Vanishing Interfacial Tension Research Articles

Impact of nanopore confinement on phase behavior and enriched gas minimum miscibility pressure in asphaltenic tight oil reservoirs

Miscible gas injection in tight/shale oil reservoirs presents a complex problem due to various factors, including the presence of a large number of nanopores in the rock structure and asphaltene and heavy components in crude oil. This method performs best when the gas injection pressure exceeds the minimum miscibility pressure (MMP). Accordingly, accurate calculation of the MMP is of special importance. A critical issue that needs to be considered is that the phase behavior of the fluid in confined nanopores is substantially different from that of conventional reservoirs. The confinement effect may significantly affect fluid properties, flow, and transport phenomena characteristics in pore space, e.g., considerably changing the critical properties and enhancing fluid adsorption on the pore wall. In this study, we have investigated the MMP between an asphaltenic crude oil and enriched natural gas using Peng-Robinson (PR) and cubic-plus-association (CPA) equations of state (EoSs) by considering the effect of confinement, adsorption, the shift of critical properties, and the presence of asphaltene. According to the best of our knowledge, this is the first time a model has been developed considering all these factors for use in porous media. We used the vanishing interfacial tension (VIT) method and slim tube test data to calculate the MMP and examined the effects of pore radius, type/composition of injected gas, and asphaltene type on the computed MMP. The results showed that the MMP increased with an increasing radius of up to 100 nm and then remained almost constant. This is while the gas enrichment reduced the MMP. Asphaltene presence changed the trend of IFT reduction and delayed the miscibility achievement so that it was about 61% different from the model without the asphaltene precipitation effect. However, the type of asphaltene had little impact on the MMP, and the controlling factor was the amount of asphaltene in the oil. Moreover, although cubic EoSs are particularly popular for their simplicity and accuracy in predicting the behavior of hydrocarbon fluids, the CPA EoS is more accurate for asphaltenic oils, especially when the operating pressure is within the asphaltene precipitation range.

Molecular insight into minimum miscibility pressure estimation of shale oil/CO2 in organic nanopores using CO2 huff-n-puff

CO2-enhanced oil recovery (EOR) has been regarded as an essential means of tertiary oil recovery worldwide, which has been gradually applied in exploiting shale oil and gas resources. In this study, we proposed a new method to estimate the MMP (minimum miscibility pressure) of shale oil/CO2 systems using huff-n-puff molecular dynamics (MD) simulations. The bulk MMP of the shale oil/CO2 system obtained agrees reasonably well with the vanishing interfacial tension (VIT) and the available experimental results. The organic nanopore oil reservoir is modeled with graphene as a substrate and octane molecules as shale oil. We found that oil recovery increases up to near miscible pressure and plateaus after that. The oil recovery increases with the rise of the reservoir temperature and slit height. Due to the nanopore’s confinement effect, the predicted MMP is lower inside the nanopore than the bulk counterpart. The MMP inside the nanopore decreases with a slit height up to a specific size and then starts to climb up due to the increased adsorption effect of nanopore walls. It means that CO2 flooding will be more efficient in shale oil reservoirs with more prominent pores and throats. Some CO2 molecules remain inside the nanopore after the completion of the huff-n-puff process. Like the oil recovery, the amount of CO2 trapped inside the pore after the huff-n-puff procedure plateaus after some critical pressure. So, CO2 huff-n-puff has two benefits — oil recovery and carbon sequestration. Our method of simulating huff-n-puff using MD can be a quick and economic supplement to the CO2-EOR experiments, which might benefit the development of shale oil reservoirs.

A novel experimental-theoretical method to improve MMP estimation using VIT technique

