Minimum Miscibility Pressure Research Articles

Comparison of three miscible injectants for a high-temperature, volatile oil reservoir - With particular emphasis on nitrogen injection

Gas injection is a proven EOR method in the oil industry with many well-documented successful field applications spanning a period of more than five decades. Miscible nitrogen injection into oil reservoirs is a relatively uncommon EOR technique because nitrogen often requires a prohibitively high pressure to reach miscibility.In this paper, we investigate the potential for applying miscible nitrogen injection for a high-temperature, low-permeability carbonate reservoir, which contains a volatile oil with some H2S and CO2. The field is still in its early development phase but suffers from relatively low throughput rate because of low permeability. At the prevailing reservoir pressures, extensive phase behavior studies confirm that the reservoir fluids develop miscibility with nitrogen, carbon dioxide, and hydrocarbon gas.Nitrogen behaves differently from hydrocarbon gas, despite the fact that the two gases lead to similar minimum miscibility pressures. At the prevailing reservoir pressure, the swelling factor with hydrocarbon gas is four times higher than for nitrogen. Furthermore, the reservoir fluid density increases during swelling with nitrogen, whereas it decreases as a result of hydrocarbon gas swelling. The same trend is observed for viscosity. Injection gas blends with various proportions of nitrogen and carbon dioxide shows that the MMP is constant when more than 35–40% nitrogen is present in the blend.The simulation studies involve a number of sensitivity runs performed on sector models, which are sufficiently fine-gridded to capture the compositional transition zone propagating between injector and producer pairs. Miscible nitrogen injection comes out as a viable option with the potential to increase recovery by 10–20% above the current water flood development scheme. The significantly improved sweep and displacement efficiency are due to N2 miscibility with reservoir oil under reservoir conditions, possibility of increased PV injected in a N2 WAG scheme, and the ability to maintain the initial reservoir pressure.

Improved Method for the Estimation of Minimum Miscibility Pressure for Pure and Impure CO2–Crude Oil Systems Using Gaussian Process Machine Learning Approach

AbstractThe minimum miscibility pressure (MMP) is one of the critical parameters needed in the successful design of a miscible gas injection for enhanced oil recovery purposes. In this study, we explore the capability of using the Gaussian process machine learning (GPML) approach, for accurate prediction of this vital property in both pure and impure CO2-injection streams. We first performed a sensitivity analysis of different kernels and then a comparative analysis with other techniques. The new GPML model, when compared with previously published predictive models, including both correlations and other machine learning (ML)/intelligent models, showed superior performance with the highest correlation coefficient and the lowest error metrics.

Estimation of minimum miscibility pressure during CO2 flooding in hydrocarbon reservoirs using an optimized neural network

CO2 flooding recovery strongly depends on the minimum miscibility pressure (MMP). Conventional tests to determine gas–oil MMP such as rising bubble apparatus and slim tube displacement are either costly or time consuming. In order to propose a quick and accurate model to determine MMP, a back-propagation neural network is presented for MMP prediction during pure and impure CO2 injections. Five new variables were screened as input parameters to the network. Next, the network was optimized using five evolutionary algorithms, and this work highlights that three of these evolutionary algorithms (e.g. Mind Evolutionary, Artificial Bee Colony, and Dragonfly) are firstly used to predict MMP. Then, data from the literature were input to the optimized network to train it. Statistical evaluation and graphical analyses were used to evaluate the performance of the proposed models and for comparison with published MMP correlates to obtain the optimal model for predicting MMP. The back-propagation model optimized using the dragonfly algorithm exhibited the highest accuracy among all those considered and MMP correlates; its coefficient of determination, average absolute percent relative error, root mean square error, and standard deviation were 0.965, 5.79%, 206.1, and 0.08, respectively. In addition, reservoir temperature was determined as the strongest MMP predictor (Pearson correlation = 0.63) based on sensitivity analysis.

