surfactant to alter the chalk wettability. This chemical is dissolved in oil (n-C10) to prepare the stearic acid solution. Solubility tests at room temperature show that stearic acid dissolves in oil when the concentration is less than 2,000 ppm, but it hardly dissolves in water. NaCl and CaCl2 are used to prepare the 0.1% NaCl+0.1% CaCl2 brine solution, which is used both for injection water and for the establishment of initial water saturation. The viscosity and density of the brine are 1.0 cp and 1.02 g/cm3 at 24°, respectively.
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Danesh, Ali, G. D. Henderson, and J. M. Peden. "Experimental Investigation of Critical Condensate Saturation and Its Dependence on Interstitial Water Saturation in Water-Wet Rocks." SPE Reservoir Engineering 6, no. 03 (August 1, 1991): 336–42. http://dx.doi.org/10.2118/19695-pa.
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Gao, Shu-Sheng, Li-You Ye, Wei Xiong, He-Kun Guo, and Zhi-Ming Hu. "Nuclear Magnetic Resonance Measurements of Original Water Saturation and Mobile Water Saturation in Low Permeability Sandstone Gas." Chinese Physics Letters 27, no. 12 (December 2010): 128902. http://dx.doi.org/10.1088/0256-307x/27/12/128902.
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Zhou, Yingfang, Dimitrios Georgios Hatzignatiou, Johan Olav Helland, Yulong Zhao, and Jianchao Cai. "Pore-Scale Modelling of Three-Phase Capillary Pressure Curves Directly in Uniformly Wet Rock Images." Geofluids 2021 (January 5, 2021): 1–15. http://dx.doi.org/10.1155/2021/6622079.
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In this work, we developed a semianalytical model to compute three-phase capillary pressure curves and associated fluid configurations for gas invasion in uniformly wet rock images. The fluid configurations and favorable capillary entry pressures are determined based on free energy minimization by combining all physically allowed three-phase arc menisci. The model was first validated against analytical solutions developed in a star-shaped pore space and subsequently employed on an SEM image of Bentheim sandstone. The simulated fluid configurations show similar oil-layer behavior as previously imaged three-phase fluid configurations. The simulated saturation path indicates that the oil-water capillary pressure can be described as a function of the water saturation only. The gas-oil capillary pressure can be represented as a function of gas saturation in the majority part of the three-phase region, while the three-phase displacements slightly reduce the accuracy of such representation. At small oil saturations, the gas-oil capillary pressure depends strongly on two-phase saturations.
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Leontidis, Vlasios, Souhail Youssef, and Daniela Bauer. "New insights into tracer propagation in partially saturated porous media." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 29. http://dx.doi.org/10.2516/ogst/2020021.
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This work deals with the influence of partial saturation on the transport process of a passive tracer. Transport experiments were done in a water-wet glass micromodel combined with specific optical techniques. Full water saturation was achieved by injecting initially the background solution and then the tracer, whereas for the partial saturation conditions, the micromodel was initially saturated with oil, and then sequential the background solution and the tracer were injected at the same flow rate. We have shown that in the investigated range of water saturations it exists a transition in the oil ganglia structure and size. For high water saturations oil ganglia have one or two pores in size, however for lower water saturations they comprise an important number of pores. Transport strongly depends on the size distribution of the oil ganglia as they create large percolating paths and stagnant zones. We also showed the existence of two different types of stagnant zones: zones accessible by diffusion into pores and zones only accessible by spatially limited diffusion in films. The major advantage of using glass micromodels lies in the fact that dispersion coefficients can be computed from concentrations averaged over the pore space or from concentrations at the outlet and simultaneously from spatial concentration profiles. Curves were fitted using the Advection–Dispersion Equation (ADE) with adequate boundary conditions. The fitting quality of the temporal evolution of the average and outlet concentration was very good. However, fitting of the concentration profiles could only be done for the higher water saturations. This is due to the fact that the Representative Elementary Volume (REV) of lower water saturations is larger than the micromodel. The results show that fitting the breakthrough curve in order to determine the dispersion coefficient in a partially saturated porous medium might be misleading. Indeed, when fitting the breakthrough curves we were able to compute a dispersion coefficient even in the case where the REV of the water saturation is larger than the micromodel. Consequently, the knowledge of the local concentration profiles as a function of time is necessary as it provides an additional information on the spatio-temporal behavior of the transport process and therefor a supplementary constraint of the fitting procedure. Finally, we observed a time dependent dispersion coefficient in the regime where oil ganglia comprise several pores. This fact might be attributed to the non-Gaussian nature of the transport.
