Relative Permeability Experiments Research Articles

State of the Art on Relative Permeability Hysteresis in Porous Media: Petroleum Engineering Application

This paper delivers an examination of relative permeability hysteresis in porous media in the field of petroleum engineering, encompassing mathematical modeling, experimental studies, and their practical implications. It explores two-phase and three-phase models, elucidating the generation of scanning curves and their applications in various porous materials. Building on the research of traditional relative permeability hysteresis models, we have incorporated literature on forward calculations of relative permeability based on digital rock core models. This offers a new perspective for studying the hysteresis effect in relative permeability. Additionally, it compiles insights from direct relative permeability and flow-through experiments, accentuating the methodologies and key findings. With a focus on enhanced oil recovery (EOR), carbon capture, utilization and sequestration (CCUS), and hydrogen storage applications, the paper identifies existing research voids and proposes avenues for future inquiry, laying the groundwork for advancing recovery techniques in oil and gas sectors.

On the Identifiability of Relative Permeability and Foam Displacement Parameters in Porous Media Flow

AbstractThis study focuses on analyzing parameter identifiability in foam displacement models during two‐phase flow in porous media, with a particular emphasis on calibrating relative permeability and foam parameters. We employ the profile likelihood technique and Bayesian inference for identifiability analysis. Successful parameter estimation is demonstrated through steady‐state experiments for relative permeability and foam quality scan experiments when both types of experimental data are available and obtained from the same core sample. However, non‐identifiability issues arise when only foam quality scan data is accessible. Additionally, we investigated a standard practice that fits foam parameters using foam quality scan data obtained from one core sample and permeability values obtained from another core sample, but from the same reservoir. Our results show that this practice is ineffective in correctly estimating foam parameters, leading to misestimation of crucial foam model parameters. These findings underscore the importance of a mandatory relative permeability experiment on a representative core sample from the reservoir for accurate characterization of foam parameters. Without it, misestimation of foam model parameters hinders the proper understanding of foam effects on sweeping porous media.

Comparative analysis of hydrogen, methane and nitrogen relative permeability: Implications for Underground Hydrogen Storage

Underground Hydrogen Storage (UHS) is an emerging technology which aims to store terawatt-scale energy in the subsurface to alleviate daily and seasonal fluctuations in the ever-increasing renewable energy market. Depleted gas reservoirs and aquifers will be the main targets of storage which requires an understanding of the interaction between formation or cushion gas with native brine. A comprehensive comparison of the petrophysical and two-phase flow properties of the hydrogen-water, methane-water and nitrogen-water systems at in-situ conditions is the focus of our work. We conduct steady-state relative permeability experiments at 2.13 MPa and 298 K using identical capillary numbers of Nc=2.92×10−7 for all three systems. The saturation and in-situ contact angles are determined with segmentation of 3D micro-CT images. The contact angle of each system is almost identical at the irreducible water saturation, Swi, 44°, 46°, 45°, respectively, as is the interfacial tension of 72.0, 71.5 and 71mN/m, respectively. The capillary pressure-saturation relationships for each system have a maximum difference of 3.8 % which leads to approximately equivalent relative permeability in the Bentheimer sandstone core. The end-point relative permeabilities are krg0=0.049, krg0=0.045 and krg0=0.062 at irreducible water saturations of Swi=0.24, Swi=0.25 and Swi=0.23, respectively. All three gases demonstrate equivalent flow properties which indicates that both nitrogen and methane are suitable analogue gases for laboratory multiphase flow experiments and cushion gas to improve safety and the economics of commercial UHS projects. The results enable history matched depleted gas reservoir performance to be used as a guide for UHS.