In the gas injection process for enhanced oil recovery (EOR), the interfacial tension (IFT) and the minimum miscibility pressure (MMP) are two key parameters for evaluating the miscibility condition. The vanishing interfacial tension (VIT) method is an efficient method for measuring the interfacial tension of oil and gas versus pressure and can estimate the minimum miscibility pressure. A problem in the VIT test of a hydrocarbon system is that during this test, oil and gas densities vary due to the composition variation of both phases. But in the conventional interfacial measurement, this issue is ignored, and the initial and non-equilibrium densities are utilized for estimating the interfacial tension. In this study, it is tried to nominate a novel method for estimating the most accurate value of IFT. Hence, for this purpose, first a VIT test has been performed for a hydrocarbon gas and a live oil system and using the axisymmetric drop shape analysis (ADSA), the oil droplet has been analyzed, and the geometry factor, which has been defined in this paper, was calculated. After that, the volume of oil droplet and the gas have been measured and were used for vapor-liquid-equilibrium (VLE) or flash calculation using Peng-Robinson equation of state (PR-EOS). By VLE calculation fulfillment, the final composition of two phases is determined. Eventually, the densities of two phases have been calculated for VIT modification. Finally, the IFT results were plotted versus the pressure steps, and the MMP were estimated. Furthermore, to evaluate the results of VIT test and its modification, slim tube displacement (STD) test, which is known as the most reliable laboratory method for measuring the MMP in the oil industry, has been performed. The results show that the values obtained for MMP values for the VIT test with the corrected densities which are lower than the values obtained for the VIT test for not-corrected densities and the suggested experimental-theoretical method has been estimated the MMP more accurately. The MMP obtained by VIT test and modified VIT method was equal to 3858.72 and 3722.0 psi, respectively. Meanwhile, the slim tube test has measured the MMP equal to 3667.13 psi.

Determination of the minimum miscibility pressure of the CO2/oil system based on quantification of the oil droplet volume reduction behavior

CO2 miscible flooding is one of the most ideal scenarios in oil recovery practices. Accurate prediction of the minimum miscible pressure (MMP) of the CO2/oil system is essential for CO2 Enhanced Oil Recovery (CO2-EOR) and carbon geological storage applications. In this paper, a novel method based on quantification of the oil droplet volume shrinkage behavior is proposed and demonstrated in the determination of the MMP of the CO2/n-hexadecane (n-C16H34) system and the CO2/n-octadecane (n-C18H38) system. Based on the specific quantitative criterion of the oil droplet volume reduction rate, the MMPs of the CO2/oil system under different temperature levels were determined. The accuracy of the measurement results has been validated with the corresponding thermodynamic phase equilibrium calculation results. To show the application potential of the proposed method, detailed discussions have been provided based on comparisons with the Vanishing Interfacial Tension (VIT) method. It is expected the proposed Oil Droplet Volume Measurement (ODVM) method could act as a robust supplementary for studying the miscibility characteristics of the CO2/oil system.

Chemical-assisted MMP reduction on methane-oil systems: Implications for natural gas injection to enhanced oil recovery

Miscible natural gas injection is widely considered as a practical and efficient enhanced oil recovery technique. However, the main challenge in this process is the high minimum miscibility pressure (MMP) between natural gas and crude oil, which limits its application and recovery factor, especially in high-temperature reservoirs. Therefore, we present a novel investigation to quantify the effect of chemical-assisted MMP reduction on the oil recovery factor. Firstly, we measured the interfacial tension (IFT) of the methane-oil system in the presence of chemical or CO2 to calculate the MMP reduction at a constant temperature (373K) using the vanishing interfacial tension (VIT) method. Afterwards, we performed three coreflooding experiments to quantify the effect of MMP reduction on the oil recovery factor under different injection scenarios.The interfacial tension measurements show that adding a small fraction (1.5 wt%) of the tested surfactant (SOLOTERRA ME-6) achieved 9% of MMP reduction, while adding 20 wt% of CO2 to the methane yields 13% of MMP reduction. Then, the coreflooding results highlight the significance of achieving miscibility during gas injection, as the ultimate recovery factor increased from 65.5% under immiscible conditions to 77.2% using chemical-assisted methane, and to 79% using gas mixture after achieving near miscible condition. The results demonstrate the promising potential of the MMP reduction to significantly increase the oil recovery factor during gas injection. Furthermore, these results will likely expand the application envelop of the miscible gas injection, in addition to the environmental benefits of utilizing the produced gas by re-injection/recycling instead of flaring which contributes to reducing the greenhouse gas emissions.