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Zhou, Y., J. O. O. Helland, and D. G. G. Hatzignatiou. "Pore-Scale Modeling of Waterflooding in Mixed-Wet-Rock Images: Effects of Initial Saturation and Wettability." SPE Journal 19, no. 01 (July 4, 2013): 88–100. http://dx.doi.org/10.2118/154284-pa.
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Summary We simulate transient behavior of viscous- and capillary-dominated water invasion at mixed-wet conditions directly in scanning-electron-microscope (SEM) images of Bentheim sandstone by treating the pore spaces as cross sections of straight tubes. Initial conditions are established by drainage and wettability alteration. Constant rate or differential pressure is imposed along the tube bundle. The phase pressures vary with positions along the tube length but remain unique in each cross section, consistent with 1D core-scale models. This leads to a nonlinear system of equations that are solved for the interface positions as a function of time. The cross-sectional fluid configurations are computed accurately at any capillary pressure and wetting condition by a semianalytical model that is based on free-energy minimization. The fluid conductances are estimated by newly derived explicit expressions that are shown to be in agreement with numerical computations performed directly on the cross-sectional fluid configurations. An SEM image of Bentheim sandstone is taken as input to the developed model for simulating the evolution of saturation profiles during waterfloods for different flow rates and several mixed-wet conditions, which are established with various initial water saturations and contact angles. It is demonstrated that the simulated saturation profiles depend strongly on initial water saturation at mixed-wet conditions. The saturation profiles exhibit increasingly gradual behavior in time as the contact angle, defined on the oil-wet solid surfaces, increases or the initial water saturation decreases. Front menisci associated with positive capillary pressures promote oil displacement by water, whereas for large and negative capillary pressures at small flow rates, oil displaces water because the associated front menisci retract. This results in the development of pronounced gradual saturation fronts at mixed-wet conditions. The waterfloods simulated at conditions established with a large initial water saturation and small contact angle on the oil-wet solid surfaces exhibit sharp Buckley-Leverett saturation profiles for high flow rates because the capillary pressure is small and less important. The shape of the saturation profiles is interpreted on the basis of the simulated capillary pressure curves and the corresponding fluid configurations occurring in the rock image.
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Lian, Peiqing, Cuiyu Ma, Bingyu Ji, Taizhong Duan, and Xuequn Tan. "Numerical Simulation Modeling of Carbonate Reservoir Based on Rock Type." Journal of Engineering 2017 (November 1, 2017): 1–6. http://dx.doi.org/10.1155/2017/6987265.
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There are many types of carbonate reservoir rock spaces with complex shapes, and their primary pore structure changes dramatically. In order to describe the heterogeneity of K carbonate reservoir, equations of porosity, permeability and pore throat radii under different mercury injection saturations are fitted, and it shows that 30% is the best percentile. R30 method is presented for rock typing, and six rock types are divided according to R30 value of plugs. The porosity-permeability relationship is established for each rock type, and their relevant flow characteristics of each rock type have been studied. Logs are utilized to predict rock types of noncored wells, and a three-dimensional (3D) rock type model has been established based on the well rock type curves and the sedimentary facies constraint. Based on the relationship between J function and water saturation, the formula of water saturation, porosity, permeability, and oil column height can be obtained by multiple regressions for each rock type. Then, the water saturation is calculated for each grid, and a 3D water saturation model is established. The model can reflect the formation heterogeneity and the fluid distribution, and its accuracy is verified by the history matching.
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Miller, Mark A., and H. J. Ramey. "Effect of Temperature on Oil/Water Relative Permeabilities of Unconsolidated and Consolidated Sands." Society of Petroleum Engineers Journal 25, no. 06 (December 1, 1985): 945–53. http://dx.doi.org/10.2118/12116-pa.