Hybrid Technique for Setting Initial Water Saturation on Core Samples

Relative permeability and capillary pressure are important parameters in reservoir simulations because it helps in understanding and anticipating oil and/or gas production scenarios over the years. They are both obtained in a laboratory after establishing the required initial conditions. As a matter of fact, before measuring imbibition relative permeability and capillary pressure, it is recommended to set initial rock reservoir conditions by establishing appropriate initial water saturation (Swi) and by aging the core to restore the reservoir wettability. There are several conventional techniques to establish Swi. Viscous flooding is a fast technique, but it may create a non-uniform saturation profile and, in some cases, be inefficient in reaching low Swi targets. Centrifugation is a capillary-driven technique that is also very fast; however, the possibility of not desaturating the outlet face is a significant constraint. In both cases, reversing flow direction is generally performed to flatten the saturation profile; however, this phenomenon is poorly controlled. The application of capillary pressure by porous plate allows targeting a specific value of Swi and generates a uniform saturation profile; however, it is a very time-consuming method. In this paper, we present the Hybrid Drainage Technique (HDT), which couples viscous flooding and porous plate approaches, significantly reducing the experimental duration when setting Swi. Another advantage of the method is the possibility of setting a uniform saturation profile at the targeted Swi. A specific core holder, adapted to nuclear magnetic resonance (NMR) imaging and capable of performing both viscous flooding and porous plate testing without unloading the rock, was designed. Using this core holder enables performing aging and imbibition coreflood testing with no further manipulation of the core sample. Monitoring saturation profiles was made possible by using an NMR imaging setup. The method has been tested and validated on two outcrop samples from Bentheimer (sandstone) and Richemont (limestone), drastically reducing the experimental time of the primary drainage step in comparison to classical porous plate drainage but also leading to uniform water saturation profiles. The experiment duration is reduced, and it enables the realization of coreflooding; therefore, this technique may be used for larger samples classically used in relative permeability experiments. This approach is preferred as it provides faster and more reliable measurements of saturation.

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.

From 3D real structure to 3D modelled structure: Modelling water vapor permeability in polypropylene/cellulose composites

A 3D tri-phasic numerical model was developed to predict water vapor permeability in composite materials made of polypropylene (PP) as matrix and cellulose particles as fillers, with existence of an interphase around permeable inclusions. About 70 tri-phasic structures composed of ellipsoidal, heterogenous-size particles were generated to represent composites with four different filler contents (φp=2.96−6.06−12.67−19.91%v/v) with interfacial region at the filler/matrix interface (either 1 or 2 μm thick) displaying its own permeability. The relative permeability (i.e., ratio between composite and neat matrix permeability) was calculated from Finite Element Method (FEM) simulations on these structures. A good prediction of experimental relative permeability for the whole filler content range investigated was observed. The presence of a percolating interphase observed in some structures explains the high permeabilization observed for high φp. The proposed 3D numerical model was confronted to five state-of-the art analytical models and was the only one able to describe the observed complex structures with identification of reliable characteristics for the interphase (thickness, permeability).

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.

An accelerated process-based method for the accurate computation of relative permeability from direct simulations of two-phase flow on micro-computed tomography images of porous media

Pore-scale forces have significant effects on the macroscopic behavior of multi-phase flow through porous media. We develop a robust and accurate accelerated process-based method for the computation of relative permeability from direct simulations of pore-scale two-phase flow on micro-computed tomography images. In the pressure drop calculation, we take advantage of an existing analysis that establishes a relationship between pore-scale forces and Darcy-scale pressure drops using an energy-conservation approach. We establish a thermodynamically consistent approximation of Darcy-scale viscous pressure drops as the rate of energy dissipation per unit flow rate of each flowing phase for the first time within the context of a free-energy lattice Boltzmann method (LBM). In addition, we propose and test a new computationally efficient partial-mirror periodic boundary condition for a fully coupled visco-capillary pore-scale flow simulator based on a free-energy LBM. The new boundary condition is imposed only in the main flow direction and significantly reduces the computational cost of the process-based relative-permeability computation protocol at a small compromise on accuracy.We first compute primary-drainage and subsequent imbibition relative permeability curves for a reservoir sandstone rock sample. We use this real-reservoir dataset to validate the pressure drop computation method and the partial-mirror periodic boundary condition. We then simulate the entire drainage and imbibition cycle using an extensively studied Berea sandstone dataset. We quantitatively demonstrate that pore-scale direct numerical simulation-based relative permeability curves computed with our novel process-based method agree well with experimental steady-state relative permeability measurements. We also quantitatively demonstrate that the new partial-mirror periodic boundary condition accelerates the relative permeability computations 4 to 13 times.

