Water Relative Permeability Research Articles

Experimental Study on the Enhanced Oil Recovery Mechanism of an Ordinary Heavy Oil Field by Polymer Flooding.

It is widely known that in the water flooding development process of ordinary heavy oil, the fingering phenomenon is obvious, there are a lot of unswept areas, and absolutely, the recovery is really very low. In addition, for some shallow and thin ordinary heavy oil reservoirs limited by the geological conditions of the reservoir, the thermal recovery technology also has serious heat loss and high development cost. Therefore, there is an urgent need to transform the development and further improve the enhanced oil recovery (EOR). In this paper, the mechanism of EOR by polymer flooding was investigated for high-porosity and high-permeability terrestrial ordinary heavy oil reservoirs. Through laboratory experiments, we analyzed the characteristics of oil-water relative permeability curves, mobility control ability, and microscopic seepage characteristics during polymer flooding of ordinary heavy oil reservoirs. On this basis, the effect of the mobility ratio on seepage characteristics and the mechanism of EOR enhancement were clarified. The results show that the polymer can effectively improve the mobility control effect of the displacing fluid. As the polymer solution and ordinary heavy oil have the characteristics of high viscosity and low mobility, there is a minimum mobility ratio in the process of polymer flooding. Namely, the characteristics of dual low mobility exist in the process of polymer flooding for the ordinary heavy oil. It effectively enhances the profile control and plugging ability of the polymer, thus expanding the sweep volume of larger pores and improving the displacement efficiency of smaller pores. Based on the two factors mentioned above, it is found that the dual low mobility characteristics can improve the recovery of ordinary heavy oil by polymer flooding. Therefore, it is proposed that an enhanced profile control and plugging effect due to the dual low mobility characteristics is an important EOR mechanism for ordinary heavy oil development by polymer flooding.

Development scheme screening considering reservoir damage based on the AHP model

The development process of oil and gas fields is affected by engineering and geology. Reservoir damage is significant as a bridge connecting these two disciplines. The life cycle of oil and gas fields can be prolonged by making development plans that consider reservoir damage. Therefore, this study performed experiments and discusses a Cretaceous reservoir development in the Chun17 block of the Chunguang Oilfield. We have carried out five sensitivity experiments on typical cores from the block, and analyzed lithology, physical properties, and crude oil. A mathematical model based on the Analytic Hierarchy Process (AHP) was then established based on the core data.Overall, the reservoir in the study area has ultra-high porosity and high permeability. The reservoir has moderately strong water sensitivity (damage rate is 38 ~ 90%) and moderately strong alkali sensitivity (damage rate is 22 ~ 75%). The crude oil belongs to extra-heavy oil reservoirs (containing 2.43% wax, 0.96% sulfur, 20.25 m% gum, 7.35 m% asphalt, 38.26 m% saturated hydrocarbon, and 27.51 m%). The crude oil is sensitive to temperature changes. Based on the AHP model analysis, the development scheme chooses the third (weight 0.1757) of the conventional analytic results of AHP; the Thermal oil production C1 scheme has the most stable future trend and appears to be the best option. In the next step, using fire flooding technology to develop the reservoir will benefit the most economically. The workflow consisting of "conclusion of reservoir experiment → AHP mathematical modeling → verification of relative permeability of high-temperature oil and water → verification of trial production" is simple and effective. The findings of this study can help to better understand the idea and process of making development plans for sensitive oil and gas fields through reservoir evaluation. Combining experimental data with mathematical modeling can find a balanced combination point in qualitative and quantitative analysis. Whether this combination point is correct can be verified by field engineering practice.

