Gas-oil Relative Permeability Research Articles

Issue with Stone-II three phase permeability model, and a novel robust fundamentals-based alternative to it

The objective of this paper is to present a fundamentals-based, consistent with observation, three-phase flow model that avoids the pitfalls of conventional models such as Stone-II or Baker's three-phase permeability models.While investigating the myth of residual oil saturation in SAGD with comparing model generated results against field data, Gupta et al. (2020) highlighted the difficulty in matching observed residual oil saturation in steamed reservoir with Stone-II and Baker's linear models. Though the use of Stone-II model is very popular for three-phase flow across the industry, one issue in the context of gravity drainage is how it appears to counter-intuitively limit the flow of oil when water is present near its irreducible saturation.The current work begins with describing the problem with existing combinatorial methods such as Stone-II, which in turn combine the water-oil, and gas-oil relative permeability curves to yield the oil relative permeability curve in presence of water and gas. Then starting with the fundamentals of laminar flow in capillaries and with successive analogical formulations, it develops expressions that directly yield the relative permeabilities for all three phases. In this it assumes a pore size distribution approximated by functions used earlier in the literature for deriving two-phase relative permeability curves. The outlined approach by-passes the need for having combinatorial functions such as prescribed by Stone or Baker.The model so developed is simple to use, and it avoids the unnatural phenomenon or discrepancy due to a mathematical artefact described in the context of Stone-II above. The model also explains why in the past some researchers have found relative permeability to be a function of temperature. The new model is also amenable to be determined experimentally, instead of being based on an assumed pore-size distribution. In that context it serves as a set of skeletal functions of known dependencies on various saturations, leaving constants to be determined experimentally.The novelty of the work is in development of a three-phase relative permeability model that is based on fundamentals of flow in fine channels and which explains the observed results in the context of flow in porous media better. The significance of the work includes, aside from predicting results more in line with expectations and an explanation of temperature dependent relative permeabilities of oil, a more reliable time dependent residual oleic-phase saturation in the context of gravity-based oil recovery methods.

Uncertainty quantification for CO2 storage during intermittent CO2-EOR in oil reservoirs

CO2 enhanced oil recovery (CO2-EOR) process is considered the most feasible option for a secure storage of CO2 in underground formations. However, predicting amounts of CO2 stored and the oil recovered is associated with high risks due to data uncertainty. Sources of uncertainty lie in the challenges of accurately characterizing reservoir properties. Hence, the main objective of this study is to quantify the uncertainty of CO2 storage and oil recovery during intermittent CO2-assisted gravity drainage (CO2-GAGD) EOR process with a focus on key uncertain parameters including reservoir properties (permeability heterogeneity, porosity, and compressibility); fluid properties (CO2 diffusion coefficient and Henry's constant); and rock-fluid properties (gas-oil relative permeability data). Additionally, we aim to generate a rapid tool that reduces the computational expenses of the compositional reservoir simulation process by employing artificial neural network (ANN) as a machine learning (ML) tool. ANN was applied to generate predictive models that accurately predicted oil recovery and gas storage during the intermittent CO2-GAGD process. A total of 173 numerical samples were simulated and the objective functions were obtained. From the defined ranges of input variables and simulation results, cumulative distribution functions (CDFs) were obtained and uncertainty bounds, i.e., P10, P50, and P90, were estimated. Additionally, the generated ANN model showed excellent predictions of the objective functions with high correlation coefficients, higher than 0.98 in most of the cases, and with an absolute average percentage error (AAPE) range from 2.6 to 9%. Finally, the results of sensitivity analysis, conducted using the developed ML models with generating 10,000 realizations from the input and output parameters, showed the most influential input parameters on the performance of the CO2 storage and oil recovery factor. Reservoir porosity was found to have a significant impact on oil recovery and CO2 storage. A response surface analysis showed that the main independent input parameters contributing to the total uncertainty of oil recovery were horizontal permeability, oil relative permeability, and formation porosity. This study highlights the significant impact of uncertainties of input parameters on simulating the performance of CO2 storage and oil recovery in underground reservoirs.