A new method for characterizing dynamic reservoir quality: Implications for quality maps in reservoir simulation and rock type classification

Determining reservoir quality is vital in order to efficiently produce hydrocarbon and/or inject fluids for secondary/tertiary recovery and carbon sequestration. In this study, we introduce a new approach and present dynamic reservoir quality index (DRQI). A high-quality reservoir would have high displacement (recovery) rate and displaceable (recoverable) saturation of oil. A modified true effective mobility (TEM) function is developed representing displacement rate of oil by an injected fluid (e.g., water or CO2). DRQI is defined as the area under modified TEM curve of oil and includes the well-known reservoir quality index (RQI) as its special case. A large dataset composed of 220 water displacing oil relative permeability experiments, conducted on limestone and dolomite rocks from three Iranian carbonate reservoirs, was used to investigate the potential relationships between DRQI and other reservoir characteristics (e.g., irreducible water saturation, bulk irreducible water, maximum movable oil saturation, and bulk maximum movable oil) as well as quality indicators of RQI, flow zone indicator (FZI), and Winland r35. Results showed that irreducible water saturation and maximum movable oil saturation as well as their bulk variants may not be appropriate for characterizing multiphase quality of reservoirs. Furthermore, the frequently-used single-phase rock quality indicators RQI, FZI, and Winland r35 were not found to be very accurate in characterization of dynamic reservoir quality. DRQI can be used in reservoir simulation studies as a criterion for defining quality maps, and in petrophysical tasks for rock typing and comparing between dynamic qualities (in terms of displacement rate and displaceable saturation of oil) of rock samples.

Simulated CO2 storage efficiency factors for saline formations of various lithologies and depositional environments using new experimental relative permeability data

Saline formations are attractive geologic reservoirs for permanent carbon dioxide (CO2) storage. The U.S. Department of Energy's National Energy Technology Laboratory (DOE-NETL) has worked to develop and refine methods and tools for the calculation of CO2 storage potential in subsurface reservoirs. DOE-NETL's CO2-SCREEN provides an online tool for executing these storage methods. CO2 storage efficiency terms are input parameters in DOE-NETL's methods and equations embedded in the CO2-SCREEN, which assesses pore space available for CO2 storage. In this work, a modeling workflow was initiated to refine two CO2 storage efficiency terms - volumetric displacement (EV) and microscopic displacement (Ed). The models are based on new experimental relative permeability data that are specific to homogenous lithology and depositional environments of key subsurface saline formations targeted for CO2 storage. In future work, heterogenous features will be added to this initial modeling effort to update efficiency factors as described in DOE-NETL's methods and CO2-SCREEN tool. EVaccounts for the volume utilized in the reservoir under the areal plume, while Ed accounts for saturation values in the plume to assess efficiency of CO2 storage at the pore scale. The results of this work are significant in that prior values were based on a limited geologically non-specific relative permeability data set that were collected prior to 2009. Specifically, we applied numerical simulations using TOUGH3 models to update CO2 storage efficiency values for supercritical CO2 injection into brine-saturated reservoirs for three lithologies (clastics, limestone, dolomite) and six depositional environments (Marginal Marine, Strand Plain, Deltaic Complex Fluvial, Aeolian, Shallow Marine, and Reef) that have a high potential for geologic CO2 storage. Experimental relative permeability data in cores from these environments were utilized in the models with corresponding rock type/sedimentary environment. Results of this study showed that dolomite followed by limestone generated higher ranges of storage efficiency compared to clastics. The updated values provided a tighter efficiency range for clastics, lower P10 but higher P90 range for limestone, and higher P10 and P90 for dolomite. In general, tighter reservoirs with relatively low permeability and porosity were associated with higher EV and Ed, showing efficient reservoir and pore utilization in these scenarios. High reservoir pressure and temperature associated with increasing depth increased the EV, and high CO2 injection rates resulted in increases in EV and Ed, while the impact of permeability anisotropy was minimal after the 30-year injection period.