Mini Review of Miscible Condition Evaluation and Experimental Methods of Gas Miscible Injection in Conventional and Fractured Reservoirs

Nowadays, one of the most efficient ways of enhanced oil recovery (EOR) is gas miscible injection (GMI). In GMI, minimum miscible pressure (MMP) is the most substantial parameter. The MMP can be estimated by different methods, such as laboratory methods, using the equation of states (EOS), empirical correlations, mathematical models, and artificial intelligence. Among these, laboratory methods of estimating MMP comprise slim tube displacement (STD), rising bubble apparatus (RBA), vanishing interfacial tension (VIT), X-ray computerized tomography (CT), fast fluorescence-based microfluidic (FFBM) method, magnetic resonance imaging (MRI), sonic response method (SRM), rapid pressure increase (RPI), oil droplet volume measurement (ODVM), and pressure–composition diagrams (PCDs), all of which are described in detail in this paper. Furthermore, experimental investigations performed using the mentioned laboratory methods have been presented. On the other hand, to perform miscible injection experiments in the matrix–fracture system, there are methods, such as fractured core plug (FCP), matrix–fracture system (MFS), modified core holder (MCH), and microconsolidation device (MCD), that the accomplished studies by the mentioned method have surveyed. Eventually, it can be deduced that, owing to the difference between the MMP in conventional and fractured reservoirs, a reliable method (laboratory or mathematical model) for estimating the MMP in fractured reservoirs is required.

Chemical-assisted minimum miscibility pressure reduction between oil and methane

Miscible gas injection is an important enhanced oil recovery technique due to favourable displacement efficiency by eliminating interfacial tension (IFT) between the injected gas and oil phases. Miscible displacement often results in far higher recovery compared to immiscible displacement. However, miscibility can be difficult to achieve in high temperature reservoirs due to high minimum miscibility pressure (MMP) with increasing reservoir temperature and in shallow reservoirs where MMP would be higher than fracture pressure. Limited studies have been performed to explore the potential of reducing MMP in CO2-oil system using chemical additives. These additives work by collecting at the boundary between the two phases thereby reducing the interfacial tension. Specifically, none have investigated potential chemical additives to reduce the MMP in methane-oil systems, which limits the potential of methane injection. We thus investigated the effect of promising chemicals (surfactant based & alcohol based) for reducing the MMP in the methane-oil system at different temperatures (333 & 373 K) for an oil with a high acidity (4.0 mg KOH/g). Results using the vanishing interfacial tension (VIT) technique show that the tested surfactant-based chemicals reduce the MMP (methane-crude oil) by up to 9% at 373 K, whereas the tested alcohol-based chemicals have little effect on the MMP. Moreover, the results show that increasing temperature improves chemical performance and yields a higher MMP reduction, suggesting that these additives are more effective in high temperature reservoirs. The outlined research likely expands the application envelop of miscible natural gas injection in shallow and high-temperature reservoirs, in addition to the environmental benefits of reducing the associated gas flaring.

Interfacial interactions between Bakken crude oil and injected gases at reservoir temperature: A molecular dynamics simulation study

Due to large amounts of oil remain in the Bakken Formation, an effective enhanced oil recovery (EOR) method is crucially important. Cyclic gas injection, like CO2, methane, and ethane, can mobilize the residual oil and enhance oil recovery. In this study, the gas solubility, volume swelling factor, oil diffusion coefficient, and minimum miscibility pressure (MMP) were studied to compare the efficiency of different gases in the EOR process. Based on the Bakken oil components, a molecular model of the crude oil containing different types of alkanes was built. A series of molecular dynamics (MD) simulations were carried out to study the interfacial interactions between Bakken crude oil and the injected gases. At various pressures and reservoir temperature, density profiles were plotted to show the distribution of different components, and the solubility of gases in crude oil was calculated. The swelling factor was obtained by comparing the density of gas-saturated crude oil and that of the pure crude oil. The vanishing interfacial tension (VIT) method was used to determine the MMPs. The simulation results show that all three gases hold great potential in further improving oil recovery. As the pressure increases, the gas solubility increases, and the interfacial width becomes wider. At constant temperature and pressure, ethane holds the highest solubility in crude oil and can induce the most pronounced oil swelling. Meanwhile, ethane can achieve the lowest MMP and the most significant oil diffusion coefficient, which means ethane is most effective in mobilizing and producing crude oil from the reservoir.

