Phase Equilibria for Enhanced Oil Recovery in an n-Butane Enriched Carbon Dioxide + Black Oil System

For a technically and economically successful miscible project, it is important that the solvent composition be as lean as possible for a given design pressure or that the operating pressure be as low as possible for a given solvent composition. In applying slim tube testing to assess miscibility, oil recovery by itself has historically been considered a sufficient criterion. This paper emphasizes that analyzing other test data, such as effluent gas compositions and pressure drop, are likely more reliable because there can be significant experimental errors associated with evaluating recovery. It is demonstrated that the ambient laboratory condition effluent gas compositions accurately reflect the solvent/oil mixture phase behaviour. In addition, the slim tube pressure drop data can be used to verify miscibility. Thus, by measuring these parameters, one can readily correlate miscibility conditions. It is also demonstrated that on accurately tuned equation of state together with a reliable prediction technique can significantly reduce the number of slim tube displacement tests required to quantify the miscibility conditions. Introduction Economics and solvent supply dictate the selection of miscible gas as an enhanced oil recovery technique. Miscible solvent design criteria, based mainly on oil recovery levels obtained from slim tube displacement tests, have been described in the literature(1,2) for evaluating miscibility. The purpose of this paper is to emphasize that other measured data such as atmospheric flash condition effluent gas compositions and pressure drops are reliable indicators of miscibility and must be included. There are generally two approaches to miscibility design. The first requires determining solvent compositions for a given reservoir pressure and is typically applied to hydrocarbon-based processes. The second approach is to predict a minimum miscibility pressure for a specific solvent composition. This technique is appropriate when considering carbon dioxide, nitrogen, or methane as solvents. An equation of state (EOS), can be used as a predictive tool for miscibility design(3). To use an EOS, it is required that the equation be tuned to accurately match reservoir gas-liquid phase behaviour. That is, the experimentally measured bubble point pressure, (Pb), gas-oil ratio, (GOR), and atmospheric flashed gas and liquid compositions of either a bottom-hole or a recombined test separator reservoir fluid sample must be accurately represented by an EOS. The EOS can then be readily used as basis to predict miscibility conditions. To verify an EOS prediction, two types of laboratory tests can be conducted: static vapour-liquid equilibria (VLE) measurements and/or dynamic slim tube displacement tests(l). Although interpreting VLE test data is usually straightforward, slim tube displacement tests are often misinterpreted by industry. Hence, it is necessary to review the physics occurring during displacement testing, so as to interpret the data from both the fluid phase behaviour and fluid displacement points of view. Terminology Reference to the ternary phase diagram in Figure 1 enables a review of the terminology. This diagram illustrates the phase behaviour existing at a single temperature and pressure. Components are grouped at the three vertices according to whether they are light ends, intermediates, or heavy ends.

Minimum Miscibility Pressures (MMP) for 102 combinations of oils, temperatures, and solvents were observed with a Rising Bubble Apparatus. The data were represented with a 4.5% standard deviation by an equation which needs only the solvent composition, oil C7+ fraction molecular weight, and the pseudoreduced temperature. A slightly better standard deviation of 3.5% was obtained by extending Peng's procedure for critical points of mixtures to calculate MMP.

Carbon dioxide flooding is a promising enhanced oil recovery method both on technical and, if operating costs are properly controlled, economic grounds. Injecting this greenhouse gas also has environmental merits. Flue gas from power plants is a ready source of CO2; however extracting CO2 for enhanced oil recovery from such a source will increase project costs. Furthermore, to reduce both the net CO2 utilization and the cost of purchasing gas, it is usually necessary to recycle the produced CO2 with as little purification as possible. Therefore, understanding the roles of impurities in fluid phase behaviour and miscibility characteristics is necessary for designing a cost-effective CO2 enhanced oil recovery process. Laboratory studies of the effect of CO2 impurities on phase equilibrium and minimum miscibility pressure (MMP) were conducted on two Saskatchewan light oils covering a range of densities from 29.5°API to 38°API. The results indicate that the MMP for these light oils could increase unfavourably as the N2 and/or CH4 concentration increased in the CO2 stream. The MMP changes as the type and concentration of impurities in the injected CO2 stream change. However, coreflood tests showed that the near-miscible CO2 displacement might employ the same mechanisms as miscible CO2 flooding to mobilize and displace oil; thus, good oil recovery can be achieved in the vicinity of the MMP. While laboratory measurements are essential in the evaluation of a gas injection process, an equation of state (EOS) simulation was demonstrated to be a useful tool in analyzing the phase behaviour of various injection gases, reservoir fluids, and the gas-oil interactions.