Techno-economic analysis of intermediate hydrocarbon injection on coupled CO2 storage and enhanced oil recovery

This study proposes economic evaluation of CO2 geological storage with enhanced oil recovery. The procedures consider capital expenditures and operating costs of infrastructures and revenues from oil recovery and carbon tax credits. Extensive CO2 geological storage with enhanced oil recovery simulations was conducted to determine the most promising scenario among cases, where miscibility was controlled by the addition of liquefied petroleum gas. The addition of liquefied petroleum gas into a CO2 injection stream can accelerate reduction of oil viscosity, interfacial tension, and oil density, which cause improved displacement efficiency. The larger was the amount of liquefied petroleum gas injected, the greater was the miscibility due to minimum miscibility pressure reduction, resulting in higher oil recovery and less CO2 sequestration. Although liquefied petroleum gas addition enhances the performance of CO2 enhanced oil recovery, economic analysis should be conducted for CO2 geological storage with enhanced oil recovery due to the higher price of liquefied petroleum gas than that of CO2. Net present value decreased from liquefied petroleum gas mole fraction of 0–2% and started to increase from mole fraction 2–13% due to the miscibility effect. Then, net present value started to decrease, because the purchasing and injecting prices of the required liquefied petroleum gas exceeded that of the oil produced. Economic evaluation showed that addition of 13% liquefied petroleum gas was the most promising scenario, with a net present value of 91 MM$. Thus, we confirmed an optimum liquefied petroleum gas concentration in the CO2 geological storage with enhanced oil recovery process.

Empirical correlations for prediction of minimum miscible pressure and near-miscible pressure interval for oil and CO2 systems

Although near-miscible CO2 flooding has recently received considerable attention, no criteria are available to predict its applicability to a specific reservoir. Evaluating the viability of near-miscible flooding requires experimental exploration of a specific region in pressure–temperature space. The near-miscible pressure field is bounded on one side in P, T space by the MMP (minimum miscible pressure). This paper provides robust empirical correlations to estimate the MMP for both pure and impure CO2 and for prediction of the near-miscible pressure region for CO2-oil. Many slim tube analyses, lacking high density data points, systematically underestimate the MMP, when the near miscible region is not accounted for. They are based on 147 published data sets that include: slim tube experimental determination of MMP; interfacial tension (IFT) between oil and CO2; concentration of solution gas; and purity of the CO2. This paper is the first to begin a systematic exploration of the pressure-temperature space within which near-miscible effects characterize CO2 floods. Our new correlations provide a basis for identifying and investigating the nature of near miscible effects associated with existing CO2 floods. For a case study of an offshore field we determined that lower and upper pressure boundaries for effective near-miscible flooding, are 0.87 MMP and 1.07 MMP at reservoir temperatures. The proposed model is the first empirical correlation for the prediction of near-miscible pressure region, it will provide the basis for both screening the relative potential of oil reservoirs for economically viable miscible or near-miscible CO2-flooding.

A new correlation for estimation of minimum miscibility pressure (MMP) during hydrocarbon gas injection

The satisfactory recovery of the hydrocarbon gases has made them a reliable choice for gas injection-based enhanced oil recovery (EOR) techniques. The minimum miscibility pressure (MMP) is a pivotal parameter governing the recovery factor during gas injection processes. Therefore, the determination of the authentic MMP is of a crucial importance. Due to the drawback of the experimental techniques (time and cost), empirical correlations are valuable tools in MMP determination. In this study, a multi-gene genetic programming and another software known as LINGO as an optimization tool are applied to offer a dependable MMP formula based on a comprehensive MMP dataset (a total of 108 MMP data). The independent parameters of reservoir temperature, pseudocritical temperature of the injection gas, molecular weight of C5+ components of the reservoir fluid and the intermediate (H2S, CO2, C2–C4)-to-volatile (N2 and C1) ratio are considered as input variables. A comprehensive set of experimental data covers wide span of primary parameters. Furthermore, in order to judge the accuracy of the suggested model and assess the precision and compare the predicted MMP by the current model with those estimated by preexisting correlations, the statistical and graphical error analyses have been employed. Based on the results, the proposed model can estimate MMP of the associated gas with an average absolute relative error of 9.86%. Also, the proposed correlation is more trustworthy and precise than the preexisting models in an extensive spectrum of thermodynamic circumstances. Eventually, the relevancy factor has depicted that the pseudocritical temperature of the injected gas has the most severe role in miscibility achievement.

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.

Application of Miscible Ethane Foam for Gas EOR Conformance in Low-Permeability Heterogeneous Harsh Environments

SummaryUnconventional plays pose a challenging set of operational conditions, including high temperature, high salinity, low permeability, and fracture networks. Aggressive development of these plays and the low primary recovery factors present an opportunity for using enhanced oil recovery (EOR) methods. This work presents a laboratory investigation of miscible ethane (C2H6) foam for gas EOR conformance in low-permeability, heterogeneous, harsh environments [<15 md, 136,000 ppm total dissolved solids (TDS) with divalent ions, 165°F]. The use of C2H6 as an alternative to carbon dioxide (CO2) offers several operational and availability strengths, which might expand gas EOR applications to depleted or shallower wells. Coupling gas conformance also helps improve displacement efficiencies and maximize overall recovery. Minimum miscibility pressure (MMP) displacement tests were performed for dead crude oil from the Wolfcamp Spraberry Trend area using C2H6 and CO2. Aqueous stability, salinity scan, and static foam tests were performed to identify a formulation. Subsequent foam quality and coreflood displacement tests in heterogeneous carbonate outcrop cores were conducted to compare the recovery efficiencies of three processes: gravity-unstable, miscible C2H6 foam; gravity-stable, miscible C2H6; and gravity-unstable, miscible C2H6 processes. Slimtube tests comparing C2H6 to CO2 resulted in a lower MMP value for C2H6. We identified a stable surfactant blend capable of Type I microemulsion and persistent foams in the presence of oil. Corefloods conducted with gravity-unstable miscible C2H6 foam, gravity-stable miscible C2H6, and gravity-unstable miscible C2H6 recovered 98.4, 61.9, and 42.6% oil originally in place, respectively. Our work shows that miscible C2H6 injection processes achieved significant recoveries even under gravity-unstable conditions. The addition of foam provides better conformance control, enhancing overall recovery at the laboratory scale, showing promise for field applications.

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.

Feasibility of miscible CO2 flooding in hydrocarbon reservoirs with different crude oil compositions

Miscible CO2-based enhanced oil recovery (CO2-EOR) flooding has been used, on many occasions, to maximize the recovery by mobilizing the residual oil. The success of this method, however, depends highly on the minimum miscibility pressure (MMP), the compatibility of CO2 with the reservoir rock and fluids. Although there have been several studies on the application of CO2-EOR, the impact of oil compositions associated with MMP on the feasibility of this technique has not been addressed elsewhere. In this study, a simulation study was carried out to investigate the effect of three different oil compositions on the miscibility and ultimate oil recovery of miscible CO2-EOR method. The results obtained indicated the oil type does not pose a significant impact on the success of miscible CO2-EOR. It was also found that the ultimate recovery of oil increases in a short period of time by injecting CO2 at the miscible conditions at the early stage of natural production. Comparatively, the reservoir with the fluid sample S2 seems to be a suitable choice for the miscible CO2 flooding once the recovery factor was considered together with the total amount of the fluid injected and produced.

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.

Thermodynamic Parameters for Quantitative Miscibility Interpretations from the Bulk to Nanometer Scale

In this paper, quantitative thermodynamic parameters are quantified and applied to evaluate the oilgas miscibility developments and determine the minimum miscibility pressures (MMPs) from bulk to ...

Experimental and simulation studies for optimization of water–alternating-gas (CO2) flooding for enhanced oil recovery

The paper deals with the screening of injection of water-alternating-gas (WAG) to tap the residual oil saturation left in the reservoir by over and above the water flooding. The detailed mineralogical composition has been studied by X-ray diffraction (XRD) method along with the petrophysical parameters to see their impacts of flow on Himmatnagar (India) sandstone. Saturates, aromatics, resins, and asphaltenes present in the crude oil were determined by ASTM procedure. Minimum miscibility pressure of CO2 with the crude oil was determined and it has been found at 1254 psi based on thermodynamic software. Different WAG ratios of 1:1, 1.5:1 and 2:1 have been applied for EOR during studies. Simulation on water injection followed by CO2 has been performed for investigation of the WAG process efficiency. A total 2 cycles of WAG injection was done with water flow rate of 1 ml/min and gas injection pressure around 1250 psi to achieve the better contact miscibility. The experimental data has been generated, compiled and interpreted during different cycles of WAG process. It was observed that WAG ratio 2:1 exhibits highest additional oil recovery around 34% of original oil in place. Increasing WAG ratio yields more additional oil recovery.

Prediction of CO2‐Oil Minimum Miscibility Pressure Using Soft Computing Methods

AbstractSearching for computational approaches for determination of the minimum miscibility pressure (MMP) is highly requested during the miscible gas injection process. New models, namely, the stochastic gradient boosting (SGB) algorithm and two distinct hybrid artificial neural network (ANN) models were used to predict CO2 MMP as a function of reservoir temperature, mole percent of volatile oil components, mole percent of intermediate oil components, molecular weight of pentane‐plus fraction in the oil phase, mole percentage of CO2 in injected gas, volatile components, and intermediate components in the injected gas based on 144 published data points. The SGB model was found to provide the better performance. The reservoir temperature turned out to be the most important factor.

Feasibility study of gas injection in low permeability reservoirs of Changqing oilfield

Changqing is the largest petroleum-producing field in China and one-third of its production is attributed to the formations with permeability lower than 1 mD. Based on the recent successes of gas injection pilots in North America, we investigated the feasibility of gas injection in the low permeability Chang 63 reservoir of Changqing. An eight-component fluid characterization, which fitted the measured PVT data, was used in a dual-porosity compositional model. A typical well pattern was selected for the simulation study. The key input parameters were adjusted to match the historical data. Huff-n-Puff using different gases shows that the richer the injected gas, the higher the oil production. C3H8 huff-n-puff achieves the best performance, increasing the cumulative oil production by a factor of 2.28 after 5 cycles, then followed by C2H6 and the produced gas. CH4 demonstrates a lower recovery factor (RF) than waterflood, because its minimum miscibility pressure is close to the maximum allowable injection pressure, i.e., the minimum horizontal stress. With the current well placement design where the producer is at the reservoir top, the miscible bank, which forms at the front of lean gas injection, will be displaced towards the reservoir bottom even out of the stimulated reservoir volume (SRV), undermining its performance. Rich gas is more compatible, as the miscible bank forms at the injection tail. Based on the fracture spacingsfrom the published work, we could, for the first time, verify the technical feasibility of rich gas injection in Chang 63 following the presented compositional modeling framework.

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...

Effect of Pore Size Heterogeneity on Hydrocarbon Fluid Distribution, Transport, and Primary and Secondary Recovery in Nano-Porous Media

In this paper, we investigate the effect of pore size heterogeneity on fluid composition distribution of multicomponent-multiphase hydrocarbons and its subsequent influence on mass transfer in shale nanopores. The change of multi-contact minimum miscibility pressure (MMP) in heterogeneous nanopores was investigated. We used a compositional simulation model with a modified flash calculation, which considers the effect of large gas–oil capillary pressure on phase behavior. Different average pore sizes for different segments of the computational domain were considered and the effect of the resulting heterogeneity on phase change, composition distributions, and production was investigated. A two-dimensional formulation was considered here for the application of matrix–fracture cross-mass transfer and the rock matrix can also consist of different segments with different average pore sizes. Both convection and molecular diffusion terms were included in the mass balance equations, and different reservoir fluids such as ternary mixture syntactic oil, Bakken oil, and Marcellus shale condensate were considered. The simulation results indicate that oil and gas phase compositions vary in different pore sizes, resulting in a concentration gradient between the two adjacent pores of different sizes. Given that shale permeability is extremely small, we expect the mass transfer between the two sections of the reservoir/core with two distinct average pore sizes to be diffusion-dominated. This observation implies that there can be a selective matrix–fracture component mass transfer as a result of confinement-dependent phase behavior. Therefore, the molecular diffusion term should be always included in the mass transfer equations, for both primary and gas injection enhanced oil recovery (EOR) simulation of heterogeneous shale reservoirs.

Study of Asphaltene Precipitation during CO2 Injection into Oil Reservoirs in the Presence of Iron Oxide Nanoparticles by Interfacial Tension and Bond Number Measurements

CO2 injection is one of the most frequently used enhanced oil recovery methods; however, it causes asphaltene precipitation in porous media and wellbore and wellhead facilities. Carbon dioxide saturated with nanoparticles can be used to enhance oil recovery with lower asphaltene precipitation issues. In this study, the vanishing interfacial tension technique was used to investigate the possibility of diminishing asphaltene precipitation by nanoparticles. The interfacial tension (IFT) of synthetic oil/carbon dioxide was measured using the pendant drop method. The results illustrated that, for synthetic oil samples containing asphaltene, the IFT data versus pressure decrease linearly with two different slopes at low- and high-pressure ranges. At high pressures, the slope of the plot is lower than the one in the low-pressure range. The addition of iron oxide nanoparticles to the oil solution reduces the interfacial tension at higher pressures with a steeper slope, showing that nanoparticles can decrease asphaltene precipitation. The plot of Bond number versus pressure also confirmed the impact of nanoparticles on reducing asphaltene precipitation. In terms of the temperature effect, the presence of nanoparticles at 50 °C resulted in a 16.34% reduction in asphaltene precipitation and a 19.65% reduction at 70 °C. The minimum miscibility pressure changed from 10.17 to 30.96 MPa at 70 °C; however, in the presence of nanoparticles, it reduced from 10.06 to 16.56. Therefore, the technique introduced in this study could be applied to avoid the problems associated with altering the gas injection mode from miscible to immiscible.

Determination of minimum miscible pressure in CO2-crude oil system of Changqing Oilfield

Carbon dioxide miscible flooding in low permeability sandstone reservoir can greatly enhance the recovery, the minimum miscible pressure (MMP) is the starting point of miscible flooding. Its determination is very important for oilfield development. In this paper, the internationally widely accepted thin tube experiment method and the bubble riser method are used to compare the minimum miscible pressure. Research results show that the minimum miscibility pressure obtained by slender tube displacement experiment is 22.12 MPa. The minimum miscible pressure measured by the bubbler method is 32.33 MPa, and the error result is large.

Correlation dependencies validation for minimum miscibility pressure of gas and reservoir oil determinination

The development of the theory and application experience of enhanced oil recovery methods comes to the fore in the conditions of depletion of traditional reserves. Russia has accumulated quite a lot of experience in applying gas enhanced oil recovery methods that have been tested at the Romashkino oil field, the Samotlor oil field, the Fedorovskoe oil field, etc. The maximum efficiency in the application of gas drive methods is achieved under the condition of miscibility or full solubility of the injected gas and reservoir oil. Therefore, an analysis of the gas methods applicability begins from the investigation of miscibility conditions assessment. Experimental study of miscibility conditions is a time consuming and expensive procedure. A large number of correlation dependencies taking into account the reservoir temperature and the composition of oil and gas - a candidate for injection into the reservoir were proposed in the technical literature for the initial assessment of miscibility. Most of these dependencies are defined for petroleum occurring in different parts of the world and diverse sediments. An analysis of the applicability of these correlations for the fields, which are located in Western Siberia, is an actual task. The article compares the results of calculations for more than ten correlation dependencies with experimental data for determining the miscibility conditions, performed on of slim tubes models, a case study of the Samotlor oil field. The comparison is made for both carbon dioxide and enriched hydrocarbon gases.