A New Relative Permeability Characterization Method Considering High Waterflooding Pore Volume

In the process of waterflooding development, high waterflooding PVs will make the fluid percolation in the reservoir more complicated, resulting in lower efficiency of waterflooding. High waterflooding PVs will affect the relative permeability and change the seepage law of oil–water two-phase flow in a high water-cut period. In this study, we performed high waterflooding PVs relative permeability experiments using nine natural cores. The unsteady measurement method is used to test the relative permeability curve. The results show that: (1) the relative permeability is affected by the waterflooding PVs, the recovery efficiency of 2000 waterflooding PVs is 10.72% higher than that of 50 waterflooding PVs on the core scale; (2) it makes water mobility increase sharply, while oil phase flow capacity remains low and decreases at high water cut stage. A new relative permeability characterization method considering high waterflooding PVs is established, which is applied to the numerical simulator. It shows that the remaining oil saturation of the high-permeability belt is higher than the calculation results of the traditional numerical simulator. It means that the injected water does not diffuse much into the low-permeability zone of the formation. The modified simulator is validated with the actual China offshore oilfield model. The numerical saturation of the key section of the passing well is in good agreement with the actual logging interpretation results, and the water cut curve fits better in the whole area. The modified simulator could predict oil production accurately after high waterflooding PVs treatment.

Discussion on the Reconstruction of Medium/Low-Permeability Gas Reservoirs Based on Seepage Characteristics

The construction of underground gas storage mostly focuses on depleted gas reservoirs. However, the depleted gas reservoir used to build underground gas storage in China is located far from the main gas consumption economic zone. It is necessary to reconstruct underground gas storage using nearby reservoirs in order to meet the needs of economic development. The complex three-phase seepage characteristics encountered in the process of reconstruction of underground gas storage reservoirs seriously affect their storage and injection production capacities. Combined with the mechanism of multiphase seepage and the multicycle injection production mode during the process of gas storage construction, the feasibility of rebuilding gas storage in medium- and low-permeability reservoirs was evaluated through relative permeability experiments and core injection production experiments. The results showed that the mutual driving of two-phase oil–water systems will affect the storage space and seepage capacity, that the adverse effect will be weakened after multiple cycles, and that increasing the gas injection cycle can enhance the gas-phase seepage capacity and improve the crude oil recovery. Therefore, we found that it is feasible to reconstruct underground gas storage in medium- and low-permeability reservoirs, which lays a foundation for the development of underground gas storage in China.

Comparison of Intercept Methods for Correction of Steady-State Relative Permeability Experiments for Capillary End Effects