Petrophysical Charaterizations of Some Reservoir Formations in Ghani Oilfield, Libya

This study has been conducted on three types of reservoir rocks for core analysis of samples denoted by R-1, R-2 and R-3 of Ghani oil field from three reservoir include Farrud, Facha and Mabruk formations respectively. This analysis includes determination of physical characteristics e. g. porosity ( ), permeability (k), formation factor (FF) and resistivity index (RI). The purpose of this study is to how core petrophysical data might be most investigating effectively applied to the petrophysical prediction of petrophysical properties from core samples analysis. For Farrud reservoir of R-1 shows that the relation between degree of saturation ( ) and relative oil permeability(Kro) equal the relative permeability of water(Krw) at which the intersection point between the two curves ; whereas, the flow with the same rate. FF and RI are vary with and the RI is a function of . The gas-oil relative permeability have been expressed graphically. Whereas, the intersection point between the two curves (Kro) equal the (Krg), at which both oil and gas are flow with the same rate. A similar results were obtained from Facha reservoir, R-2. The petrophysical properties of core samples for R-3 of Mabruk Formation have been performed including , k, and . The comparison between the three reservoirs by correlation between the average values such as , k, grain density and RI; shows that the average of Mabruk reservoir k greater than the other two reservoirs, while the other properties seem to be close together.

Experimental determination of relative permeabilities and critical gas saturations under solution-gas drive

Relative permeabilities are crucial to predict oil production from underground reservoirs. Multiple previous studies are limited to measuring/estimating relative permeabilities within the region where both phases are mobile. This study presents a novel experimental method to measure the oil relative permeability under presence of the trapped gas for gas-oil systems under depressurization. The experiments were carried out with the carbonaceous reservoir and outcrop samples. The results show a highly variable amount of immobile gas for North Sea chalk (from 8% up to 26% volume) and a significant reduction in oil relative permeability (up to 75%). The relative permeabilities were found to be power-law type functions. A comparison with the previously developed pore-network based model for gas-oil relative permeabilities is presented, allowing for reconstruction of both gas and oil relative permeability curves in the whole saturation range.

A note on dynamic rock typing and TEM-function for grouping, averaging and assigning relative permeability data to reservoir simulation models

For years, rock typing based on two-phase flow characteristics was mainly founded on grouping primary drainage capillary pressure curves, while rock classification based on relative permeability measurements and its practical applications were overlooked. Recently, a dynamic rock typing approach was proposed by defining a True Effective Mobility tool (TEM-function) to convert relative permeability data to fluid flow indicators. This technical note sheds further light on the concept of dynamic rock typing and TEM-function. Moreover, in previous studies the fact that how identified petrophysical dynamic rock types (PDRTs) and their corresponding average relative permeability tables should be assigned to simulation grid cells was not addressed. We accordingly investigate whether a general property can be found to assign average relative permeability data to grid cells. For this purpose, we apply TEM-function to identify PDRTs and present average relative permeability tables using gas-oil relative permeability experiments on a subset of carbonate samples. We also analyze the PDRTs in a counter-part water-oil system and investigate their relationship with gas-oil PDRTs. Results show that the recent dynamic rock typing approach incorporates forward and inverse processes that are physically meaningful and consistent with laboratory analysis and reservoir simulation processes. The strong dependency of TEM-function on the ratio of permeability to porosity enables us to introduce a general property to assign average relative permeability data to grid cells. Furthermore, while PDRTs in the gas-oil systems were almost identical, PDRTs in the water-oil system were dissimilar and different from the gas-oil counterpart. This confirms that each saturation function needs its specific rock typing scheme.

Simultaneous Interpretation of Three-Phase Relative Permeability and Capillary Pressure for a Tight Carbonate Reservoir From Wireline Formation Testing

AbstractIn this paper, techniques have been developed to interpret three-phase relative permeability and water–oil capillary pressure simultaneously in a tight carbonate reservoir from numerically simulating wireline formation tester (WFT) measurements. A high-resolution cylindrical near-wellbore model is built based on a set of pressures and flow rates collected by dual packer WFT in a tight carbonate reservoir. The grid quality is validated, the effective thickness of the WFT measurements is examined, and the effectiveness of the techniques is confirmed prior to performing history matching for both the measured pressure drawdown and buildup profiles. Water–oil relative permeability, oil–gas relative permeability, and water–oil capillary pressure are interpreted based on power-law functions and under the assumption of a water-wet reservoir and an oil-wet reservoir, respectively. Subsequently, three-phase relative permeability for the oil phase is determined using the modified Stone II model. Both the relative permeability and the capillary pressure of a water–oil system interpreted under an oil-wet condition match well with the measured relative permeability and capillary pressure of a similar reservoir rock type collected from the literature, while the relative permeability of an oil–gas system and the three-phase relative permeability bear a relatively high uncertainty. Not only is the reservoir determined as oil-wet but also the initial oil saturation is found to impose an impact on the interpreted water relative permeability under an oil-wet condition. Changes in water and oil viscosities and mud filtrate invasion depth affect the range of the movable fluid saturation of the interpreted water–oil relative permeabilities.

A black-oil approach to model produced gas injection in both conventional and tight oil-rich reservoirs to enhance oil recovery

A robust compositionally extended black-oil simulation approach is developed, which is capable of including the effect of large gas-oil capillary pressure for first contact miscible (FCM), and immiscible gas injection. The simulation methodology is applied to gas flooding in both high and very low permeability reservoirs. For a high permeability conventional reservoir, simulations use a five-spot pattern with different reservoir pressures to mimic both FCM and immiscible displacements. The results show that the simple modified black-oil approach can model well both immiscible and miscible floods, as long as the minimum miscibility pressure (MMP) is matched. For a tight oil-rich reservoir, primary depletion and huff-n-puff gas injection are simulated including the effect of large gas-oil capillary pressure in flow and in flash calculation on recovery. Finally, a dynamic gas-oil relative permeability correlation that accounts for the compositional changes owing to the produced gas injection is introduced and applied to correct for changes in interfacial tension (IFT), and its effect on oil recovery is examined. The results show that the new black-oil approach can model these processes well and could be implemented when fully compositional simulations are computationally too time consuming. For the first time, a black-oil type reservoir simulation method is used to simulate near-miscible and immiscible produced gas injection enhanced oil recovery. It provides a fast and robust alternative for large-scale reservoir simulation with the purpose of flaring/venting reduction through reinjecting the produced gas into the reservoir for EOR.

Compositional simulation of three-phase flow in mixed-wet shale oil reservoir

Three-phase flow is often involved during the production of shale oil reservoir. Relative permeability, which is often used to characterize multiphase flow, is found a strong function of wettability. Meanwhile, the mixed wettability in shale reservoir has been well characterized and may have impacts on fluid flow. In this work, to describe the mix-wet condition in shale, matrix is divided into organic and inorganic matrix which are hydrophobic and hydrophilic respectively. Relative permeabilities under different condition of wettability are applied in each kind of matrix. To construct permeability for three-phase flow, water-oil and oil-gas systems are evaluated separately with the assumption that water/gas permeabilities are only functions of their own saturations. Specifically, water-oil relative permeability is obtained by simulating multiphase flow directly on a digital rock sample using the lattice Boltzmann method. Oil-gas relative permeability is calculated from capillary pressure obtained from confined vapor liquid equilibria (VLE) coupled with Young-Laplace equation. Compositional simulation shows that the rich hydrocarbon in organic matrix is difficult to be produced due to the relatively lower permeability and poorer oil mobility under oil-wet condition. Since organic matter is a dispersed phase inside inorganic matter, fluids in organic matrix must flow through inorganic matrix before reaching the fractures. The dispersed nature of organic matter makes the relative permeability in inorganic matrix a dominant factor that controls the overall production in shale oil reservoir. The effect of relative permeability in organic matrix however has limited effect.

Experimental and theoretical study of gas/oil relative permeability

Gas injection is a proven economical process that significantly increases oil and condensate recovery from hydrocarbon reservoirs. Relative permeability is an important parameter in modeling, simulation, and evaluation of gas injection. In this study, new empirical-mathematical models are developed to predict the relative permeability of gas-oil systems in different rock and fluid systems. The Multi-Gene Genetic Programming (MGGP) technique is employed to develop relative permeability equations. The smart correlations presented in this work require capillary number, interfacial tension, API, gas molecular weight, and viscosity ratio as extra input variables to improve its precision and accuracy. The significance of each parameter is evaluated by statistical approach and Taguchi experimental design. The new models are evaluated by experimental data extracted from literature and validated by extensive error analysis. Additionally, laboratory tests were performed for determining gas-oil relative permeability which were used to check the accuracy of new developed correlations. In relative permeability curves for different gas flow rates, the coupling effect becomes strong and, in competition with the inertia effect, causes changes in the relative permeability with flow rate. The comparison of the experimental results of this study with the new proposed correlation resulted in a root-mean-square error (RMSE) of 0.0796 for gas relative permeability and 0.0564 for oil relative permeability. The results strongly admit the MGGP approach and high accuracy of developed mathematical correlations.

A further verification of FZI* and PSRTI: Newly developed petrophysical rock typing indices

Despite the differences between petrophysical static (PSRTs) and dynamic rock types (PDRTs), previous indices were unable to distinguish between them. FZI-Star (FZI*) and PSRTI are recently developed petrophysical dynamic and static rock typing indices, respectively. Considering the importance of rock typing in reservoir characterization and the need for reliable and user-friendly techniques, in this study we attempt to further verify the performance of FZI* and PSRTI by comparing them with FZI, Winland r35, and MFZI using data belonging to a heterogeneous carbonate reservoir from the Asmari Formation. The experimental data set includes 10 primary drainage mercury injection, 29 water-oil, and 45 gas-oil capillary pressure tests for PSRTs prediction in conjunction with 52 water-oil and 51 gas-oil relative permeability data for PDRTs. Moreover, we investigated the correlation between various indices and several petrophysical attributes. We defined these attributes as the integrals of mercury injection capillary pressure, mercury injection threshold capillary pressure, measured r35, capillary pressure, and relative permeability curves along with residual saturations. The results showed that our indices are able to successfully identify static and dynamic rock units with higher accuracy than other indices. Among the other existing methods, Winland r35 was the only one that showed an acceptable outcome; while, FZI, and MFZI underperformed in identifying the existing rock types. Using the experimental data we also propose the empirical equations that can be used to model capillary pressure and relative permeability characteristics of rocks.

Estimation of the water–oil–gas relative permeability curve from immiscible WAG coreflood experiments using the cubic B-spline model

Immiscible water-alternating-gas (WAG) flooding is an EOR technique that has proven successful for water drive reservoirs due to its ability to improve displacement and sweep efficiency. Nevertheless, considering the complicated phase behavior and various multiphase flow characteristics, gas tends to break through early in production wells in heterogeneous formations because of overriding, fingering, and channeling, which may result in unfavorable recovery performance. On the basis of phase behavior studies, minimum miscibility pressure measurements, and immiscible WAG coreflood experiments, the cubic B-spline model (CBM) was employed to describe the three-phase relative permeability curve. Using the Levenberg–Marquardt algorithm to adjust the vector of unknown model parameters of the CBM sequentially, optimization of production performance including pressure drop, water cut, and the cumulative gas–oil ratio was performed. A novel numerical inversion method was established for estimation of the water–oil–gas relative permeability curve during the immiscible WAG process. Based on the quantitative characterization of major recovery mechanisms, the proposed method was validated by interpreting coreflood data of the immiscible WAG experiment. The proposed method is reliable and can meet engineering requirements. It provides a basic calculation theory for implicit estimation of oil–water–gas relative permeability curve.

Modeling of Two-Phase Relative Permeability in Cambrian and Early Miocene Sandstone Reservoirs: A Case Study, Egypt

The relative permeability is the ratio of the effective permeability to the absolute permeability. Due to the importance of relative permeability in reservoir simulation, there is a dominant need to upscale it. So, several models were introduced to modeling the relative permeability. Some correlation models were dependent on capillary pressure measurements, while other models did not require such measurements. In this study, four relative permeability correlation models were chosen to apply them on two sandstone reservoir (labeled A and B) data sets. The two reservoirs belong to different ages and depositional environments. Both reservoirs are located in the Southern Gulf of Suez, Egypt. Reservoir A is the Nubian sandstone of Cambrian age. Reservoir B is the Nukhul clastic of Early Miocene age. The data sets include laboratory measurements of unsteady-state gas–oil relative permeability and steady-state water–oil relative permeability tests. The results indicate that the practical and modified Corey models were the most applicable model for the studied reservoirs. Additionally, prediction of relative permeability at saturation end points was carried out based on using routine core porosity and permeability by introducing new empirical equations. The relative permeability was used to identify rock wettability, water cut, water cutoffs and the areal and vertical sweep efficiencies.

Experimental study of gas–oil relative permeability curves at immiscible/near miscible gas injection in highly naturally fractured reservoir

The main aim of this work is to investigate gas–oil relative permeability curves as the main flow function in different gas injection scenarios, immiscible and near miscible in case of highly fractured reservoirs.In this research, some experiments have been done on the reservoir core sample selected from sandstone formation in one of the Iranian naturally fractured oil reservoirs. The core is saturated with oil sample and CO2 is injected into oil saturated core sample. Experiments have been performed on both of the sandstone and artificial fractured sandstone, represented as no fractured and highly fractured reservoirs, based on incremental pressure algorithm approaching into near miscible condition. Inverse modeling method has been used to calculate relative permeability curves.By comparing the relative permeability curves in immiscible and near-miscible conditions, the results show that in sandstone core type this change is considerable, but in highly artificial fractured sandstone with a high ratio of artificial fractured to sandstone absolute permeability (Kef /Ks) is not substantial. Moreover the results show that in the described case of artificial fractured core type so simple conventional relative permeability methods have the same results compared to a sophisticated inverse modeling method. The other main result is the lack of miscibility activation in near miscible injection through the highly fractured reservoirs leading to viscose dominant flow rather than capillary.Finally by considering this changing behavior, a better knowledge of gas front movement through highly fractured reservoirs in low IFT regions can be obtained.

Petrophysical properties analysis of a carbonate reservoir with natural fractures and vugs using X-ray computed tomography

X-ray computed tomography (X-ray CT) is a nondestructive internal core structure characterization technique. With X-ray CT, natural fractures and vugs have been identified in the Y Field, which is a limestone carbonate reservoir in the Middle East. Based on CT images of all core samples, three main core types in the Y Field were identified: matrix, fractured and vuggy carbonate. For core samples with different pore types and structures, the petrophysical properties vary considerably. In this paper, the X-ray CT technique was used to investigate the effect of fractures and vugs on the porosity–permeability relationship, internal heterogeneity of the core samples, permeability and porosity stress sensitivity, and oil–gas relative permeability. The analysis results show that matrix carbonate displays a stronger porosity–permeability relationship compared with that of fractured and vuggy carbonate. Fractured carbonate is very sensitive to the net confining pressure compared with non-fractured carbonate, and vugs increase the porosity stress sensitivity. The oil–gas relative permeability experiment demonstrates that fractures and vugs can provide flow channels and increase gas flowability. In particular, fractures are unfavourable for gas injection and oil recovery is low due to gas channelling.

Joint estimation of absolute and relative permeabilities using ensemble-based Kalman filter

An ensemble-based, sequential assimilation procedure is developed and successfully applied to estimate absolute and relative permeabilities jointly under multi-phase (oil, gas and water) flow condition in the porous media. Two-phase oil–water and gas–oil relative permeabilities are represented by power-law models, and Stone's Model II is used to calculate three-phase oil relative permeability. Prior absolute permeability field is also generated with isotropic Gaussian covariance. The proposed method is validated by a twin numerical setup with three different case studies, in which a synthetic 2D reservoir under multi-phase flow condition is considered. In the first case, there is simultaneous flow of oil, water, and gas phases within the reservoir. In the second, only oil and water phases are present; and, only oil and gas phases are mobile for the third case. By assimilating measured production rates of the producers and bottomhole pressure of the injector, relative permeability curves and absolute permeability field are accurately estimated. Therefore, simultaneous estimation of absolute and relative permeabilities from measured production data is feasible if there exists a prior model for the absolute permeability field and relative permeability curves.

Connectionist approach estimates gas–oil relative permeability in petroleum reservoirs: Application to reservoir simulation

Relative permeability of the petroleum reservoirs is a key parameter for various aspects of the petroleum engineering area like as reservoir simulation, history matching and etc. Due to this fact, various approaches such as experimental, theoretical and numerical approaches have been studied however; such experimental methods are time consuming, complicated and expensive. Based on the addressed disadvantages, robust, rapid, simple and accurate model is needed to represent gas/oil relative permeability through petroleum reservoirs. In this research communication we utilized the concept of various intelligent approaches such as least square support vector machine (LSSVM) which is high attended branches of artificial intelligent approaches. To develop and test the proposed LSSVM approach massive experimental relative permeability data from literature survey was faced to the addressed model. The suggested LSSVM method has low deviation from relevant measured values and statistical factors of the addressed model solutions were calculated. According to the determined statistical factors, the results of the proposed LSSVM approach prove and certify the high performance and low uncertainty of the addressed model in prediction gas/oil relative permeability in petroleum reservoirs. Finally, the suggested LSSVM model could help us to prepare more precise and accurate relative permeability curves without extensive experiment and furthermore, could lead to provide high performance reservoir simulation with low uncertainty.

A Laboratory Study of Gas-oil Relative Permeability during CO2 Injection

Gas injection is the second largest enhanced oil recovery process being applied in many reservoirs around the world. Simulation of these processes is necessary for implementation, management, and decision making. Relative permeability is one of the most important factors in numerical reservoir simulation. In this study, several core flood experiments are done and the relative permeability in carbon dioxide (CO2) injection is compared with nitrogen (N2) injection. Oil relative permeability in CO2 injection is found to be higher than in N2 injection, but gas relative permeability in CO2 injection is found to be lower than in N2 injection. Higher oil relative permeability in CO2 injection causes higher recovery factor, lower differential pressure across the core, and different trend of differential pressure during CO2 injection. Also, results were shown that enhancement of oil relative permeability by CO2 is increasing with decreasing oil saturation.

Integrated geologic modeling and reservoir simulation of Umiat: A frozen shallow oil accumulation in national petroleum reserve of Alaska

Current high oil price and availability of new technologies allow re-evaluation of oil resources previously considered uneconomic. The Umiat oil field is one such resource: a unique, shallow (275−1055ft), low-pressure (200−400psia) reservoir within the permafrost zone with no initial gas cap, located north of the Arctic Circle, 80miles west of the Trans Alaska Pipeline System (TAPS) with an estimated 1.5 billion barrels of oil in place.A static model was built based on reinterpretation of original log and core data and seismic information. A permeability anisotropy ratio of 0.45 was incorporated into the geologic model. A Monte Carlo simulation was conducted to estimate the different degrees of uncertainty in the original oil in place (OOIP) estimates. To cover the wide permeability range (0–500md), three sand groups (rock types) were defined and assigned appropriate capillary pressure and relative permeability curves. These were included in the dynamic model along with measured PVT data and gas–oil relative permeabilities in the presence of ice to evaluate the performance of immiscible gas injection using a multilateral wagon wheel well pattern with horizontal well length of 1500ft.The new simulation results show that with 50years of gas injection, recovery factors for the base case (400psia injection pressure) and two cases with 600 and 800psis injection pressures are 10.81%, 13.77%, and 16.66% respectively, keeping other parameters constant. These recovery numbers will reduce by 14% and 9% when producing GOR is restricted to 5000scf/STB and 10,000scf/STB, respectively. Due to unknown characteristics of natural fractures, several permeability anisotropy (Kv/Kh) ratios were considered. Simulation results indicate that lower anisotropy ratio will reduce oil recovery, probably due to inhibition in the downward movement of gas.The result obtained by this study contributes to the understanding of uncertainties in resource estimates and evaluating ranges of oil recovery in reservoir modeling. Despite limited data and lack of production history to tune the model, the results demonstrate that the economics of the proposed development plan bear a high degree of uncertainty and risk. These findings strongly encourage the operator to include development plan strategies to reduce the risk and enhance the quantity and quality of input simulation data.

Gas–oil relative permeability at near miscible conditions: An experimental and modeling approach

Reliable relative permeability curves of oil–gas systems are important for successful simulation and modeling of gas injection, especially when the miscibility condition approaches. In this work, the relative permeability of a CO2-light oil system has been measured under different conditions, using the Civan and Donaldson (1989) [13] method. Dolomite and sandstone core samples were used in the experiments. The minimum miscibility pressure was calculated using an empirical correlation, as well as slim-tube simulation. Due to some controversial assumptions of the Civan and Donaldson method, such as immiscible and incompressible displacement, history matching was used for predicting the reliable relative permeability of each phase at near miscible conditions. The Civan and Donaldson method was used to predict the relative permeabilities as the initial guesses for the history matching. We found that the Civan and Donaldson method underestimates oil relative permeability. Moreover, the effect of near miscibility on the gas phase relative permeability curve was stronger and the intersection point of the oil and gas phase relative permeability curves occurred at lower gas phase saturations. The results are helpful for understanding near miscible relative permeability behavior and provide knowledge on fluid flow at low IFT conditions during gas injection projects.

The Validation of Methods to Calculate Gas-Oil Relative Permeability Using Capillary Pressure Data from South Pars Reservoir

Gas-oil relative permeability is the most important parameter in the simulation of fluid flow in the gas condensate reservoirs. Experimental measurements of relative permeability need core samples with regular shape, which is costly and time consuming. On the other hand, experimental data of relative permeability may also have significant error and uncertainty in many cases. One source of uncertainty is that the input to numerical simulator is uncertain and inaccurate; it may be reduced if the number of input parameters is decreased, especially if the parameters with the greatest uncertainty are avoided. It is possible to impose only capillary pressure data, because relative permeability can be predicted consistently using specific models. The present methods, which are based on capillary pressure, considered the porous media as a bundle of capillary tubes; they indeed are mercury flow paths that are filled during the mercury injection capillary pressure test at the certain value of capillary pressure. The authors applied the existing capillary models for relative permeability calculations to a gas condensate reservoir. The tested samples have a wide range of liquid permeability from less than 1 to 18 md. The results of this study show that the Purcell model has the best fit with experimental data for wetting phase (oil), and the differences between measured and model data were almost negligible. The predictions of nonwetting phase (gas) relative permeability were a good agreement with experimental data except for Purcell model. Results reveal that the relative permeability could be computed by using accurate capillary pressure data.