Gas injection as an EOR method is being considered for the giant Al Shaheen field, located offshore Qatar. The field is characterized by large lateral variations in fluid properties; the oil gravity ranges from 16 to 38 °API and significant variations in initial GOR and saturation pressure are observed.An extensive experimental program aimed at establishing the miscibility behaviour for this complex fluid system has been performed. Experiments included a range of gas injection tests such as swelling and multi-contact miscibility tests, enrichment studies and slimtube measurements. The miscibility behaviour across the range of oil gravities has been very well captured with a single equation of state (EOS) model, as described by Lindeloff et al. (2008).Slimtube measurements are the preferred method for establishing minimum miscibility pressures experimentally as condensing/vaporizing effects can be captured in this setup. The physical dispersion of the slimtube was characterized by a specially designed experiment using first-contact miscible (FCM) fluids. The results of the FCM experiments were used to determine the degree of numerical dispersion required in a 1D slimtube simulation model to match the measured data. An extrapolation towards an infinite number of cells was then performed to estimate the dispersion-free minimum miscibility pressure (MMP) from the slimtube experiments conducted on live reservoir oil using carbon dioxide as injection gas.In addition to the slimtube simulations, several algorithms for estimating the minimum miscibility pressure have been compared; some are empirical correlations, others are based on analytical gas injection theory using the method of characteristics (MOC) limiting tie-line method and the last one relies on a mixing-cell approach. The advantages and drawbacks of each approach are discussed, and the results are compared to laboratory data. In general, there is a very large spread in predicted MMP using carbon dioxide as injection gas. Empirical correlations generally overpredict the MMP for light oils and underestimate the MMP for heavy oils. Various key tie-line methods using the same tuned EOS model provide very different estimates of the MMP and some of them exhibit convergence problems. The results of the present work suggest that the mixing-cell model provides the most robust estimate of MMP over a large range of oil compositions, subject to EOS description. In essence, there is currently no prediction method that can replace the slimtube experiments.

Among existing enhanced oil recovery (EOR) processes, carbon dioxide (CO2) flooding is the most widely used. The popularity of CO2 as a miscible agent is due to its characteristics, which result in excellent macroscopic and microscopic efficiencies when miscibility conditions are optimal. In most CO2 flooding studies, these conditions are related to the minimum miscibility pressure (MMP), which is the pressure above which miscibility develops and materializes in recoveries equal to or higher than 90% (Metcalfe and Yarborough,1979). Since the MMP is a quick and convenient tool for conducting screening studies for post-evaluation of miscible projects, many correlations used to estimate the MMP have been developed for various crude oils and are presented in the literature. The problem is that not all correlations reflect the necessary process parameters needed in a typical CO2 flooding project. Correlations that work for reservoirs in North America may not be suitable for reservoirs in the Middle East. This paper addresses the issues related to experimental estimation of the MMP in a large, low-permeability reservoir in the Middle East and the evaluation of correlations as a means of estimating the MMP for a given reservoir. These issues range from the experimental approach and the verification of slim tube results by core flooding experiments to the use of dead versus live oil to estimate the MMP (for instance) or the effect of impurities on the MMP of pure CO2. The use of dead oil instead of live oil to conduct both slim tube and core flooding experiments resulted in errors up to 9%. Also the effect of some gases like nitrogen, hydrogen sulfide, and methane on the MMP of pure CO2 is discussed. Among the correlations tested, only one was found to apply with a reasonable accuracy to CO2 flooding in the reservoir studied. The deviation between live and dead oil MMP slim tube experimental results is also discussed as well as the correction due to contamination of CO2 by other gases.

A reliable fluid characterization achieved through the use of an Equation of State (EOS) is vital to reproduce the phase behaviour of a reservoir fluid and consequently, to improve understanding of the reservoirs EOR potential. In this case, an EOS model was developed aimed at accurately reproducing the phase behaviour of two reservoir oils in the same field that contain, besides H2S, substantial amounts of organic sulphur components. The tuning of the EOS for both oils was more difficult to achieve than in cases without such level of sulphur components. The tuning of the Peng-Robinson EOS was achieved with 9 pseudo-components for both oils, following the selection of the lumping scheme considered adequate for reservoir simulation studies. Organic sulphur components are concentrated in the higher range of molecular weights and, consequently, were incorporated into the heavy fraction. The tuned EOS was then used on a 1 D reservoir simulation compositional model to match the available slim tube experiments, to verify the validity of the EOS tuning. Using the compositional simulation of slim tube displacements, minimum miscibility pressure (MMP) was estimated for both oils and different injection gases. Although a 9 component scheme is adequate for reservoir performance purposes, engineering of surface facilities requires more detail. Therefore, a delumping methodology was developed to allow engineers to estimate detailed fluid composition from the lumped components obtained from reservoir simulation studies. One of the objectives of this study is to obtain a table of variation of the detailed components distributions that can be used for delumping purposes at different stages of the gas injection project.

Over the years, the slim tube experiment has been the most commonly used laboratory technique for determination of minimum miscibility pressure (MMP) for designing field miscible floods. However, till now, the design of these experiments is not standardized, neither in terms of set-up nor procedure. Often, the set-up, characteristics of the slim tube coil and even the experimental procedures are left to the discretion of the experimentalist, leading to very uncertain and non-unique MMP values, to say the least. Not just the uniqueness is of great concern, but also the lack of measurement repeatability; two measurements using same fluid samples under the "same experimental conditions" may result in too different MMP values. Matching these experiments with any PVT simulation package may pose a challenge, which even if a match is achieved, may be of questionable reliability. It is on this premise that this work was based. Slim tube experiments were designed and performed to study the effects of some parameters on the uniqueness and repeatability of the MMP measurements. It was found that MMP measurements are different with different injection rates. The lowest tested rate showed slightly lower MMP and better recovery performance than the other tested rates. No clear trend was noted, however. MMP was found to be lower for the larger coil diameter of the two investigated. MMP decreased as the coil length increased. The decrease in MMP with increase in coil length followed a parabolic trend. It was, therefore, concluded that laboratory measurements of MMP using the slim tube apparatus is a function of not just the characteristics of the interacting fluids but also those of the coil used as well as the choice of injection rates. The experimental design and procedure need to be unified to produce more reliable MMP data. It is the recommendation of the authors to design the experimental injection rate based on the expected field gas injection, to use the largest coil diameter possible, and to design the coil length, based on the expected well spacing between the injector and producer.

In a miscible displacement process, me condition of miscibility between oil and solvent can be achieved at pressures greater than a certain minimum. This minimum miscibility pressure (MMP) is one of the essential factors affecting oil displacement efficiency. The MMP of an oil-solvent system is often used as a key criterion for screening and selecting suitable solvents for enhanced oil recovery (EOR) projects. This paper compares the suitability of various solvents on the basis of their MMP determined for three oil samples collected from Weyburn pool (a reservoir located in southeast Saskatchewan). Three different methods were employed for determining MMP, namely, slim tube experiments, rising bubble apparatus (RBA) tests, and correlations. The solvents investigated included pure CO2, several blended or impure CO2 streams, and a wellhead gas from the Steelman gas plant near the pool The contaminants in the impure CO2 streams considered were nitrogen (from flue gas) and methane (from recycled CO2). Tests were carried out to determine the various amounts of impurities in. CO2 that can be tolerated for a miscible flood in the Weyburn field. Results of the study indicated that the MMP values measured by the RBA technique agreed well with those measured using the slim tube tests and those predicted using a published correlation. However, MMP values measured by REA were generally lower than those determined by slim tube. The difference in the values may be attributed to the method of interpretation. RBA tests are fast, precise, and less expensive for determining MMP but may require a knowledge of the mechanism of miscibility development for efficient operation. This study demonstrated that for the Weyburn reservoir, promising EOR agents (having an MMP below 80% of the reservoir fracture pressure) are pure CO2 and blended CO2 containing up to about 12 mol% CH4 or 5 mol% N2. The wellhead gas from Steelman gas plant requires further enrichment (with CO2 or hydrocarbon gases) to become a suitable EOR agent for southeast Saskatchewan reservoirs. Introduction The majority of light and medium oil (LMO) reservoirs in Saskatchewan have reached their economic limit of production under primary and secondary melhods.1 There is limited opportunity to discover additional reservoirs in askatchewan Therefore, it is essential to develop proper tertiary enhanced oil recovery (EOR) techniques if light and medium oil production in Saskatchewan is to be maintained. Miscible flooding with carbon dioxide or hydrocarbon solvents is considered to be one of the most effective EOR processes applicable to LMO reservoirs. It is estimated that an additional 15 to 25 percent of initial-oil-in-place (IOIP) will be recovered if EOR is successfully applied to Saskatchewan LMO reservoirs.2 Such a gain will triple the existing LMO reserves and extend the producing life of these reservoirs by two decades. With this in mind, the Saskatchewan Research Council (SRC) started a five-year multiclient research project in September 1988 to assess the suitability of CO2 and/or a hydrocarbon gas as a miscible flooding agent for Saskatchewan light and medium oil reservoirs. A reservoir located in southeastern Saskatchewan. Weyburn, was selected for the study.

Most Saskatchewan light and medium oil (LMO) reservoirs have reached their economic limit of production under current technology (primary and secondary recovery methods). The successful development of the miscible displacement process using CO2 and hydrocarbon gases will lead to a significant increase in Saskatchewan LMO reserves and substantially extend the production life of these pools. A laboratory study was conducted to evaluate the applicability of various solvents (including the potential source of CO2 extracted from flue gas) for the recovery of oil from a southeast Saskatchewan reservoir (Weyburn). The physical, chemical, and phase behaviour (PIT) properties of the dead oil, reservoir fluid, and reservoir fluid with CO2 were determined. Slim lube tests were conducted for the Weyburn reservoir fluid with pure CO2. with wellhead gas from the Steelman gas plant, and with two impure CO2 gases (one containing 9.9. mol % CH4 and the other containing 5.1 mol % N2 5.1 mol % CH4 in CO2 as contaminants) at various pressures and the reservoir temperature of 59 °C. The tests were also carried out to determine the maximum amount of impurities in CO2 that can be tolerated for the miscible process. The minimum miscibility pressures (MMP) determined for the above four systems demonstrated that the miscible displacement process using pure CO2 or impure CO2 containing up to 9.9 mol % CH4 (contaminant) as a solvent is a promising enhanced oil recovery (EOR) technique for southeast Saskatchewan reservoirs. The MMPs for these two systems are below the estimated reservoir fracture pressure. Carbon dioxide contaminated with 5.1 mol % N, from flue gas and 5.1 mol % CH4 from the reservoir during recycling would require further purification to lower the MMP to an acceptable level. The wellhead gas from the Steelman gas plant is not a suitable EOR agent for the Weyburn reservoir. Rising bubble (RBA) tests on the four reservoir fluid/solvent systems were conducted and the MMPs obtained from these systems were in good agreement with those obtained from slim tube experiments. The REA test is much faster than the slim tube technique, requires only a small amount of fluids and also allows direct visual observation of miscibility (vaporizing-gasdrive) development. The technique is thus considered to be superior to slim tube tests, where miscibility is inferred from the oil recovery and also from the somewhat subjective sight glass observation. Introduction Most Saskatchewan light and medium oil (LMO) reservoirs have reached their economic limit of production under current technology (primary and secondary recovery methods).1The successful development of the miscible displacement process using CO2 and hydrocarbon gases will lead to a significant increase in Saskatchewan LMO reserves and substantially extend the production life of these pools.2 Current industry interest in CO2 and hydrocarbon miscible flooding is high, as evidenced by the high level of activity in field testing worldwide.3

Most Saskatchewan light and medium oil (LMO) reservoirs have reached their economic limit of production under current technology (primary and secondary recovery methods). The successful development of me miscible displacement process using CO2 and hydrocarbon gases will lead to a significant increase in Saskatchewan LMO reserves and substantially extend the production life of these pools. A laboratory study was conducted to evaluate the applicability of various solvents (including the potential source of CO2 extracted from flue gas) for the recovery of oil from a southeast Saskatchewan reservoir (Weybum). The physical, chemical, and phase behaviour (PVT) properties of the dead oil, reservoir fluid, and reservoir fluid with CO2 were determined. Slim tube tests were conducted for the Weyburn reservoir fluid with pure Cal, with wellhead gas from the Steelman gas plant, and with two impure CO2 gases (one containing 9.9. molCH4 and the other containing 5.1 mol % Ni 5.1 mol % CH4 in CO2 as contaminants) at various pressures and the reservoir temperature of 59 ºC. The tests were also carried out to determine the maximum amount of impurities in CO2 that can be tolerated for the miscible process. The minimum miscibility pressures (MMP) determined for the above four systems demonstrated that the miscible displacement process using pure CO2 or impure CO2 containing up to 9.9 mol % CH4 (contaminant) as a solvent is a promising enhanced oil recovery (EOR) technique for southeast Saskatchewan reservoirs. The MMPs' for these two systems are below the estimated reservoir fracture pressure. Carbon dioxide contaminated with 5.1 mol % N2 from flue gas and 5.1 mol % CH4 from the reservoir during recycling would require further purification to lower the MMP to an acceptable level. The wellhead gas from the Steelman gas plant is not a suitable EOR agent for the Weybum reservoir. Rising bubble (RBA) tests on the four reservoir fluid/solvent systems were conducted and the MMPs obtained from these systems were in good agreement with those obtained from slim tube experiments. The RBA test is much faster than the slim tube technique, requires only a small amount of fluids, and also allows direct visual observation of miscibility (vapourizing-gasdrive) development. The technique is thus considered to be superior to slim tube tests. Introduction Most Saskatchewan light and medium oil (LMO) reservoirs have reached their economic limit of production Under current technology (primary and secondary recovery methods)(1). The successful development of the miscible displacement process using CO2 and hydrocarbon gases will lead to significant increase in Saskatchewan LMO reserves and substantially extend the production life of these pools(2). Current industry interest in CO2 and hydrocarbon miscible flooding is high, as evidenced by the high level of activity in field testing worldwide(3). In spite of a general slowdown in enhanced oil recovery (EOR) during the last two years (the number of active US EOR projects decreased from 366 in 1988 to 295 in 1990s, oil production from the miscible projects showed a 113% increase by 49% (over the same period in 1988).

The results of the minimum miscibility pressure (MMP) determination for miscible injection of two gases (CO2 and an associated gas of one of Iranian gas reservoirs) into two different oil samples from two Iranian oil reservoirs using a slim tube apparatus are presented in this work. For efficient determination of MMP, prior to slim tube experimentation, cell‐to‐cell simulation of the slim tube experiment was performed using a tuned Peng Robinson equation of state as a pre‐experiment and the results were used as initial estimates of MMP to select the pressure steps for the slim tube experiment. Finally, a comparison between the measured MMP values obtained by the slim tube experiments and those calculated by cell‐to‐cell simulation was made. It was shown that the cell‐to‐cell slim tube simulation predicts the results of slim tube experiments with a relative error of less than 6 %. This low error value shows that cell‐to‐cell simulation can replace the slim tube test in the cases where time is a major concern. Moreover, since the slim tube is an expensive and time‐consuming experiment and selecting the pressures to run the test is very important, cell‐to‐cell simulation can help us select the pressures for performing a slim tube experiment.

A novel protocol for estimation of minimum miscibility pressure from slimtube experiments

Carbon dioxide flooding process has been a proven valuable tertiary enhanced oil recovery technique. Although the petroleum industry has been applying the technique to produce heavy oil, it can be an effective tool to yield appreciable recoveries from complicated formations to produce comparatively lighter oil. The focus of experimental studies has been on the production of heavy oil and Carbon dioxide application to a wide range of other geological conditions and for wide range of petroleum fluids has been a less traversed path. Especially the process can be applied to tight formations where normal production procedures are not economically viable. This unviability may be due to rock or rock-fluid interactive properties. A research program for evaluation of the feasibility of development of such tight formations in the Middle East has been initiated. The research work included determination of minimum miscibility pressure (MMP), CO2 Core flooding and phase behavior investigation. Since both these processes are governed by the phase behavior; an investigation of phase behavior and PVT properties of reservoir fluids when combined with carbon dioxide are an integral part for a complete evaluation of crude oil extraction process. This paper presents the experimental and simulated phase behavior data for various mixtures of a live crude oil and carbon dioxide. The data helped in designing of the slim tube investigations and core flooding experiments. The phase behavior during a CO2 flooding is a very complex process. Three mechanisms; oil swelling, reduction of oil viscosity, and the acidization of carbonate help obtaining better recovery in a CO2 flooding process. First two are the mechanisms boosting the miscibility between CO2 and reservoir oil. The other parameters which effect phase behavior during a CO2 flooding are the temperature, pressure and rock-fluid interactive properties of the reservoir. Carbon dioxide can be first contact miscible with crude oils, but usually at very high pressure. Attaining and operating a flooding process at these pressures is not financially desirable. Multi contact miscible process is preferred as the economical process for the carbon dioxide flooding. The phase behavior of the original oil and after addition of different amounts of CO2 was studied by performing Constant Composition Expansion (CCE) tests. The bubble point pressure determined for the original oil sample and with increasing carbon dioxide. The phase behavior properties like bubble point pressure amount of liquid for the mixture with carbon dioxide range matched well with Equation of State (EOS) simulations. A comparison of the average density of the crude oil CO2 mixtures confirmed the swelling process. A material balance study between the injected and produced material from the core was also done for verification.

The CO2 flooding is a proven enhanced oil recovery technique to obtain high oil recovery from complicated formations and can be applied to various types of oil reservoirs. It can be injected as immiscible or miscible flooding but immiscible flooding is less effective than miscible flooding. Two types of miscibility can occur: first contact miscibility and multiple contact miscibility. First contact miscibility happens when a single phase is formed when CO2 is mixed with the crude oil. Multiple contact miscibility occurs when miscible conditions are developed in situ, through composition alteration of the CO2 or crude oil as CO2 moves through the reservoir. The miscible flooding process involves complex phase behavior, which depends on the temperature, pressure and fluid properties of the oil reservoir. The CO2 increases oil recovery by oil swelling, reduction of oil viscosity and density, the acidization of carbonate formations and miscibility effects. Multiple-contact miscibility between the injected CO2 and oil can be achieved at pressures above the minimum miscibility pressure (MMP). MMP is the pressure at which the reservoir fluid develops miscibility with CO2 and is a very important parameter in a well-designed CO2 flood project. Some reservoirs are considered tight because of poor rock or fluid characteristics. The main objective of this study is to investigate the performance of CO2 miscible flooding in tight oil reservoirs. This includes determination of minimum miscibility pressure (MMP) involving carbon dioxide and crude oil and miscible CO2 core flooding. This paper addresses the results of CO2 miscible flooding applied to a known reservoir. Several CO2 miscible flooding experiments were conducted using live oil at reservoir temperature and pressure above the MMP on composite cores of known reservoir. The MMP was determined experimentally using the slim tube. High oil recovery from these experiments indicates that the MMP determined from slim tube studies was correct and such a high recovery is only possible if full miscibility occurs during the displacement. The analytical correlation also gave a MMP consistent with MMP determined from slim tube experiments.

URTeC 1589572 Hydrocarbon and non-hydrocarbon gas injection are generally effective means to enhance oil recovery in conventional reservoirs. In unconventional oil reservoirs gas injection could also improve oil recovery, but it is not proven yet. A key design parameter in any gas injection project is the minimum miscibility pressure (MMP), which is the lowest pressure at which miscibility between the injected gas and reservoir oil is achieved when the interfacial tension between oil and gas vanishes. MMP is generally measured in the laboratory in sand-packed slim-tube flooding equipment, or in a rising bubble apparatus (RBA). In these experimental methods the gas and oil come in contact in a space sufficiently large enough to resemble the large pores in conventional reservoirs; and, such space confinement does not affect the conventional phase behavior. However, in unconventional oil reservoirs the small size of the pore space could significantly affect the thermodynamic phase behavior of contacted fluids because of capillary force and confinement effect on molecules. Hence, the slim tube and RBA measurements may not represent the in-situ MMP and, thus, may require correction. In this paper, we review experimental and numerical modeling methods of MMP determination and utilized the Multiple Mixing Cell (MMC) algorithm in our assessment. To account for the effect of capillary pressure and thermodynamic equilibrium in nanopores (hereafter, confined space), a critical property shift correlation was implemented in the conventional MMC algorithm for MMP determination. Two reservoir oil compositions (synthetic oil and Bakken oil) were used to determine their MMP with CO2 and a mixture of CO2 and CH4. Our results indicate that the MMP can be reduced by up to 600 psi for pore diameters less than 3 nm because of the critical property shift. On the other hand, capillary pressure does not significantly affect the MMP.