Summary Steady-state relative permeability experiments are performed by coinjection of two fluids through core plug samples. The relative permeabilities can be calculated using Darcy’s law from the stabilized pressure drop and saturation of the core if capillary end effects and transient effects are negligible. In most cases, such conditions are difficult to obtain. Recent works have presented ways to extrapolate steady-state pressure drop and average saturation measurements affected by capillary end effects collected at different rates to obtain correct relative permeabilities at correct saturations. Both the considered methods are based on linear extrapolations to determine intercepts. Gupta and Maloney (2016) derived their method intuitively and validated it with numerical and experimental data. Andersen (2021a) derived a method from fundamental assumptions and presented an intercept method in a different form where the saturation and relative permeabilities are found directly and uniquely from straightline intercepts. All system parameters, including saturation functions and injection conditions, appear in the model. In this work, the two methods are compared. It is proven theoretically that Gupta and Maloney’s method is correct in that it produces the correct saturation and pressure drops corrected for capillary end effects. Especially, a constant pressure drop was assumed and here proved to exist, as a result of capillary end effects in addition to the Darcy law pressure drop with no end effects. Their method assumes a well-defined end effect region with length xCEE, but this length can be defined almost arbitrarily. This choice has little impact on average saturation and pressure drop, however. They also assumed that for a defined end effect region, the average saturation was constant and equal to the slope in their saturation plot. It is shown that if the region is defined, the average saturation is indeed constant, but not given by the slope. The correct slope is predicted by the Andersen model. We also comment on theoretical misinterpretations of the Gupta and Maloney method. A few works have correctly calculated that the pressure drop over the end effect region is independent of rate, but not accounted for that its length is rate dependent. We show that the combined pressure drop is equal to a constant plus the Darcy pressure drop over the full core. Examples are presented to illustrate the model behaviors. Literature datasets are investigated showing that (a) apparently rate-dependent CO2-brine relative permeability endpoints can be explained by capillary end effects and (b) the intercept methods can be applied to correct shale relative permeabilities.

Enhancing acid fracture design in carbonate formation using a dynamic up-scaling procedure to convert discrete fracture network to dual continuum

For a low-permeability carbonate formation, the acid fracture process is simulated through coupling a commercial acid fracture simulator (GOHFER) to a finite volume reservoir simulator (IMEX). Unlike LGR (Local grid refinement) approach that suffers from severe convergence problems, a dynamic up-scaling procedure is employed to convert the discrete fracture network (DFN) model into a dual continuum model for our simulation. In this paper, multiple simulations are used to optimize the acid fracture schedule parameters, such as fluid volume, flow rate, perforation location, number of injection steps, and acid type, in order to maximize the effective fracture length. For four points perforation as the relevant operation case in this work, acid fracturing consumes 44 Mgal acid volume at a rate of 25 bpm at a 20 ft interval, resulting in a 3.5-fold increase in well productivity index (PI). Based on experimental relative permeability data, two models of fine and medium grid sizes are employed to be compared with the LGR method. The results have shown that these models are 22 and 54 times faster than LGR, however, the latter has a deviation of less than 5% which is quite acceptable.

Experimental investigation of synergistic effect of non-ionic surfactant and smart water injection methods for enhanced oil recovery from carbonate reservoirs

In the water-based EOR methods, surfactants and smart water injection methods usually are employed to reduce the water-oil interfacial tension and altered the rock wettability, respectively. The main objective of this study is to employ the combination effects of non-ionic Surfactants (including KEPS 80 and Behamid D) and Smart water Flooding to alter the wettability and interfacial tension (IFT) towards the most favorable conditions. Contact angle, spontaneous imbibition, capillary pressure (P c ), and relative permeability (k r ) experiments were performed at various concentrations of the surfactants and ions using carbonate rock to identify the various mechanisms occurring in the Surfactant and Smart water (SSW) flooding process and also to determine the additional oil recovery. The optimum concentrations of surfactant and positive ions (Mg 2+ , Ca 2+ ) were also obtained. In this regard, concentrations of the employed ions were optimized for altering the carbonate rock surface wettability toward the water-wet. The optimum surfactant concentrations obtained by Mohammadshahi et al. (2019) were also used, in this study. After obtaining the optimum concentrations, some promising aqueous solutions were designed for Amott cell, relative permeability, and capillary pressure experiments using the combination of surfactant and ions. Amott cell tests were implemented for comparing the ability of different aqueous solutions such as base water (Brine with 30,000 ppm NaCl), surfactant solution, smart water, and SSW solution in the oil recovery from the cores. Subsequently, relative permeability and capillary pressure experiments were performed. The results of contact angle experiments depicted that brine containing 24,000 ppm NaCl +6000 ppm Mg 2+ yielded the lowest contact angle among the studied samples. In the spontaneous imbibition tests, the oil recovery was obtained to be 7.6% for the base water, 9.5% for the smart water (24,000 ppm NaCl + 6000 ppm Mg), 15.09% for the surfactant solution (1500 ppm KEPE in 30,000 NaCl), and 20.8% for the SSF water. The relative permeability and capillary pressure tests have demonstrated the change of residual oil saturation and wettability of rock while using the SSW method compared to other techniques (i.e. base water, surfactant injection, smart water flooding). Finally, the results indicated that the combination of smart water and surfactant injection could lead to a much higher recovery factor than each method alone. • The brine with concentrations of 6000 and 2000 ppm of Mg ++ achieved the highest improvement in wettability alteration towards the water wetness. • The kr measurement highlighted that smart water can slightly improve oil relative permeability and the surfactant, was not very successful in improvingkr. • The brine designed with optimum ion and surfactant incredibly improved the kroand highly reduced the krw compared to the cases where each of surfactant and smart water are used separately. • The Pc tests demonstrated that the smart-surfactant water has the most favorable Pc with the least residual oil saturation.