Experimental Investigation of Asphaltene Content Effect on Crude Oil/CO2 Minimum Miscibility Pressure

Minimum Miscibility Pressure (MMP) is regarded as one of the foremost parameters required to be measured in a CO2 injection process. Therefore, a reasonable approximation of the MMP can be useful for better development of injection conditions as well as planning surface facilities. In this study, the impact of asphaltene content ranging from 3.84 % to 16 % on CO2/heavy oil MMP is evaluated. In this respect, slim tube miscibility and Vanishing Interfacial Tension (VIT) tests are used. Regarding the VIT test, the Interfacial Tension (IFT) is measured by means of two methods including pendant drop and capillary apparatuses, and thereafter the MMP measurement error between slim tube and VIT methods are calculated. Based on the results, by increasing the asphaltene content, the measured MMP by slim tube method increases linearly while that by VIT follows no clear trend. The results also indicate that there is an asphaltene content range within which the MMP error between slim tube and VIT tests is minimized. IFT measurement by pendant drop and Capillary Glass Tube (CGT) methods show that by increasing asphaltene content up to 10.15 %, IFT declines, whereas for further increase in content, IFT increases because of the irregular dispersion of asphaltene in oil droplets.

Studying Phase Behavior of Oil/Natural-Gas Systems for Designing Gas-Injection Operations: A Montney Case Study

SummaryAdvances in horizontal drilling and multistage hydraulic fracturing have unlocked tight-oil resources, such as the Montney Formation in the Western Canadian Sedimentary Basin. However, the average oil-recovery factor after primary production is 5 to 10% of the original oil in place. The aims of this study are to investigate phase behavior and to estimate the minimum miscibility pressure (MMP) of the Montney oil/natural-gas systems.First, we measure the MMPs of the oil/gas systems using the vanishing interfacial tension (VIT) technique. The gas samples are methane (C1) and mixtures of methane and ethane (C1/C2). Second, we perform constant-composition-expansion (CCE) tests to study the phase behavior of the oil/gas systems using a pressure/volume/temperature (PVT) cell. To complement the VIT and CCE tests, we perform bulk-phase tests to visualize vaporizing/condensing phenomena at the oil/gas interface using a visualization cell. Finally, we use the measured CCE and MMP data to calibrate the Peng-Robinson (Robinson and Peng 1978) equation of state (PR-EOS) and predict the MMP of the oil/gas systems using ternary diagrams. The results suggest that the dominant mechanism for developing miscibility conditions for oil/C1 and oil/C1/C2 systems is vaporizing and condensing gas drive, respectively. According to the results of the VIT and CCE tests, increasing C2 mole fraction in the gas mixtures significantly reduces MMP of the oil/gas system (from 4,366 psi for oil/C1 to 1,467 psi for oil/C1/C2 with 71.3 mol% C2) and increases the oil-swelling factor (from 1.47 to 1.61 by increasing C2 mol% from 0 to 70 mol%). The results of visualization tests show that the presence of C2 in the injection gas significantly enhances oil swelling compared with the pure-C1 case. We observe vaporizing flows of oil components in all tests and strong condensing flows of C1 and C2 into the oil phase in the C1/C2 test with increasing gas-injection pressure. The MMP values predicted by plotting two-phase equilibrium data on ternary diagrams appear to be in good agreement with the measured ones. The results can be used to optimize the injection-gas composition and operating pressure in the Montney.

Experimental Determinations of Minimum Miscibility Pressures Using Hydrocarbon Gases and CO2 for Crude Oils from the Bakken and Cut Bank Oil Reservoirs

Minimum miscibility pressures (MMPs) were measured at reservoir temperatures using a capillary-rise vanishing interfacial tension (VIT) technique for four crude oils collected from different format...

Ketone Solvent to Reduce the Minimum Miscibility Pressure for CO2 Flooding at the South Sumatra Basin, Indonesia

This paper experimentally analyzes the chemical additives, i.e., methanol and ethanol, as alcohol solvents, and acetone as a ketone solvent, and the temperature influencing the minimum miscibility pressure (MMP) that is essential to design miscible CO2 flooding at an oil field, the South Sumatra basin, Indonesia. The experiments were designed to measure CO2-oil interfacial tension with the vanishing interfacial tension (VIT) method in the ranges up to 3000 psi (208.6 bar) and 300 degrees Celsius. The experiment results show that lower temperatures, larger solvent volumes, and the acetone were effective in reducing MMP. The acetone, an aprotic ketone solvent, reduced MMP more than the methanol and the ethanol in the CO2-oil system. The high temperature was negative to obtain the high CO2 solubility into the oil as well as the lower MMP. The experimental results confirm that the aprotic ketone solvent could be effective in decreasing the MMP for the design of miscible CO2 flooding at the shallow mature oilfields with a low reservoir temperature.

Nanoscale-extended correlation to calculate gas solvent minimum miscibility pressures in tight oil reservoirs

In this paper, a novel nanoscale-extended correlation is developed to calculate the minimum miscibility pressures (MMPs) for a wide range of dead and live tight oil−gas solvent systems in bulk phase and nanopores. First, experimentally, the slim-tube and coreflood tests as well as the vanishing interfacial tension (VIT) technique are conducted to measure the MMPs of three oil‒gas systems. Second, the newly-developed correlation is proposed as a function of the reservoir temperature, molecular weight of C5+, mole fraction ratios of volatile components to intermediate components in oil and gas samples, and pore radius. Third, theoretically, the new correlation is analyzed on a basis of an oil‒gas MMP database from this study and literature that covers 101 oil‒gas MMP data for fifteen oil and thirteen gas samples at different reservoir temperatures in bulk phase and nanopores. A total of 40 commonly-used existing correlations are analyzed and reviewed. Compared to the seven existing correlations, the new correlation is found to provide the most accurate MMPs with an overall percentage average absolute deviation (AAD%) of 5.72% and maximum absolute deviation (MAD%) of 12.96% for different dead and live oil‒pure CO2 systems in bulk phase. Moreover, for the different oil‒pure and impure gas solvent systems, the new correlation leads to the best calculation accuracy of the MMPs with an overall AAD% of 4.70% and MAD% of 15.81% in comparison with the four existing correlations. More importantly, the new correlation is found to calculate the MMPs of different dead and live oil‒pure and impure gas solvent systems in nanopores in an accurate, efficient, and physical correct manner. The overall AAD% and MAD% in terms of the MMP calculations in nanopores from the new correlation are determined to be 6.91% and 13.66%, respectively.

Evaluation of four CO2 injection schemes for unlocking oils from low-permeability formations under immiscible conditions

In this paper, four different injection schemes, i.e., CO2 continuous gas injection (CGI), gas injection (GI) + soaking, pulse injection, and injection-alternating-production (IAP), for the high-temperature and pressure CO2 immiscible flooding in low-permeability formations are experimentally studied. A series of comprehensive and optimum practical strategies with respect to the four immiscible CO2 injection processes in the low-permeability formations can be determined from this study. More specifically, a total of 10 immiscible coreflood tests are conducted at the injection pressure of 20.0 MPa and reservoir temperature of 130.0 °C by means of the four different injection schemes. The oil viscosity and density are experimentally measured to be reduced with the temperature increase and the minimum miscibility pressure is measured to be 30.0 MPa at 130.0 °C from the vanishing interfacial tension (VIT) technique. Among Tests No. 1–10 with the same experimental conditions, the measured oil recovery factor (ORF) of Test No. 9, which is the CO2 IAP with the injection rates of 0.5 cm3/min, is the highest at 69.06%. In Test No. 4, the CO2 GI + soaking at the injection rate of 0.5 cm3/min has the second highest ORF of 65.21%. Tests No. 1, 4, 7, and 9 at the injection rate of 0.5 cm3/min outperform other tests with the same injection scheme in terms of the ORF under the same experimental conditions but at larger injection rates. Thus, a small CO2 injection rate is beneficial to increase the ORF for all schemes except for the CO2 pulse injections. It is found that soaking is an important step for CO2 enhanced oil recovery at the immiscible conditions. Moreover, the smaller injection rate also contributes to the delay of CO2 breakthrough so that a higher ORF can be reached at a lower cost. Finally, the measured asphaltene and wax contents in the produced oil are found to reduce in the percentages of 33–51% and 14–25% from the beginning period to the end of the oil production.

Evaluation of recycle gas injection on CO2 enhanced oil recovery and associated storage performance

An enhanced oil recovery (EOR) technique comprising the alternate injection of gas (CO2) and water, commonly referred to as water alternating gas (WAG) flooding, is currently ongoing at an oil field in the northeastern Powder River Basin (PRB), where 4 million barrels (MMbbl) of oil were produced between May 2013 and September 2017. During WAG flooding, a large amount of CO2, which contains some impurities, is produced at the surface with the recovered oil and reinjected into the reservoir to minimize the amount of purchased CO2. The concentration of these impurities in the CO2, which are dominated by CH4, is a key parameter in the design of miscible CO2 flooding of an oil reservoir and in the quantitative assessment of the associated storage of CO2 that occurs in the reservoir. For a given oil and reservoir temperature, the CO2–oil minimum miscibility pressure (MMP) is strongly and adversely affected by the presence of CH4, the concentration of which varies with time and operational conditions, such as injection pressure, flooding pattern, and injection scheme (i.e., continuous CO2 injection or WAG). To capture the full range of potential variation in the MMP caused by the presence of CH4, a series of laboratory experiments were conducted to determine CO2–oil MMP with different mole percentages of CH4 in the CO2. All of the experiments were performed at reservoir temperature (108 °F) using the VIT (vanishing interfacial tension) method. Results showed that MMP increases from 1403 to 4085 psi as the mole percentage of CH4 in the CO2 increases from 0% to 100%. To assess the impact of this variation in MMP on the oil recovery performance in the field, a history-matched, compositional reservoir simulation model was used to predict the oil production performance for a WAG flood using CO2 that contained a range of CH4 concentrations. The reservoir simulations examined the effects of permeability heterogeneity, fluid crossflow, and phase behavior on the oil displacement performance in three-dimensional space over time. Simulation results indicated that CO2 floods using a limited range of CO2–CH4 mixtures could still maintain multiple-contact miscibility and result in effective EOR. In addition, the ability to reinject produced CO2–CH4 mixtures as is, without removal of the CH4, ensured that this approach to EOR would continue to be cost-effective.

Carbon Dioxide Minimum Miscibility Pressure with Nanopore Confinement in Tight Oil Reservoirs

CO2-injection is one of the capable processes in EOR from low-permeable reservoirs and MMP determination is a key factor in estimating the displacement efficiency of the CO2 in the EOR processes. The laboratory procedures for MMP determination recognized in the oil industry are slim-tube, rising-bubble, or vanishing interfacial tension (VIT). However, the presence of nanopores in tight formations influences phase equilibrium, causing reduction in MMP. Instead, the existing MMP correlations need to be modified for tight reservoirs that might result in reliable MMP. Therefore, MMP measurement is performed using WinProp to validate correlations for tight oil samples. This study presents MMP determination experimentally using VIT for tight oil samples in both recombined-oil and dead-oil conditions. Subsequently, results obtained from VIT are compared with slim-tube results and the relative error was found 4.86% for recombined-oil and 23.36% for dead-oil. A huge deviation between VIT and slim-tube is noted while measuring MMP for dead-oil, due to deficiency of multiple contacts miscibility and stabilization of heavier fractions. subsequently, an already incorporated correlation for MMP is utilized, considering the effect of nanopore confinement. This study provides an appropriate technique for predicting MMP considering the capillary pressure and solubility on well performance of tight reservoirs.

Minimum miscibility pressure and interfacial tension measurements for N2 and CO2 gases in contact with W/O emulsions for different temperatures and pressures

In this research, the IFT behavior of two different specimens of W/O emulsion with distinctive soluble ingredients of water in contact with CO2 and N2 was examined. The Minimum Miscibility Pressure (MMP) of the mentioned gases with emulsion specimens were measured and compared with the case of the original crude oil with no water content. This study focuses on the quantity of water in the W/O emulsion specimens and its effects on IFT and MMP values. The IFT behavior of W/O emulsions was surveyed for two different cases of distinctive water soluble ingredients, i.e. sea water and reservoir brine. The tests were performed under high pressure-high temperature (HPHT) conditions utilizing Axisymmetric Drop Shape Analysis (ADSA) procedure. The equilibrium IFT values between the two distinctive specimens of W/O emulsions with different amounts and compositions of dispersed water and two types of gases, i.e. CO2 and N2, were measured. The outcomes were compared with the behavior of original crude oil, i.e. crude oil with no water content. The temperature was set in two distinctive values of 313.15 K and 333.15 K, and the pressure changes in the scope of 1 MPa–20.68 MPa. The outcomes manifested that the IFT behavior of the emulsion could be correlated directly with pressure for two distinctive variation rates, categorized in two different regions. Comparing to the original crude oil, in the case of W/O emulsion the equilibrium IFT increases, and this incremental behavior is much significant in the case of N2-emuslion system. Additionally, the outcomes of IFT versus pressure, in the case of N2-emulsion system, manifested that the slope of the first part of the curve decreases with increment in dispersed water content in the crude oil. However, the IFT values versus pressure in the second region were not affected by the water content of the emulsion. Also, Vanishing Interfacial Tension (VIT) technique was used to estimate the MMP of N2-emulsion systems. According to the outcomes, MMP was increased in the existence of water, and the incremental behavior becomes significant when the water content is increased. It is worthy to note that the outcomes of the CO2-emulsion systems manifested that both IFT behavior and MMP values were not changed significantly by water content. Finally, in light of the test information gathered in this research, various relationships were proposed to express the IFT and MMP correlations as dependants of pressure at distinctive temperatures.

Application of predicted bubble-rising velocities for estimating the minimum miscibility pressures of the light crude oil–CO2 systems with the rising bubble apparatus

In this paper, an empirical correlation is modified and applied to predict the CO2 bubble-rising velocity (BRV) in the light crude oil. On a basis of the predicted BRVs, the minimum miscibility pressures (MMPs) of three light crude oil−CO2 systems are estimated by using the BRV criterion with the rising-bubble apparatus (RBA). First, a correction term of s·2PρL0.5 is added into the BRV correlation in order to reflect the velocity of falling liquid film in velocity field by applying the Bernoulli’s theorem. The modified correlation is tuned to match the BRVs of the dead light oil–pure and impure CO2 systems from the literature and two respective numerical coefficients s of −0.00046 and −0.00028 are determined by using the non-linear least-square method. It is found that the BRV is positive proportionally increased with the bubble diameter, interfacial tension, and density difference. Second, the predicted BRVs are used to estimate the MMPs by using the BRV criterion. Two respective MMPs of the dead light oil–pure and impure CO2 systems are found to be 12.4 MPa and 23.7 MPa at Tres = 53.0 °C, which agree well with 12.4–12.9 MPa from the coreflood tests and 23.4 MPa from the RBA tests or 23.4–23.5 MPa from the vanishing interfacial tension (VIT) technique. In addition, a live light oil–pure CO2 system is added to validate the modified BRV correlation. By means of the predicted BRVs, the MMP of the live oil–pure CO2 system is estimated to be 15.5 MPa, which matches well with 15.2–15.4 MPa from the slim-tube tests. The modified empirical correlation can improve the efficiency and capability of the BRV criterion.

Experimental investigation on CO2-light crude oil interfacial and swelling behavior

Abstract A systematic series of experiments are designed and performed including interfacial tension (IFT) measurements concomitant with Bond (BN, the ratio of gravity forces to capillary forces) and swelling/extraction measurements. Dynamic IFT, BN and swelling/extraction are measured as a function of pressure at temperatures of 30, 50 and 80 °C. In addition, in the light of measured IFT the minimum miscibility pressure (MMP) of CO 2 and light crude oil is determined based on a method called vanishing interfacial tension (VIT). The obtained results interestingly revealed that equilibrium IFT decreases linearly with pressure in two distinct pressure intervals while equilibrium BN shows an increasing trend as a function of pressure for all of the studied cases while no obvious trend is observed for swelling of crude oil and extraction of light-components regarding time, temperature and pressure.

Minimum miscibility pressure measurement for CO2 and oil using rapid pressure increase method

CO2-enhanced oil recovery (CO2-EOR) is a technique for commercially producing oil from depleted reservoirs with associated benefits of capturing and storing large quantities of CO2. Minimum miscibility pressure (MMP) for gas and oil system is one of the most important factors affecting projecting and developing of EOR CO2 miscible flooding to reach maximum recovery efficiency. Determination of MMP can be performed with computational techniques and experimental methods. The slim tube test (STT), the pressure rising bubble apparatus (RBA), the vanishing interfacial tension (VIT), and recently, developed the sonic response method (SRM) can be considered as the petroleum industry experimental approaches for determination of the MMP for hydrocarbons and CO2. This paper presents a new technique, named rapid pressure increase method (RPI) to measure MMP and investigate the phase behavior of the analyzed fluids. The main principle of the measurement are determination of the relation between pressure increase and reduced volume of binary system and registration of the moment at which derivative of the function is the lowest. This point corresponds to ratio change of pressure increase to reduced volume and is considered as MMP. Determined values fit well with previous work and literature data. This experimental method of MMP is simple, time-saving, and more easily to conduct than other experimental techniques of measurement MMP.