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Abstract Over the past 20 years, a number of studies have reported temperature effects on two-phase relative permeabilities in porous media. Some of the reported results, however, have been contradictory. Also, observed effects have not been explained in terms of fundamental properties known to govern two-phase flow. The purpose of this study was to attempt to isolate the fundamental properties affecting two-phase relative permeabilities at elevated temperatures. Laboratory dynamic-displacement relative permeability measurements were made on unconsolidated and consolidated sand cores with water and a refined white mineral oil. Experiments were run on 2-in. [5.1-cm] -diameter, 20-in. [52.-cm] -long cores from room temperature to 300F [149C]. Unlike previous researchers, we observed essentially no changes with temperature in either residual saturations or relative permeability relationships. We concluded that previous results may have been affected by viscous previous results may have been affected by viscous instabilities, capillary end effects, and/or difficulties in maintaining material balances. Introduction Interest in measuring relative permeabilities at elevated temperatures began in the 1960's with petroleum industry interest in thermal oil recovery. Early thermal oil recovery field operations (well heaters, steam injection, in-situ combustion) indicated oil flow rate increases far in excess of what was predicted by viscosity reductions resulting from heating. This suggested that temperature affects relative permeabilities. One of the early studies of temperature effects on relative permeabilities was presented by Edmondson, who performed dynamic displacement measurements with crude performed dynamic displacement measurements with crude and white oils and distilled water in Berea sandstone cores. Edmondson reported that residual oil saturations (ROS's) (at the end of 10 PV's of water injected) decreased with increasing temperature. Relative permeability ratios decreased with temperature at high water saturations but increased with temperature at low water saturations. A series of elevated-temperature, dynamic-displacement relative permeability measurements on clean quartz and "natural" unconsolidated sands were reported by Poston et al. Like Edmondson, Poston et al. reported a decrease in the "practical" ROS (at less than 1 % oil cut) as temperature increased. Poston et al. also reported an increase in irreducible water saturation. Although irreducible water saturations decreased with decreasing temperature, they did not revert to the original room temperature values. It was assumed that the cores became increasingly water-wet with an increase in both temperature and time; measured changes of the IFT and the contact angle with temperature increase, however, were not sufficient to explain observed effects. Davidson measured dynamic-displacement relative permeability ratios on a coarse sand and gravel core with permeability ratios on a coarse sand and gravel core with white oil displaced by distilled water, nitrogen, and superheated steam at temperatures up to 540F [282C]. Starting from irreducible water saturation, relative permeability ratio curves were similar to Edmondson's. permeability ratio curves were similar to Edmondson's. Starting from 100% oil saturation, however, the curves changed significantly only at low water saturations. A troublesome aspect of Davidson's work was that he used a hydrocarbon solvent to clean the core between experiments. No mention was made of any consideration of wettability changes, which could explain large increases in irreducible water saturations observed in some runs. Sinnokrot et al. followed Poston et al.'s suggestion of increasing water-wetness and performed water/oil capillary pressure measurements on consolidated sandstone and limestone cores from room temperature up to 325F [163C]. Sinnokrot et al confirmed that, for sandstones, irreducible water saturation appeared to increase with temperature. Capillary pressures increased with temperature, and the hysteresis between drainage and imbibition curves reduced to essentially zero at 300F [149C]. With limestone cores, however, irreducible water saturations remained constant with increase in temperature, as did capillary pressure curves. Weinbrandt et al. performed dynamic displacement experiments on small (0.24 to 0.49 cu in. [4 to 8 cm3] PV) consolidated Boise sandstone cores to 175F [75C] PV) consolidated Boise sandstone cores to 175F [75C] with distilled water and white oil. Oil relative permeabilities shifted toward high water saturations with permeabilities shifted toward high water saturations with increasing temperature, while water relative permeabilities exhibited little change. Weinbrandt et al. confirmed the findings of previous studies that irreducible water saturation increases and ROS decreases with increasing temperature. SPEJ P. 945
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Malanchuk, Yevhenii, Viktor Moshynskyi, Petro Denisyuk, Zinovii Malanchuk, Andriy Khrystyuk, Valerii Korniienko, and Petro Martyniuk. "Regularities in the distribution of granulometric composition of tuff while crushing." Mining of Mineral Deposits 15, no. 1 (2021): 66–74. http://dx.doi.org/10.33271/mining15.01.066.
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Purpose is to analyze distribution of granulometric composition of tuff as well as ultimate composition and identify dependence of its softening in the process of water saturation based upon a set of experiments to assess raw materials importance of the mineral. Methods. Laboratory experiments were carried out to determine ultimate composition of tuff extracted from different open pits of the region. Methods of mathematical statistics were applied to derive analytical dependences describing the tuff softening in the process of water saturation. The dependences denote logarithmic nature of the saturation increase along with the increase in the sample weight. Findings. It has been determined that tuff is a valuable mineral rather than basalt extraction waste. Thus, tuff needs both mining and complex approaches for processing and extracting of useful metals and silicates. Analytical dependences of tuff softening during water saturation have been defined. The dependences denote logarithmic nature of the saturation increase based upon a sample weight increment. Magnetic susceptibility of tuff, turned on magnetic field induction, has been identified. Dependences of distribution of technological indices (i.e. product yield, copper content and yield) in terms of granulometric-size class have been identified; the basic factors for crushing process have been determined; and regression dependences of grinder efficiency upon the input factors have been derived. Regression model of a crushing process of a general technological scheme of ore processing has been obtained involving the initial fragmentation using a jaw crusher, and additional fragmentation (i.e. reduction) using a sizer. Originality.It has been determined that magnetic susceptible tuff share is 49% of the sample weight; the remaining part is a silicate share. Logarithmic nature of the analytical softening dependences while water saturating has been identified. The above-mentioned denotes the increased saturation along with the increase in a sample weight. Practical implications. The definition of tuff ultimate composition as well as analytical softening dependences in the process of water saturation makes it possible to calculate the required water consumption. Keywords: tuff, basalt, softening, water saturation, silicate, magnetic susceptibility, ultimate composition, crushing
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Chistyakov, A. D. "The permittivity of water and water vapor in saturation states." Russian Journal of Physical Chemistry 81, no. 1 (January 2007): 5–8. http://dx.doi.org/10.1134/s0036024407010025.
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Maraqa, Munjed A., Roger B. Wallace, and Thomas C. Voice. "Effect of Water Saturation on Retardation of Ground-Water Contaminants." Journal of Environmental Engineering 125, no. 8 (August 1999): 697–704. http://dx.doi.org/10.1061/(asce)0733-9372(1999)125:8(697).
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Bänninger, Dominik, Peter Lehmann, Hannes Flühler, and Jonas Tölke. "Effect of Water Saturation on Radiative Transfer." Vadose Zone Journal 4, no. 4 (November 2005): 1152–60. http://dx.doi.org/10.2136/vzj2004.0109.
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Hamada, G. M., M. N. J. Al-Awad, and A. A. Alsughayer. "Water Saturation Computation from Laboratory 3d Regression." Oil & Gas Science and Technology 57, no. 6 (November 2002): 637–51. http://dx.doi.org/10.2516/ogst:2002044.
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Yan, Shu. "Water Saturation Model Optimization after Polymer Flooding." Applied Mechanics and Materials 522-524 (February 2014): 1280–83. http://dx.doi.org/10.4028/www.scientific.net/amm.522-524.1280.
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In this paper, the conducting model which is more suitable to describe the reservoir in the process of polymer flooding was selected, according to the reservoir properties. Based on the polymer solution conductance laws and the polymer flooding rock resistivity experiments, by injecting various types of polymers and water with different salinities, the rock resistivity change rule was studied. The change rule of the Archie model parameters in the polymer flooding process was analyzed and the accuracy of the dual water model was analyzed by means of the Litho-electric experiment data. On the basis of rock physical property analysis data, combined with the actual logging rules, the parameters interpretation model of porosity, permeability, irreducible water saturation and shale content were established. Using the core analyze data to contrast the practical application effect of the interpretation model, the result show that, the conclusion of the model corresponds to reality.
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Vargas-Guzmán, J. A. "Spatial modeling of heterogeneous initial water saturation." Journal of Petroleum Science and Engineering 58, no. 1-2 (August 2007): 283–92. http://dx.doi.org/10.1016/j.petrol.2007.02.001.
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Jafari Kenari, Seyed Ali, and Syamsiah Mashohor. "Robust committee machine for water saturation prediction." Journal of Petroleum Science and Engineering 104 (April 2013): 1–10. http://dx.doi.org/10.1016/j.petrol.2013.03.009.
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Stalheim, S. O., T. Eidesmo, and H. Rueslåtten. "Influence of wettability on water saturation modelling." Journal of Petroleum Science and Engineering 24, no. 2-4 (December 1999): 243–53. http://dx.doi.org/10.1016/s0920-4105(99)00046-7.
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Zhang, Jie, Xizhe Li, Weijun Shen, Shusheng Gao, Huaxun Liu, Liyou Ye, and Feifei Fang. "Study of the Effect of Movable Water Saturation on Gas Production in Tight Sandstone Gas Reservoirs." Energies 13, no. 18 (September 7, 2020): 4645. http://dx.doi.org/10.3390/en13184645.
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The movable water saturation of tight sandstone reservoirs is an important parameter in characterizing water production capacity, and there is a great need to understand the relationship between movable water saturation and water production characteristics. However, movable water behavior in this context remains unclear. In this study, four groups of tight sandstone cores from the Sulige gas field are measured to understand the movable water saturation characteristics. Then, the effects such as reservoir micropore throat, clay mineral and physical properties on movable water saturation are analyzed, and the movable water saturation and water production characteristics are discussed. The results show that higher movable water saturation will result in a greater amount of water in the gas drive. There is a critical pressure difference of the gas drive, and a large amount of movable water will flow out. Movable water saturation is independent of the porosity, permeability and initial water saturation, while it is closely related to the reservoir micropore throat and clay mineral content. Movable water is mainly distributed in the medium and large pores; the larger the proportion of such pores, the higher the degree of movable water saturation. A lower mineral content will lead to higher movable water saturation in tight sandstone gas reservoirs. These results provide clues for identifying gas–water bearing reservoirs and evaluating and predicting the water production characteristics in gas wells in tight sandstone gas reservoirs.
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Huong, Huynh Thi Thu, Nguyen Huu Quang, Le Van Son, and Tran Trong Hieu. "Transport of oil/water partitioning components during water injection." Petrovietnam Journal 6 (June 30, 2021): 37–42. http://dx.doi.org/10.47800/pvj.2021.06-03.
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The oil/water partitioning components such as alkylphenols and aliphatic acids naturally exist in crude oil compositions at different initial concentrations of hundreds or even thousands of ppm depending on the location of the reservoir compared to the site of original rocks. During contact with sweeping injection brine, those compounds diffuse from oil phase to water phase due to oil/water partitioning behaviours. As a result, their concentration in oil contacting with water will be attenuating during water injection. Their concentration profile in water injection history contains the information related to diffusion in oil and water phase, interstitial velocity of water and oil saturation. This paper presents the research results of theoretical model and numerical model of the washed-out process of alkylphenols in the late stage of water injection. The research results have proposed approximate analytical expression for concentration of alkylphenols at the late stage of water flooding. In this regard, at the sufficient large injection volume the alkylphenol concentration attenuates exponentially and the attenuation rate depends on parameters such as partitioning coefficient, oil saturation and interstitial velocity of water and oil and diffusion coefficients. The simulation concentration results obtained from UTCHEM simulator for the 5-spot model showed a good match with analytical calculation results. The research results can be used as the basis for developing methods to assess water flooding systems as well as oil saturation. The results can also be used for study of transport of non-aqueous phase liquid (NAPL) in environmental contamination. Keywords: Residual oil saturation, waterflooding, tracer, partitioning organic compounds, enhanced oil recovery.
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Benmesbah, Fatima Doria, Livio Ruffine, Pascal Clain, Véronique Osswald, Olivia Fandino, Laurence Fournaison, and Anthony Delahaye. "Methane Hydrate Formation and Dissociation in Sand Media: Effect of Water Saturation, Gas Flowrate and Particle Size." Energies 13, no. 19 (October 6, 2020): 5200. http://dx.doi.org/10.3390/en13195200.