Wettability of Carbonate Reservoir Rocks: A Comparative Analysis

Various methods have been proposed for the evaluation of reservoir rock wettability. Among them, Amott–Harvey and USBM are the most commonly used approaches in industry. Some other methods, such as the Lak and modified Lak indices, the normalized water fractional flow curve, Craig’s triple rules of thumb, and the modified Craig’s second rule are based on relative permeability data. In this study, a set of capillary pressure curves and relative permeability experiments was conducted on 19 core plug samples from a carbonate reservoir to evaluate and compare different quantitative and qualitative wettability indicators. We found that the results of relative permeability-based approaches were consistent with those of Amott–Harvey and USBM methods. We also investigated the relationship between wettability indices and rock quality indicators RQI, FZI, and Winland R35. Results showed that as the rock quality indicators increased, the samples became more oil-wet.

Micropore Structures and Percolation Characteristics of Carboniferous Carbonate Reservoirs in the Zanarol Area.

Proven oil and gas reserves in carbonate rocks comprise a high proportion of oil and gas fields, but these reservoirs have high heterogeneity. It is of great importance to study the micropore structures and percolation characteristics of carbonate rocks for the development of oilfields. In this paper, reservoirs are studied by means of casting sections, high-pressure mercury injection, and water and gas flooding oil phase permeability experiments. Reservoirs are classified into three categories, I, II, and III, by the k-means cluster analysis method. The results show that class I reservoirs are mainly composed of biolimestone with strong dissolution, displacement pressure of 0.016 MPa, median pressure of 0.135 MPa, mercury removal efficiency of 17.15%, well-developed pore throats, and good connectivity. They have the highest reservoir quality index and strong percolation ability. Class II reservoirs are mainly biogenic limestone and granular limestone with intergranular pores, a displacement pressure of 0.098 MPa, a median pressure of 6.026 MPa, and a mercury removal efficiency of 25.82%. The pore throat class is complex, and the sorting is poor. Class III reservoirs are mainly clastic limestone with residual intergranular pores, poor connectivity, displacement pressure of 0.403 MPa, median pressure of 3.77 MPa, mercury removal efficiency of 14.01%, small median radii, and good sorting performance. Relative permeability experiments show that water drive permeability at the isopermeability point is (0.049 10–3 μm2) higher than that of gas drive (0.041 10–3 μm2). The permeability of oil and water phases in class I reservoirs is obviously higher than those of class II and III reservoirs. When gas flooding is used, the phase permeability characteristics of class I and II reservoirs are no different than when water flooding is used. The permeability of gas flooding is slightly lower than that of water flooding. Because of the high proportion of micropores in class III reservoirs, gas can easily enter the pores, so the relative permeability of the gas phase increases rapidly. With increases in injection volume, the ultimate oil displacement efficiency of class I reservoirs can reach 53.2%, while those of class II and III reservoirs are 50.7 and 46.1%, respectively. This study provides important guidance for formulating oilfield development plans.