Effect of Heterogeneity on Capillary Pressure and Relative Permeability Curves in Carbonate Reservoirs. A Case Study for Mishrif Formation in West Qurna/1 Oilfield, Iraq

The special core analysis tests were accomplished on a set of core plugs for Mishrif Formation (mA, mB1, and mB2cde/mC units) in West Qurna/1 oilfield, southern Iraq. Oil relative permeability (Kro) data and the Corey-type fit of the data as functions of the brine saturation at the core outlet face for individual samples in the water-oil imbibition process to estimate relative permeability measurements by the centrifuge method were utilized. Identical correlations for oil and water relative permeabilities were extracted by steady-state and unsteady-state methods. For the mA samples, the gas-water capillary pressure curves were within a narrow range (almost identical) indicating that mA is a homogeneous unit. Kro curves for three mB2ab plugs were practically identical, that is referring to the homogeneity in the upper portion of the unit. The mB2 unit has a more solid‐phase concentration than other units. In addition, the general trend of low residual oil saturation is related to the raising in porosity but no reliable correlation between the residual oil saturation to water drive (Sorw) and Klinkenberg-corrected permeability (Kinf). Based on the correlation between the effective oil permeability at the initial water saturation [ko(Swi)] and (Kinf/f)1/2 for the high-permeability lithofacies mB1 plugs, ko(Swi) is approximately equal to or exceeds Kinf. While ko(Swi) was below Kinf for the other samples. New good empirical equations were obtained for effective gas permeability at final water saturation versus Kinf, as well as, for Kro and Krw versus saturation for all lithofacies.

Low Salinity Water–Polymer Flooding in Carbonate Oil Reservoirs: A Critical Review

AbstractLow salinity water–polymer flooding (LSWPF) is an emerging hybrid enhanced oil recovery (EOR) method that uses the synergetic effects of low salinity water (LSW) and polymers to enhance both the microscopic and macroscopic sweep efficiencies. Polymer flooding is an EOR method that aims to increase water viscosity and improve the mobility ratio of the injected fluid to the reservoir. It enhances mobility control and reduces water relative permeability, reaching a more favorable condition for sweep efficiency. LSW is an EOR method that aims to change wettability by exploiting crude oil and reservoir rock interactions. It allows for improving oil recovery when the injected water has a very low salinity compared to seawater or formation water. The literature reports LSWPF studies applied to sandstone reservoirs. However, LSWPF applications in carbonate reservoirs still lack. This review critically analyzes LSWPF as an alternative to Polymer flooding using seawater in carbonate reservoirs.

Effect of fines migration on oil recovery from carbonate rocks

We perform single-phase and two-phase flooding on Edwards Brown rock samples. The single-phase injection was of seawater or CaCl2 brine, at successive salinities 0.63, 0.21, 0.07, 0.05, and 0 mol/L (distilled water). For CaCl2 brine experimental run, no significant fines migration or permeability decrease is observed. For seawater experimental run, distilled water injection is found to bring about the highest concentration of produced fines and most of the permeability decrease, with the ultimate permeability decrease being 99.94%. Therefore, distilled water injection is used to stimulate fines migration in the following two-phase experimental runs. Two-phase experiments are performed on four Edwards Brown rock samples using seawater or CaCl2 brine as the aqueous phase, and Soltrol® 130 or crude oil as the oleic phase. Rock samples are initially fully saturated with 0.63 mol/L of the selected aqueous solution. This is followed by injecting the selected oil at a constant rate for at least 20 pore volumes to displace brine. Next, selected brine is injected to displace oil, and finally distilled water. For CaCl2 brine, distilled water injection is found to recover no additional oil of either type of oil. However, for seawater, the fines production observed during distilled water injection is found to reduce water relative permeability by two orders of magnitude when Soltrol® 130 is used and by three orders of magnitude when crude oil is used. The seawater experimental runs also brought about additional oil recovery during distilled water injection: 18% when Soltrol® 130 is used and 3.4% when crude oil is used. This last result can be attributed to the plugging of pores due to fines migration, which can divert further injected water into previously unswept pores. Cited as: Almutairi, A., Saira, S., Wang, Y., Le-Hussain, F. Effect of fines migration on oil recovery from carbonate rocks. Advances in Geo-Energy Research, 2023, 8(1): 61-70. https://doi.org/10.46690/ager.2023.04.06

Effect of Gas Diffusion Layer Notch Arrangement and Gradient Depth on the Performance of Proton Exchange Membrane Fuel Cells in the Serpentine Flow Field.

The structure of the gas diffusion layer (GDL) of a proton exchange membrane fuel cell (PEMFC) affects the transfer of the reaction gas and the water flooding phenomenon. First, the three-dimensional numerical model of the GDL was reconstructed by the stochastic reconstruction method, and the kinetic behaviors of liquid water in the conventional GDL, circular groove GDL, and elliptical groove GDL were compared and analyzed, based on which the liquid water penetration time, the effective diffusion rate of oxygen, and relative permeability of water in the three GDLs were analyzed, and the results of the study found that the circular groove GDL had the best drainage effect. Second, based on the PEMFC with serpentine channels, an electrochemical model of the GDL with circular grooves was arranged in the flow field, and the effects of the groove depth distribution and center spacing of circular grooves on its performance were numerically investigated. It was found that the presence of circular grooves enhanced the transfer rate of reactants from the GDL to the catalytic layer and increased the current density. Oxygen concentration uniformity and under-rib convection were enhanced when the groove depth was designed to have a power function distribution with an exponent close to 1, effectively reducing flooding. The best drainage effect was achieved when the groove spacing was 2 mm, and also the cell performance was more stable.

Correct relative permeability data from steady-state experiments for capillary end effects

Water-oil relative permeability curves can be obtained from co-injection experiments at steady-state (SS) conditions. The two-phase Darcy's law can be used to calculate the relative permeability directly only when water saturation is constant along the core. However, the capillary end effect (CEE) causes water accumulation or depletion at the end of the core depending upon the wettability. This work modifies the Intercept Method initially proposed by Gupta and Maloney. Similar to their work, we again envisage carrying out a steady-state (SS) co-injection experiment. For each ratio of water to oil flowrate (F=qwqo), we require experiments at different total flowrates. From each run, we obtain pressure drop across the core and average water saturation inside the core.We demonstrate mathematically that a plot of average water saturation vs. reciprocal of oil flowrate gives a straight line whose intercept is the water saturation in the unaffected region. A plot of pressure difference vs. oil flowrate yields a straight line whose slope gives the oil relative permeability which can be used to calculate water relative permeability. It is necessary to perform the SS experiment at least three times for the same F=qwqo (at different oil/water rates). The same procedure is used for other values of F to obtain more data points to construct the relative permeability curves. An experimental step-by-step procedure for experimental engineers to follow is given in appendix C.

Water Retention Curve–Based Design Method for the Artificial Ground Freezing: The Isarco River Underpass Tunnels within the Brenner Base Tunnel Project

The paper presents an interpretation of the temperature monitored during the application of artificial ground freezing in the Isarco River Underpass tunnel, within the Brenner Base Tunnel project. The observations gathered in the in situ monitoring provided an opportunity to (1) examine the response of a heterogeneous glacial and river deposit composed of gravelly loose sand and boulders subject to seepage, upon freezing; and (2) set up a coupled (thermohydraulic) theoretical formulation, which accounts for the water retention curve and relative permeability function, able to properly simulate the artificial ground freezing process on a heterogeneous coarse subsoil under seepage. The simulation was able to provide a satisfactory representation of the development of the in situ monitoring data and it revealed the dependence between the freezing process, the retention properties of the subsoil, and the seepage velocity. A sensitivity analysis was also carried out to examine the potential effect of water retention parameters on the frozen wall formation in terms of thickness and closing time. The critical examination of in situ observations and the results of the numerical analyses allowed the definition of a new criteria to define the freezing temperature of the soil based on the water retention curve features and the residual degree of saturation, with the aim to optimize the design of the artificial ground freezing process by maintaining the safety level against waterproofing of the excavation area.

Prediction of gas–water relative permeability in tight rock from movable fluid distribution with nuclear magnetic resonance

The measurement of the relative permeability in tight rock is challenging due to its ultralow permeability and the time-consuming nature of the experiments. Studying the movable and unmovable fluid distribution and establishing a reliable relative permeability prediction model is an urgent problem to be solved. This paper used nuclear magnetic resonance (NMR) to investigate movable and unmovable water distribution in tight sandstone under different centrifugal forces. A new method for predicting gas–water relative permeability in tight rock is established based on movable fluid distribution using the capillary bundle model. The results show that the distribution of movable and unmovable fluids is strongly influenced by the tight rock's pore size distribution and structure. The unmovable fluid saturation increases as the tight rock's permeability and median radius decrease. The nonlinear correlation between the NMR relaxation time and the pore throat size obtained from high-pressure mercury intrusion can be used to derive the pore size of the fluid distribution in tight rocks. The ratio of the movable fluid thickness to pore throat size increases near linearly with the logarithm of the pore throat size. The proposed mathematical model for the prediction of gas-water relative permeability based on movable fluid distribution is verified by comparing with the normalized relative permeability curve measured from experiments. This new model offers an alternative method of estimating the gas–water relative permeability when measurement is unavailable due to the ultralow permeability of the core samples.

Multiphase flow behavior of diesel in bog, fen, and swamp peats

Hydrocarbon fate and transport in various categories of peatlands is complicated by the botanical origin, and thus variations in the hydraulic structures and surface chemistry of its peat soils. There has been no systematic evaluation of the role of different peat types on hydrocarbon migration. Thus, two-phase, and three-phase flow experiments were performed for living and partially decomposed peat cores from bog, fen, and swamp peatlands. Numerical simulations of water drainage were performed using HYDRUS-1D, diesel-water and diesel-water-air flow using MATLAB Reservoir Simulation Toolbox (MRST). Five water table (WT) fluctuations were imposed to explore its potential to reduce residual diesel saturation in peat columns. Our results demonstrate a good match of the relative water permeability (krw) – saturation (S) relations estimated using the unsaturated hydraulic conductivity-S relation derived from HYDRUS-1D modeling of two-phase flow, and krw – S from MRST for three-phase flow, for all tested peat columns. Thus, we recommended using two-phase system based krw – S predictions if multiphase data are unavailable for peatland sites' spill management plans. We found the discharge of water and diesel both increase with increasing hydraulic conductivity, while residual water and diesel were within the range of 0.42–0.52 and of 0.04–0.11, respectively. High diesel discharge rates suggest that quick spill-response is required to manage its spread in peatlands. Up to 29% of residual diesel saturation was yielded by the five WT fluctuations, and thus we strongly recommend WT manipulation as a first step towards diesel decontamination progression in peatlands.

Micro-scale experimental investigation of the effect of pore space deformation on trapping of supercritical CO2

In this study, we investigate the impact of pore space deformation on various trapping mechanisms of supercritical CO2 (scCO2) relevant to storage of CO2 in deep saline aquifers. A series of unsteady-state two-phase brine/scCO2 drainage, imbibition, and dissolution tests were performed on a miniature sandpack sample under various stress conditions. High-resolution x-ray microtomography techniques were employed to acquire the pore and fluid occupancy maps at each step of the experiment, which were subsequently utilized to characterize the pore space deformation and changes in the frequencies of various pore-scale fluid displacement events. Our results revealed that, during the scCO2 injection stage, additional scCO2 was stored in the sandpack sample after the sandpack was compressed due to an increase in the pressure gradient even though the pore volume had decreased. On the other hand, the capillary trapping was impaired by the pore space contraction because all the imbibition displacement mechanisms at the pore scale, including the piston-like advance and snap-off, were facilitated as a consequence of an increase in their threshold capillary pressures. The increased frequency of snap-off events caused additional trapping, but more importantly, displaced scCO2 from throats by fragmenting large residual scCO2 clusters into smaller globules. During the dissolution process, the trapped scCO2 clusters and globules shrank in both pore bodies and throats, resulting in movement of the Main Terminal Meniscus (MTM) interfaces and snap-off events, respectively. The water relative permeability during the dissolution process decreased, at a fixed saturation, with the increase in the effective stress since the small pores occupied by the water phase deformed more significantly than the large pores.

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

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

Novel Discrete Fracture Network Model for Multiphase Flow in Coal

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

A Novel Semianalytical Model for the Relationship between Formation Pressure and Water Saturation in Coalbed Methane Reservoirs

The accuracy of the relationship between formation pressure and water saturation has a direct impact on predicting the production performance of coal reservoirs. As a result, researchers are becoming more interested in this connection. The most commonly used method to evaluate this connection is the semianalytic method, but it disregards the impact of coal matrix shrinkage on pore compressibility, resulting in inaccurate water saturation estimations for coal reservoirs. A material balance equation that considers the effect of coal matrix shrinkage on cleat porosity and pore compressibility, as well as the gas–water relative permeability curve, is used for the first time in this study to establish a model between pressure and water saturation. Furthermore, this study extends the proposed pressure–saturation model to predict cumulative gas production and gas recovery, resolving the difficult problem of calculating recovery for coalbed methane reservoirs. To verify its accuracy, this study compares the proposed method with numerical simulations and previous methods; the results of the comparison show that the water saturation under formation pressure calculated by the method proposed in this study is closer to the results of the numerical simulation. Sun’s model ignores the effect of matrix shrinkage on pore compressibility, resulting in larger calculation results. The findings of this study indicate that the effect of coal matrix shrinkage on pore compressibility cannot be ignored, and that the proposed method can replace numerical simulation as a simple and accurate method for water saturation evaluation, which can be applied to predict cumulative gas and recovery estimation for closed coalbed methane reservoirs. The proposed method increases the accuracy of the semianalytical method and broadens its application. It is critical for the prediction of coal reservoir production performance and forecasting of production dynamics.

MULTIFRACTAL MODELING OF GAS–WATER RELATIVE PERMEABILITY CONSIDERING MULTISCALE AND MULTIEFFECTS: INVESTIGATION OF UNCONVENTIONAL GAS DEVELOPMENT

Unconventional gas is a momentous energy source due to its considerable reserves and eco-friendly properties, where relative permeability is a key evaluative parameter of unconventional gas extraction. However, the geo-complexity, multiscale and multieffect of the unconventional gas reservoir challenge the relative permeability evaluation and production enhancement. Here, we establish a gas–water flow model by integrating multifractal theory, covering from nanoscale to macroscale and regarding the effects of slip, gas desorption–diffusion and water film separation, to reliably evaluate the relative permeability evolution during unconventional gas development. Based on our model, we describe the permeability of the unconventional reservoir with an 88% less evaluation error compared to the single fractal Darcy with the literature benchmark. Moreover, we characterize the gas–water relative permeability with a no more than 10% evaluation error based on the experimental data. The slip effect plays the most crucial role in the evaluation precision of relative permeability. We reveal that the permeability of the unconventional gas reservoir is decreased by the increase of generalized fractal dimension which enhances the heterogeneity and tortuosity of pores. We uncover that the slip effect facilitates the relative permeability of gas and water. Besides, the gas desorption–diffusion boosts gas relative permeability while limiting water relative permeability, whereas water film separation enhances water relative permeability but hinders gas relative permeability. This work brings insights into the precise description of multiscale and multieffect gas–water porous flow in unconventional gas development.

Method for oil and water relative permeability calculating in Western Siberia formations according to capillarimetric and geophysical data

The most important filtration characteristics of productive formations are the oil and water phase and relative permeability. Methods for obtaining relative phase permeabilities can be divided into laboratory and analytical. Currently, the main source of information about RFP are techniques based on laboratory core studies. However, for each productive reservoir, it is desirable to have analytical models describing experimental data on RFP with an accuracy sufficient for practical purposes. The existence of such models will make it possible to increase the accuracy of development computer modeling. The analytical expressions obtained in this study allow us to take into account the influence of the pore channels heterogeneity in size on the relative phase permeabilities magnitude. It is shown that the pore channels heterogeneity in size can be estimated by the residual water saturation amount, which in turn can be determined from the geophysical well studies. Keywords: relative permeability; residual water saturation; pore channels; capillarimetric and geophysical studies.

Comparing Centrifuge, Steady-State and Semi-Dynamic Methods for Relative Permeability and Capillary Pressure Determination: New Insights

Relative permeability and capillary pressure are essential parameters for understanding multiphase flow in porous media and scenarios of production in oil or gas reservoirs. There are several experimental methods for determining the relative permeability curves: unsteady-state (USS), steady-state (SS), and semi-dynamic (SD) methods. Each method has advantages and weaknesses. Although the USS approach leads to fast data results, the interpretation neglects the capillary pressure effects and provides a limited amount of data points obtained after breakthrough. The SS method is time consuming but enables covering a wider range of saturation with data points if the test is well designed. The SD method may be more time consuming than the SS method but provides both relative permeability to the injected phase and capillary pressure. The relative permeability to the produced phase is then determined by numerical means. The main objective of this study was to compare the water-oil relative permeability curves obtained from the steady-state and semi-dynamic methods performed at reservoir conditions with live fluids. Carbonate core plugs of same rock type and same properties were selected for this experimental program. The samples were brought to the same irreducible water saturation at a constant brine-oil capillary pressure using a centrifuge before being dynamically aged with live oil. In addition to monitoring the average saturation using material balance (MB), a linear X-ray scanner was used for in-situ saturation monitoring (ISSM) along the core samples. The oil relative permeability from the SD method was simulated with fixed water relative permeability and capillary pressure by history-matching the oil production and the differential pressure signal. Two additional centrifuge tests on twin plug were performed in order to measure imbibition capillary pressure and oil relative permeability at pseudo-reservoir conditions. This comparative study shows that the SD method provides similar capillary pressure and oil relative permeability curves to those obtained by centrifuge methods. Even if all Kr curves are in an acceptable envelop, some differences are observed between SD and SS Kr curves: several investigative leads are given to explain this discrepancy. It is also shown that a better saturation method needs to be implemented, especially when dealing with heterogeneous rocks. While a more robust ISSM method is being tested at TOTAL, the results presented in this paper are very encouraging.

Influence of permeability on rainfall infiltration based on water gas two phase flow

The permeability function is one of the key properties in unsaturated soil mechanics and variation of parameters in soil water characteristic curve can easily affect matric suction as well as infiltration. The purpose of this research is to explore the significant effect of parameters in SWCC on rainfall infiltration. A water gas two phase flow analysis method was conducted to investigate the influence of parameters in SWCC on stable infiltration intensity. Result showed that when saturation was low, stable intensity of infiltration was greatly affected by matric suction because the modified parameters were related to pore size distribution such as air entry value ρ0 and parameter m. When saturation was close to 1, the influence of soil infiltration intensity was almost not affected by matric suction. The minimum value of stable infiltration of intensity was mainly determined by the intrinsic permeability, while saturation of this value was mainly affected by soil water characteristic curve, intrinsic permeability coefficient of soil as well as water relative permeability coefficient.

Water-Gas Imbibition Relative Permeability: Literature Review, Direct versus Indirect Methods and Experimental Recommendations

When an active aquifer encroaches into a gas bearing reservoir or when an oil rim sweeps gas during late depletion of the gas cap, gas displacement by liquid is important for estimating the gas recovery. In the water displacing gas condition, the viscosity ratio is extremely favorable, resulting in a sharp waterfront in the reservoir matrix: it results that changing the relative permeability Kr shape has negligible effect, while endpoints water relative permeability Krw Max and residual gas saturation Sgr are much more important to understand gas flow performance for estimation of gas recovery with active aquifer or productivity decline after water breakthrough. Three main methods are used to determine water/gas relative permeability curves: imbibition unsteady-state, imbibition steady-state or indirect approaches such as co-current spontaneous imbibition if transient data are available. One of the other popular indirect methods is called Brooks-Corey approach: by measuring the drainage Pc curve using centrifuge or porous plate methods, it is possible to calculate a pore size distribution index c. This coefficient is used in a Brooks-Corey model to determine the drainage Kr curve. It is also required to measure and determine the relationship between the residual gas saturation Sgr and the initial gas saturation Sgi relationship. Finally, it is accepted that there is no hysteresis on the water relative permeability Krw curve, as water is always the wetting phase in the gas/water couple. As non-wetting phase, gas exhibits strong hysteresis between drainage and imbibition curves: it is therefore necessary to apply a correction on the drainage Krg curve to build the imbibition one using correcting models. The aim of this paper is to compare gas/water relative permeability of clastic rocks using direct waterflooding information and indirect approach using Brooks-Corey model. It is shown that using the indirect approach leads to results like those experimentally obtained. Also, additional numerical simulations are proposed to discuss the relevance of measuring the entire water-gas imbibition relative permeability curve using the steady-state approach.

Experiments on Water-Gas Flow Characteristics under Reservoir Condition in a Sandstone Gas Reservoir

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.