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Assessing the influence of key parameters governing the formation of hydrates and determining the capacity of the latter to store gaseous molecules is needed to improve our understanding of the role of natural gas hydrates in the oceanic methane cycle. Such knowledge will also support the development of new industrial processes and technologies such as those related to thermal energy storage. In this study, high-pressure laboratory methane hydrate formation and dissociation experiments were carried out in a sandy matrix at a temperature around 276.65 K. Methane was continuously injected at constant flowrate to allow hydrate formation over the course of the injection step. The influence of water saturation, methane injection flowrate and particle size on hydrate formation kinetics and methane storage capacity were investigated. Six water saturations (10.8%, 21.6%, 33%, 43.9%, 55% and 66.3%), three gas flowrates (29, 58 and 78 mLn·min−1) and three classes of particle size (80–140, 315–450 and 80–450 µm) were tested, and the resulting data were tabulated. Overall, the measured induction time obtained at 53–57% water saturation has an average value of 58 ± 14 min minutes with clear discrepancies that express the stochastic nature of hydrate nucleation, and/or results from the heterogeneity in the porosity and permeability fields of the sandy core due to heterogeneous particles. Besides, the results emphasize a clear link between the gas injection flowrate and the induction time whatever the particle size and water saturation. An increase in the gas flowrate from 29 to 78 mLn·min−1 is accompanied by a decrease in the induction time up to ~100 min (i.e., ~77% decrease). However, such clear behaviour is less conspicuous when varying either the particle size or the water saturation. Likewise, the volume of hydrate-bound methane increases with increasing water saturation. This study showed that water is not totally converted into hydrates and most of the calculated conversion ratios are around 74–84%, with the lowest value of 49.5% conversion at 54% of water saturation and the highest values of 97.8% for the lowest water saturation (10.8%). Comparison with similar experiments in the literature is also carried out herein.
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Lenhard, R. J., A. R. Kacimov, A. M. Tartakovsky, and H. AbdelRahman. "Modeling Residual NAPL in Water-Wet Porous Media." Journal of Agricultural and Marine Sciences [JAMS] 7, no. 2 (June 1, 2002): 1. http://dx.doi.org/10.24200/jams.vol7iss2pp1-7.
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A model is outlined that predicts NAPL which is held in pore wedges and as films or lenses on solid and water surfaces and contributes negligibly to NAPL advection. This is conceptually referred to as residual NAPL. Since residual NAPL is immobile, it remains in the vadose zone after all free NAPL has drained. Residual NAPL is very important because it is a long-term source for groundwater contamination. Recent laboratory experiments have demonstrated that current models for predicting subsurface NAPL behavior are inadequate because they do not correctly predict residual NAPL. The main reason for the failure is a deficiency in the current constitutive theories for multiphase flow that are used in numerical simulators. Multiphase constitutive theory governs the relations among relative permeability, saturation, and pressure for fluid systems (i.e., air, NAPL, water). In this paper, we outline a model describing relations between fluid saturations and pressures that can be combined with existing multiphase constitutive theory to predict residual NAPL. We test the revised constitutive theory by applying it to a scenario involving NAPL imbibition and drainage, as well as water imbibition and drainage. The results suggest that the revised constitutive theory is able to predict the distribution of residual NAPL in the vadose zone as a function of saturation-path history. The revised model describing relations between fluid saturation and pressures will help toward developing or improving numerical multiphase flow simulators.
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Hustad, Odd Steve, and David John Browning. "A Fully Coupled Three-Phase Model for Capillary Pressure and Relative Permeability for Implicit Compositional Reservoir Simulation." SPE Journal 15, no. 04 (July 27, 2010): 1003–19. http://dx.doi.org/10.2118/125429-pa.
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Summary A coupled formulation for three-phase capillary pressure and relative permeability for implicit compositional reservoir simulation is presented. The formulation incorporates primary, secondary, and tertiary saturation functions. Hysteresis and miscibility are applied simultaneously to both capillary pressure and relative permeability. Two alternative three-phase capillary pressure formulations are presented: the first as described by Hustad (2002) and the second that incorporates six representative two-phase capillary pressures in a saturation-weighting scheme. Consistency is ensured for all three two-phase boundary conditions through the application of two-phase data and normalized saturations. Simulation examples of water-alternating-gas (WAG) injection are presented for water-wet and mixed-wet saturation functions. 1D homogeneous and 2D and 3D heterogeneous examples are employed to demonstrate some model features and performance.