3D Modelling of Mass Transfer into Bio-Composite.

A three-dimensional model structure that allows considering interphase layer around permeable inclusions is developed to predict water vapor permeability in composite materials made of a matrix Poly(3-HydroxyButyrate-co-3-HydroxyValerate) (PHBV) including Wheat Straw Fiber (WSF) particles. About 500 two-phase structures corresponding to composites of different particles volume fractions generated using experimental particles’ size distribution have permitted to capture all the variability of the experimental material. These structures have served as a basis to create three-phase structures including interphase zone of altered polymer property surrounding each particle. Finite Element Method (FEM) applied on these structures has permitted to calculate the relative permeability (ratio between composite and neat matrix permeability ). The numerical results of the two-phase model are consistent with the experimental data for volume fraction lower than but the large upturn of the experimental relative permeability for highest volume fraction is not well represented by the two-phase model. Among hypothesis made to explain model’s deviation, the presence of an interphase with its own transfer properties is numerically tested: numerical exploration made with the three-phase model proves that an interphase of , with diffusivity of would explain the large upturn of permeability at high volume fraction.

Influence of Pore Throat Structure and the Multiphases Fluid Seepage on Mobility of Tight Oil Reservoir

Abstract Mobility is the main factor restricting the production of tight oil. In order to explore the influence of pore throat structure and fluid seepage on the mobility, six tight sandstone samples are selected by high-pressure mercury intrusion, nuclear magnetic resonance, water driving oil experiments, and oil-water relative permeability experiments to discuss the influence of pore structure and multiphases on the mobility of tight oil. The results indicate that with the increase in effective porosity, more oil and water are exchanged, and the mobility of the oil phase is enhanced. The large pore is positively correlated with the mobility of tight oil while the relationship between the mobility of small pore and effective porosity remains unclear. Particularly, the mobility of the tight oil is determined by the matching relationship between the pore throat radius and the sorting of the tight reservoir. Specifically, the smaller the two-phase copermeation zone, the greater the bound water saturation; the greater the slope of the oil phase permeability curve, the less the space for the two phases to flow together; the more the oil blocked by water in the reservoir, the worse the phase mobility. The mobility of tight oil can be divided into four categories by pore throat radius, pore throat sorting coefficient, and bound water saturation.

Measurements of the relative permeability to CO2‐and‐brine multiphase fluid of Paaratte formation at near‐reservoir conditions

AbstractCO2 sequestration in deep saline aquifers is a promising method to reduce atmospheric CO2. The on‐going CO2CRC Otway project aims to demonstrate the effectiveness of large‐scale CO2 storage in deep saline formations and to develop new monitoring technologies in Australia. The relative permeability curves are essential for predicting the movements of CO2 and estimate residual trapping in the aquifer during and after injection through numerical simulations. However, studies of relative permeability curves for the Paaratte sandstone at the in situ conditions are limited. In addition, different rock types in the Paaratte formation can behave differently when CO2 displaces brine. This work reports four relative permeability experiments of CO2/brine systems using the unsteady‐state core flooding method for different types of rock collected from various depths of Paaratte formations at near‐reservoir conditions. The relative permeability results calculated from the analytical Johnson, Bossler, and Naumann (JBN) method and the numerical history matching method are compared. The JBN method does not calculate the relative permeability accurately for CO2/brine systems due to the assumptions of incompressible flow, since the CO2 relative permeability results calculated from the JBN method are similar for all the cases. The history matching results show that the brine (water) relative permeability of the core samples with a high fraction of macropores is similar to the measurements for Paaratte formation reported in the literature over a large range of brine (water) saturation. In contrast, the brine relative permeability of the core samples with a high fraction of micropores is considerably higher than that of the core samples with macropores, suggesting better connectivity for the samples with a high fraction of micropores. The new findings will be useful in reservoir‐scale numerical modelings of the Paaratte formation to more accurately predict the movement of CO2 during and after the injection. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd.