Gas Injection For Enhanced Oil Recovery Research Articles

Importance of critical point for the phase behavior of a reservoir fluid

It is a fundamental assumption behind a cubic equation of state that the phase behavior of a pure component can be expressed in terms of its critical temperature and pressure. This paper shows that the location of the critical point also for multicomponent reservoir fluids influences the phase behavior throughout the gas and liquid region. An equation of state model that matches the critical point and the saturation pressure at the reservoir temperature is likely to provide a good match of the phase behavior of a reservoir fluid at all conditions experienced during oil and gas production. An experimental critical point is seldom available for a reservoir fluid but the critical point can be estimated from correlations in the molar ratio of C7+ and lighter hydrocarbons. When PVT data exists, such estimated critical point can be used as an extra datapoint when assigning critical properties to an equation of state model. This is particularly useful as a constraint when the equation of state is to be used for gas injection enhanced oil recovery calculations. When the available PVT data is limited to a saturation point at the reservoir temperature, a reliable equation of state model can be developed by only tuning to the saturation pressure and the estimated critical point. The presented method is applicable to reservoir oils and gas condensates with a C7+ mole% of at least 10.

Investigating Enhanced Oil Recovery in Unconventional Reservoirs Based on Field Case Review, Laboratory, and Simulation Studies

Aimed at advancing gas injection enhanced oil recovery (EOR) technologies in unconventional reservoirs, this study comprised a series of activities to bridge the gap between the theoretical study and actual field applications. Twenty-four EOR pilot tests were collected from the major unconventional plays in North America to evaluate the performance of different EOR technologies. Fit-for-purpose experiments and simulations were performed to investigate the effects of injection rate and pressure on EOR performance, as well as to reveal the effectiveness of huff “n” puff (HnP) cycles in actual field operations. The selection of injection rate and pressure as key parameters for investigation was based on field observations and communications with oil and gas operators because these two parameters play critical roles in both facility design and overall cost for an EOR project. Results showed that miscible EOR with a high gas injection rate and pressure is required for field operations because the injected gas needs to penetrate and extract oil from the tight matrix. Experimental results indicated that there is a correlation between oil recovery and the logarithm of core volume for miscible EOR. Immiscible gas EOR could not yield a satisfactory EOR response in actual reservoirs because the injected gas tends to flow through fractures instead of penetrating the matrix to interact with oil. Results also showed that reaching minimum miscibility pressure (MMP) does not guarantee an optimum EOR operation in unconventional reservoirs. Pressure higher than MMP is preferred in field operations. When designed properly, up to a tenfold oil production rate boost is achievable in field applications within a short period. However, such a high-performance operation is only effective in the first several HnP cycles due to the limited gas penetration depth into the rock matrix.

Water-Plus-Gas Injection on a Bakken Well Pad May Solve Problems That Stymied Shale EOR

_ After years of enhanced oil recovery (EOR) tests in the Bakken, one method finally appears to have added to a well’s ultimate production. The Liberty Resources well “is perhaps the first one that had clear, indisputable evidence of incremental oil. I do firmly believe we are on the right track for cracking the code for Bakken EOR,” said Jim Sorensen, director of subsurface R&D for the University of North Dakota Energy and Environmental Research Center (EERC) which provided technical support and funding. The gain predicted after the treatment with water alternating with gas injection (WAG) is not huge. A paper on the test, which was limited to a single 30-day injection cycle, estimated it added 7,000 bbl to the ultimate production, based on decline curve analysis (URTeC 3722974). An updated analysis from EERC is expected in early 2023. While there are endless arguments over the accuracy of decline curve analysis, Gordon Pospisil, development advisor for Liberty, said incremental oil estimates look solid: “The oil rate response to water alternating gas injection was clearly measurable at over 7,000 bbls over the baseline trend.” The bigger news may be an injection method that can overcome two barriers to EOR in the Bakken and elsewhere. One is finding a way to keep the injected gas around the wellbore, and the other is significantly lowering the cost, primarily by slashing the volume of gas required. “Overall, we were pleased with the project outcome to date as we were able to build pressure, contain the injection within the DSU (drilling spacing unit), and make incremental oil,” Pospisil said. For the test, Liberty used a novel, computer-controlled injection system from a startup company, EOR ETC. This system can rapidly switch from gas to water injection based on the control system the company developed. This reduces the surface injection pressure required to significantly increase the downhole pressure level and helps contain the gas in the target zone. “I have never seen anything like that. It performed as advertised,” Sorensen said. The estimated long-term gain looks small compared to the 800,000 bbl of oil prior to the test. But Brian Schwanitz, president of EOR ETC, said the income from those barrels covered what they billed for pumping the job, which was a discounted rate reflecting Liberty’s willingness to be the first operator to use the device. What it accomplished stands out compared to the futility of past Bakken tests where far more gas was injected with little impact on the downhole pressure because so much of it leaked off through the fractured formation. The Bakken Debacle For a decade, companies in the Bakken, often in partnership with the EERC, have searched for ways to get more oil out of the play where the ultimate recoveries are usually below 10% of the oil in place, which is in line with other unconventional oil plays. Gas-injection EOR tests in oil-producing shale plays have been hit or miss, with most of the results in the Bakken in the miss column. The problem has been that much of the gas escapes from the target zone, making it impossible in some cases to achieve the pressure levels needed for effective EOR and it increases the volume of gas needed to uneconomic levels for gas-only projects to achieve improved ultimate recoveries.

Experimental evaluation of enhanced oil recovery in unconventional reservoirs using cyclic hydrocarbon gas injection

The significant amount of gas produced from unconventional reservoirs in the US in recent years has reduced market prices for hydrocarbon gas and created an opportunity for using low-cost gas in enhanced oil recovery (EOR) projects. In addition to its availability in large quantities and at low cost, injecting produced gas back into the reservoir prevents flaring the gas, reducing environmental concerns associated with greenhouse gas emissions to the atmosphere. Furthermore, while CO2 has shown tremendous success as an EOR injectant in huff-and-puff operations in tight liquid-rich shales, the lack of sufficient pipeline infrastructure supplying low-cost CO2 as well as operational issues (e.g., corrosion) has forced field operators to consider other gas options, such as produced gas, to substitute for or mix with CO2.While limited, experimental and numerical studies conducted on produced gas huff-and-puff in unconventional resources have shown promising results and highlighted the great potential of this technique for enhanced oil recovery from ultra-tight shale resources. The objective of the current work is to investigate the feasibility of produced gas huff-and-puff operations in one of the major oil-producing shale formations in North America further by performing several flow experiments using various mixtures of hydrocarbon gases. Three reservoir-condition core-flooding experiments are carefully designed and executed on shale core plugs in the absence and presence of proppant-filled fractures. After establishing initial two-phase brine-oil conditions in the core samples, hydrocarbon gas is injected into the medium through a huff-and-puff approach. The cycle of injection-soaking-production is repeated multiple times in each experiment. The results show that the use of hydrocarbon gas in huff-and-puff operations has great potential similar to CO2 for enhanced oil recovery from tight shale rocks and can lead to remarkable oil recovery. The hydrocarbon gas mixture in the fracture penetrates the matrix due to pressure and concentration gradients during the injection and soaking periods and forces the oil to leave the matrix during the depressurization process. It is observed that the rate of oil production is high in the first cycle and decreases in subsequent cycles as the rate of mass transfer and the amount of oil remaining in the matrix decrease. The average oil production due to the cyclic gas injection process in an intact and fractured composite rock sample was more than 48 and 21%, respectively. The results show that even though the ultratight formations could be heavily fractured, a proper cyclic gas injection EOR scheme could potentially improve oil recovery from the shale oil reservoirs, significantly.

A novel correlation for modeling interfacial tension in binary mixtures of CH₄, CO₂, and N₂ + normal alkanes systems: Application to gas injection EOR process

The Enhanced Oil Recovery (EOR) has received significant attention in recent years by the cessation of primary production of several reservoirs and also the increasing global demand for energy. Miscible gas flooding is one of the most popular EOR techniques. Interfacial Tension (IFT) data plays an important role in determining Minimum Miscibility Pressure (MMP) as well as estimating the recovery performance of the EOR schemes, and the production potential of fractured reservoirs. CH₄, CO₂, and N₂ are the gases widely used for gas injection EOR practices. Normal alkanes can represent the real crude oil samples as they are their most abundant constituents. Acquiring knowledge about the IFT between vapor phase and n-alkanes can shed light on the governing mechanisms between the injected gas phase and the real crude oil in EOR projects. Experimental determination of IFT is often associated with the high cost and arduous and timely procedures. The theoretical works need expensive numerical and computational effort. Data-based methods can offer a promising alternative to compensate for the disadvantages of the mentioned methods. An extensive database including 606, 1131, and 469 data samples of IFT between normal n-alkanes and CH₄, CO₂, and N₂ was utilized in this study to develop predictive models. Proper input variables were analyzed and selected for modeling. The Group Method of Data Handling (GMDH) was used in this study. Separate models were developed for the three vapor phases. The Root Mean Square Errors (RMSE) of 1.24, 1.29, and 1.15 mN/m for respective CH₄, CO₂, and N₂ systems indicate the acceptable accuracy of the developed model. The models were compared with the models available in the literature. It was revealed that the proposed GMDH models provide superior predictions for a wide range of pressure and temperature. External validation was performed using a very recently published dataset to check for the generality of the proposed models. Finally, a systematic method was proposed to select the best predictive model based on the n-alkane type and operational parameters of pressure and temperature. The findings of this study can be utilized in designing and planning efficient EOR schemes.

Laboratory Investigation of Permeability Impairment Caused by Asphaltene Precipitation during Screening for Gas-Injection Enhanced Oil Recovery and Pressure Change in a Major Gulf of Mexico Field

Summary As part of studying miscible gas injection (GI) in a major field within the Green Canyon protraction area in the Gulf of Mexico (GOM), asphaltene-formation risk was identified as a key factor affecting a potential GI project. The industry has not conducted many experiments to quantify the effect of asphaltenes on reservoir and well performance under GI conditions. In this paper we discuss a novel laboratory test for evaluating the asphaltene effect on permeability. The goals of the study were to define the asphaltene-precipitation envelope using blends of reservoir fluid and injection gas, and measure permeability reduction caused by asphaltene precipitation in a core under GI. To properly analyze the effect of GI, a suite of fluid-characterization studies was conducted, including restored-oil samples, compositional analysis, constant composition expansion (CCE), and differential vaporization. Miscibility conditions were defined through slimtube-displacement tests. Gas solubility was determined through swelling tests complemented by asphaltene-onset-pressure (AOP) testing. The unique procedure was developed to estimate the effect of asphaltene deposition on core permeability. The 1-ft-long core was saturated with the live-oil and GI mixture at a pressure greater than the AOP, and then pressure was depleted to a pressure slightly greater than the bubblepoint. Several cycles of charging and depletion were conducted to mimic continuous flow of oil along the path of injected gas and thereby to observe the accumulation of asphaltene on the rock surface. The test results indicated that during this cyclic asphaltene-deposition process, the core permeability to the live mixture decreased in the first few cycles but appeared to stabilize after Cycle 5. The deposited asphaltenes were analyzed further through environmental scanning electron microscopy (ESEM), and their deposition was confirmed by mass balance before and after the tests. Finally, a relationship was established between permeability reduction and asphaltene precipitation. The results from the asphaltene-deposition experiment show that for the sample, fluids, and conditions used, permeability is impaired as asphaltene flocculates and begins to coat the grain surfaces. This impairment reaches a plateau at approximately 40% of the initial permeability. Distribution of asphaltene along the core was measured at the end by segmenting the core and conducting solvent extraction on each segment. Our recommendation is numerical modeling of these test results and using this model to forecast the magnitude of the permeability impairment in a reservoir setting during miscible GI.

A New Effective Multiwalled Carbon Nanotube-Foam System for Mobility Control

SummaryNanoparticles have improved a surfactant's ability to create long-lasting foam. Recent studies have widely recommended the use of silica nanoparticles to enhance foam stability. This paper presents an experimental investigation of a new and highly effective alpha olefin sulfonate (AOS)–multiwalled carbon nanotube (MWCNT) system for mobility control during gas enhanced oil recovery (EOR) operations.The new AOS–MWCNT system was evaluated for its foam stability at 150°F using a high-pressure view cell. The MWCNT was obtained as solid particles of aspect ratio up to 100 and silica nanoparticles of median size of 118 nm. The foam system was optimized for its maximum half-life by varying the concentration of the AOS and the nanotube from 0.2 to 1% and 250 to 1,000 ppm, respectively. Compatibility testing with salts was done as well. Coreflood experiments with 1.5-in.-diameter, 6-in.-long Berea sandstone cores were run to calculate the mobility reduction factor at 150°F. Nitrogen foam was injected into the core at 80% foam quality in the tertiary recovery mode, and the pressure drop across the core was measured. The formation brine had a salinity of 5 wt% sodium chloride (NaCl), and the foaming solutions were prepared with 2 wt% NaCl.The optimal concentrations of the AOS solution and the nanotubes for maximum foam stability were determined to be 0.5% and 500 ppm, respectively. The optimized AOS–MWCNT system yielded 60% greater nitrogen foam half-life (32 minutes) than an optimized AOS–silica system at 150°F. The foam half-life of a stand-alone 0.5% AOS solution was 7 minutes. In the presence of crude oil, the foam half-life decreased for all the tested systems. Coreflood experiments at 150°F showed a significant increase in the mobility reduction factor when the new AOS–MWCNT system was used as the foamer instead of stand-alone AOS or AOS–silica system. The new foaming system was stable through the duration of the experiment, yielding foam in the effluent samples. There was no formation damage observed. Salt tolerance for the MWCNT nanofluid was higher than the silica nanofluid.Foam needs to be stable for long periods of time to ensure effective mobility control during gas injection for EOR. This paper investigates a new highly effective AOS-multiwalled carbon nanotube system that outperforms the AOS–silica foaming systems in terms of foam stability and mobility control at 150°F.

Modified Peng-Robinson equation of state for CO2/hydrocarbon systems within nanopores

Phase behavior of confined fluid demonstrates significant deviation from that of bulk fluid because of the strong molecule-wall interaction and geometric constraint in confined space, resulting in the inapplicability of the classical cubic equation of state (EOS). The objective of this work is to modify the Peng-Robinson EOS (PR EOS) with respect to both the attractive parameter and the covolume term to reflect the impact of molecule-wall interaction and geometric constraint, respectively. The modified PR EOS is applied to compute the phase diagrams of CO2+n-C4H10 and CO2+n-C10H22 binary mixtures, CO2+n-C4H10+n-C10H22 ternary mixture, and CO2+Eagle Ford condensate in nanopores. In this work, correlations of both critical temperature and critical pressure shift with nanopore sizes are proposed to compute the confined attractive parameter and the confined covolume in the modified PR EOS. The proposed EOS model is validated by both the critical temperature and the critical pressure shift data collected from literature. Results demonstrate that confinement effect in nanopores impose an overall shrinkage to the two-phase diagrams of all the CO2-hydrocarbon systems. The upper dew-point pressure of the Eagle Ford condensate sample is calculated to be 2972.6 psi, with a suppression of 27.56% compared to the bulk value of 4103.6 psi. Moreover, the size of the two-phase region in the ternary diagram and the minimum miscibility pressure also decrease in confined space, which is in favor of the miscible gas injection enhanced oil recovery with a higher possibility of achieving first contact miscibility.

A unified intelligent model for estimating the (gas + n-alkane) interfacial tension based on the eXtreme gradient boosting (XGBoost) trees

The interfacial tension (IFT) between the injecting gas and host oil is a key parameter that affects the ultimate displacement efficiency and gas injection enhanced oil recovery (EOR) performance. The accurate characterization of the IFT between varying n-alkanes and injecting gases is crucial to obtaining deeper insight into the predominating mechanisms behind the interfacial behaviors of (gas + oil) systems, and in turn ensuring the optimal design of gas injection EOR projects. Laboratory measurement of the IFT usually requires expensive experimental apparatus, time-consuming operation procedure and cumbersome data deduction. This paper proposed the use of a novel supervised learning (SL) method, namely the eXtreme gradient boosting (XGBoost) trees, for the fast estimation of (gas + n-alkane) IFT. A unified estimation model was constructed for varying injecting gas species and n-alkanes based on a large database consisting of a number of 1561 data sets. Results showed that the unified model is capable of accurately reproducing the experimental IFT based on pressure, temperature, n-alkane molecular weight and gas composition. It was also demonstrated that the new model outperforms the multi-layer perceptron (MLP), support vector regression (SVR) and existing correlations in terms of accuracy and robustness. Furthermore, the permutation importance (PI) was applied to quantify the importance of each input feature to the IFT, which concluded that the ranking of features in terms of decreasing importance to the (gas + n-alkane) IFT are: pressure ≫ n-alkane molecular weight > gas composition > temperature.

Evaluating foam stability using tailored water chemistry for gas mobility control applications

Generating in-situ foam is regarded as one of the most promising techniques to overcome gas mobility issues and improve sweep efficiency in both miscible and immiscible gas injection enhanced oil recovery (EOR) processes. Gravity override, viscous fingering and channeling through permeable zones are the major limiting factors that can impair the efficiency of gas floods, mainly due to low density and viscosity of the gas relative to reservoir fluids. Generating strong and stable foam while injecting gas is one way to achieve in-depth conformance improvement in the reservoir.In this study, a tailored water chemistry (formulated low salinity water) has been evaluated in comparison to using typical high salinity injection water (i.e. seawater) and deionized water in surfactant solutions to determine its overall effect on the produced foam. Using bulk foam tests, foam rheology apparatus and microfluidics device, the foam stabilization factors were analyzed and quantified by measuring the foam-life over time of different surfactants in varying salinity water solutions. In addition, the foam rheological properties were measured under high pressure. The microfluidics device was also used to examine the generated foam strength in porous media.The results from laboratory experiments clearly demonstrated that the use of tailored water chemistry can improve the stability of produced foam when compared to both high salinity water and deionized water. Low salinity tailored water chemistry solutions resulted in a longer lasting foam, by almost 1.8–3.0 times depending on the surfactant type. The foam rheology results showed that the produced foams with the tailored low salinity water are of higher apparent viscosity when compared to those obtained with deionized water. Both longer foam-life and higher apparent viscosity are indicative of better, stronger and more stable foam. The higher resistance to gas flow was observed in porous media with foams generated using the low salinity tailored water chemistry solutions when compared to those foams obtained with deionized water and high salinity water.This experimental study, for the first time, demonstrated substantial improvements in the foam stability by using a tailored water chemistry aqueous solution. Such huge foam stabilization improvements obtained with tailored water chemistry has the promising potential to increase the apparent viscosity of injected gas and subsequently more effectively mitigate gas mobility issues encountered in EOR applications.

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.

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

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

Huff ‘n’ Puff EOR Proves Effective in Gas-Condensate Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTEC-2019-987-MS, “Gas-Injection EOR in Eagle Ford Shale Gas-Condensate Reservoirs,” by Reza Ganjdanesh, SPE, Wei Yu, and Mauricio Xavier Fiallos, SPE, The University of Texas at Austin; Erich Kerr, SPE, EP Energy; Kamy Sepehrnoori, SPE, The University of Texas at Austin; and Raymond Ambrose, SPE, EP Energy, prepared for the 2019 Unconventional Resources Technology Conference, Denver, 22–24 July. The paper has not been peer•reviewed. Copyright 2019 Unconventional Resources Technology Conference. Reproduced by permission. As the pressure drops below the dewpoint in an unconventional gas-condensate reservoir, the liquid drops out of the gas phase and forms an oil phase in the matrix and fracture. The volume of the oil phase formed in the matrix mostly stays below the residual oil saturation. The gas huff ‘n’ puff process has demonstrated potential in improving recovery from tight oil reservoirs. The objective of the study described in this paper was to investigate the feasibility of huff ‘n’ puff enhanced oil recovery (EOR) in a•gas-condensate reservoir. Introduction Compositional analyses of fluid samples, taken from early production of three wells located a few miles apart from each other in Eagle Ford, were used to build the black-oil, volatile-oil, and gas-condensate fluid models. The produced field gas was selected as the only viable option for injection. Phase-Behavior Models The phase-behavior models were built for black-oil, volatile-oil, and gas-condensate wells on the basis of pressure/volume/temperature reports from bottomhole samples. The reservoir fluids were built by combining mathematically the oil and gas fluids from separators. The pseudocomponents were characterized from the detailed compositional laboratory analysis. The Peng-Robinson equation of state with the temperature-independent volume correction was used for phase-behavior modeling. The Lohrenz-Bray-Clark viscosity model was applied in calculating the phase viscosities. The condensate/gas ratio for the gas condensate fluid is 147 STB/MMscf, which is a rich gas-condensate fluid. Comparative Study of Gas Injection To compare the performance of huff ‘n’ puff gas injection in different fluid types, single-well simulation models were built for each fluid type. Several well models of 4,500 ft in length with a fracture spacing of 50 ft were built using a compositional simulator. The reservoir thickness was 130 ft. The hydraulic fractures were set up using the embedded discrete fracture model (EDFM) preprocessor. Each single-well model was history matched using the production data. Because the history-matching solutions were nonunique, the rate and pressure transient analysis for each well were used to limit the results to the realistic solution spaces. The history-matched fracture half-length varied between 50 and 175 ft and the fracture height varied between 50 and 90 ft. The fracture conductivity ranged between 3–30 md-ft. The history-matched models were used to investigate the performance of gas-injection EOR for all fluid types. The field gas was injected for 10 cycles, and the cumulative produced oil using huff ‘n’ puff was compared to one without gas injection. The incremental oil recovery for the nine studied black-oil cases varied between 30 and 40%. The incremental oil recovery was less than 10% for three volatile-cases and 15 to 20% for 13 gas-condensate ones.

Optimizing CO2- and Field-Gas-Injection EOR in Unconventional Reservoirs Using the Fast-Marching Method

SummaryRecently, there has been an increasing interest in enhanced oil recovery (EOR) from shale-oil reservoirs, including injection of carbon dioxide (CO2) and field gas. For the performance assessment and optimization of CO2- and field-gas-injection processes, compositional simulation is a powerful and versatile tool because of the capability to incorporate reservoir heterogeneity, complex fracture geometry, and multiphase and multicomponent effects in nanoporous rocks. However, flow simulation accounting for such complex physics can be computationally expensive. In particular, field-scale optimization studies requiring a large number of high-resolution compositional simulations can be challenging and sometimes computationally prohibitive. In this paper, we present a rapid and efficient approach for the optimization of CO2- and field-gas-injection EOR in unconventional reservoirs using a fast-marching-method (FMM) -based flow simulation.The FMM-based simulation uses the concept of diffusive time of flight (DTOF). The DTOF is a representation of the travel time of pressure-front propagation and accounts for geological heterogeneity, well architecture, and complex fracture geometry. The DTOF can be efficiently obtained by solving the Eikonal equation using the FMM. The 3D flow equation is then transformed into an equivalent 1D equation using the DTOF as a spatial coordinate, leading to orders of magnitude faster computation for high-resolution and compositional models as compared to full 3D simulations. The speed of computation enables using robust population-based optimization techniques such as genetic- or evolutionary-based algorithms that typically require a large number of simulation runs to optimize the operational and process parameters.We demonstrate the efficiency and robustness of our proposed approach using synthetic and field-scale examples. We first validate the FMM-based simulation approach using an example of CO2 huff ‘n’ puff for a synthetic heterogeneous dual-porosity model with a multistage hydraulically fractured well. Next, we present a field-scale optimization of operating strategies for gas-injection EOR in the Eagle Ford Formation. The rapid computation of the FMM-based approach enabled a comprehensive evaluation of the EOR project, including sensitivity studies, parameter-importance analysis, and optimal operating strategies using high-resolution geologic models.

Gas Injection Evaluated for EOR in Organic-Rich Shale

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190323, “Gas Injection for EOR in Organic-Rich Shale: Part I—Operational Philosophy,” and paper URTeC 2903026, “Gas Injection for EOR in Organic-Rich Shale: Part II—Mechanisms of Recovery,” by Francisco D. Tovar, SPE, Maria A. Barrufet, SPE, and David S. Schechter, SPE, Texas A&M University. Paper SPE 190323 was prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April; paper URTeC 2903026 was prepared for the 2018 Unconventional Resources Technology Conference, Houston, 23–25 July. The papers have not been peer reviewed. This synopsis contains elements of two papers. In the first, the authors describe their comprehensive experimental evaluation of gas injection for enhanced oil recovery (EOR) in organic-rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic-rich shale reservoirs, whereas tests in resaturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slimtube minimum miscibility pressure (MMP) on recovery. In the second paper, the authors focus on the effect of fluid transport in organic-rich shale on recovery mechanisms under gas injection, and provide the rationale behind the proposed operational philosophy. Part I—Operational Philosophy Background. The notion that industry experience in the implementation of gas-injection methods in conventional reservoirs can be applied to unconventional reservoirs is a problematic one. A lack of understanding exists regarding the effect of contrast in mechanisms at the pore scale on the implementation of a gas-injection process. Experimental research so far, though encouraging, suffers from serious limitations. Also, there still is a significant lack of understanding of the mechanisms of recovery under gas injection for enhanced recovery in organic-rich shales. In this paper, the authors base their investigation on experimental observations made in core plugs extracted from the reservoir interval, and show the development of a coreholder configuration that enables the physical simulation of the injection of gas through a hydraulic fracture in the laboratory. Then, this configuration is used to perform coreflooding experiments at the pressure and temperature conditions seen in the reservoir. Detailed descriptions and results of the experimental work are provided in the complete paper. Summary. The authors begin by demonstrating that direct gas injection through an organic-rich shale matrix is not possible in a reasonable time frame. That discovery triggered the construction of specialized equipment and the development of a novel injection technique that resembles that of injection through hydraulic fractures. Using that technique, nine experiments injecting CO2 in preserved organic-rich shale cores were performed. Only three of those experiments recovered a significant volume of oil, and the recovery factor was estimated to be between 18 and 62% of the initial crude-oil volume in the cores. This demonstrated CO2 can be used to extract the naturally occurring oil in core plugs with extremely low permeability, where gas cannot be injected directly. Also, by coupling the coreflooding equipment developed in-house to a computed-tomography (CT)-scanner, this technology proved able to track the changes in density resulting from the mass exchange between CO2 and crude oil.

A Review of Gas Injection in Shale Reservoirs: Enhanced Oil/Gas Recovery Approaches and Greenhouse Gas Control

Shale oil and gas resources contribute significantly to the energy production in the U.S. Greenhouse gas emissions come from combustion of fossil fuels from potential sources of power plants, oil refineries, and flaring or venting of produced gas (primarily methane) in oilfields. Economic utilization of greenhouse gases in shale reservoirs not only increases oil or gas recovery, but also contributes to CO2 sequestration. In this paper, the feasibility and efficiency of gas injection approaches, including huff-n-puff injection and gas flooding in shale oil/gas/condensate reservoirs are discussed based on the results of in-situ pilots, and experimental and simulation studies. In each section, one type of shale reservoir is discussed, with the following aspects covered: (1) Experimental and simulation results for different gas injection approaches; (2) mechanisms of different gas injection approaches; and (3) field pilots for gas injection enhanced oil recovery (EOR) and enhanced gas recovery (EGR). Based on the experimental and simulation studies, as well as some successful field trials, gas injection is deemed as a potential approach for EOR and EGR in shale reservoirs. The enhanced recovery factor varies for different experiments with different rock/fluid properties or models incorporating different effects and shale complexities. Based on the simulation studies and successful field pilots, CO2 could be successfully captured in shale gas reservoirs through gas injection and huff-n-puff regimes. The status of flaring gas emissions in oilfields and the outlook of economic utilization of greenhouse gases for enhanced oil or gas recovery and CO2 storage were given in the last section. The storage capacity varies in different simulation studies and is associated with well design, gas injection scheme and operation parameters, gas adsorption, molecular diffusion, and the modelling approaches.

Viability of Gas-Injection EOR in Eagle Ford Shale Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191673, “Dynamic Data Analysis With New Automated Work Flows for Enhanced Formation Evaluation,” by Safian Atan, SPE, Arashi Ajayi, Matt Honarpour, Edward Turek, SPE, Eric Dillenbeck, and Cheryl Mock, BHP, and Mahmood Ahmadi and Carlos Pereira, MI3 Petroleum Engineering, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. Gas-injection huff ’n’ puff enhanced-oil-recovery (EOR) techniques have the potential to improve liquid hydrocarbon recovery in ultratight, unconventional reservoirs. This paper studies the technical and economic viability of this EOR technique in Eagle Ford shale reservoirs using natural gas injection, generally after some period of primary depletion, typically through long, hydraulically fractured horizontal-reach wells. Reservoir-Analysis Work Flow Model Description. A compositional, fine-scale, dual-porosity, dual-permeability, symmetry-element numerical model was used in this study to model the current primary depletion and the EOR huff ’n’ puff process. In this study, the element of symmetry, which represents the bottom half of a cluster within a fracturing stage, is being extended to include three wells to allow the investigation of the effect of interference and containment on pad-level cyclic-gas-injection deployment. Production and injection of the entire well come from all active stages in each well, with equal weighting. The production and the injection for each cluster in every well are calculated proportionally by use of these assumptions. Model Input. The complete paper describes the critical input for the numerical model, including fracture half-length and fracture height, shape factor, absolute and relative permeability, and pressure/volume/temperature (PVT). History-Matching Work Flow. Because the history-matching solution is known to be highly nonunique, a comprehensive probabilistic approach was used to identify the realistic solution space. To facilitate this process, the authors used a three-step approach: Identify the solution space through parametric study. Perform combinatorial analysis of predetermined variables and understand available solutions within the solution space. Fine-tune history matching to identify the correct combination of parameters for probable solutions. Characterizing the Performance of Cyclic Natural-Gas Injection The compositional fluid-flow analysis of the combined sample of the separator liquid and gas at reservoir conditions indicated a volatile oil in the reservoir. To evaluate the phase behavior of the mixture, the original oil and the gas supplied for injection purposes were mixed at different ratios. For each mixture, the calibrated equation of state (EOS) is used to evaluate the resulting phase diagram and fluid properties by modeling a constant-composition-expansion experiment at reservoir conditions. The 1979 Peng-Robinson EOS with nine components was used to model the PVT changes resulting from the composition changes related to each injection ratio. As the composition changes, the phase behavior and the fluid properties also change. The fluid system in the reservoir gradually changed from a volatile oil to a gas condensate. Results show that when injected-gas makeup is 20% or greater, the phase behavior changes from volatile oil to gas condensate. When the mixture consists of more than 70% injected gas, at any pressure below 6,000 psi, there is a possibility that condensation can occur.

Modeling of Nanoparticle-Stabilized CO2 Foam Enhanced Oil Recovery

Summary Previous experimental studies show that “nanoparticle-stabilized” supercritical carbon dioxide (CO2) foams (NP-stabilized CO2 foams or NP CO2 foams in this paper) can be applied as an alternative to surfactant foams, to reduce CO2 mobility in gas-injection enhanced oil recovery (EOR). The NPs, if chosen correctly, can be effective foam stabilizers attached at the fluid interface in a wide range of physicochemical conditions. By using NP CO2 foam experiments available in the literature, this study investigates the applicability of NP foams for mobility control and, thus, improved sweep efficiency. This study consists of two tasks: (1) presenting how a population-balance mechanistic foam model can be used to fit experimental data and determine required model parameters and (2) examining sweep efficiency in a condition resembling Lisama Field (a five-spot pattern with four producers and one injector in the middle), by using relevant gas mobility-reduction factors (MRFs) derived from the mechanistic-modeling technique. The field-scale simulations are conducted with Computer Modeling Group (CMG) software, contrasting NP and surfactant foams (in both dry and wet foam-injection conditions) to a gas-only injection and a gas/water coinjection (no foam). The results show how the model can successfully reproduce coreflood experimental data, creating three different foam states (weak foam, strong foam, and intermediate) and two steady-state strong-foam regimes (high quality and low quality). When the gas-phase MRFs, ranging up to 10 from the model fit, are applied in the field-scale simulations, the use of NPs improves oil recovery compared with a gas/water coinjection, but not as efficiently as a successful surfactant foam injection does. This implies that, although NP-stabilized foams do provide some benefits, there still seems to be some room to improve the stability and the strength of resulting foams.

Shale EOR Works, But Will It Make a Difference?

When EOG Resources disclosed that it had found a way to get from 30 to 70% more oil from Eagle Ford shale wells, it set off a race among competitors looking for a low-cost way to add reserves by injecting natural gas. It has been little noticed because few companies have said anything publicly about it. But university researchers and service companies are seeing widespread interest from companies that are trying to figure out how EOG uses gas injection to increase production and whether those gains can be sustained long enough to add reserves. Research interest in gas injection enhanced oil recovery (EOR) persuaded David Schechter, a petroleum engineering professor at Texas A&M University, to equip his lab that has been used to test carbon dioxide (CO2) for EOR to safely observe how natural gas affects reservoir rock. “Basically everyone with a substantial acreage position is working on unconventional oil EOR now,” said Schechter. “This is the name of the game. Everybody is talking about EOR and pumping money into trials of EOR,” said Deepak Devegowda, an associate engineering professor at the University of Oklahoma. The question facing EOG and its competitors is, can they take a method that improves results from some of its best wells, and use it on a far larger scale to increase overall recoveries in unconventional formations where more than 90% of the resource is left behind. Companies would like to understand and simulate it and, most importantly, they are looking for clues on how EOG did it. “A whole bunch of folks are watching what other people are doing,” Devegowda said. Companies and researchers are using statistical analysis to determine patterns in production data filed with the Texas Railroad Commission to try to figure out how EOG is using natural gas injection. Among those looking is Todd Hoffman, an associate professor from Montana State, who was initially skeptical of EOG’s claims. After studying the data, Hoffman said that EOG clearly is “seeing huge increases in added oil production.” He is now working on a paper based on the disclosures. As for how he figured out which of EOG’s more than 7,000 Eagle Ford wells to study, he said, “I really had to dig around to find it. I talked to a number of companies planning pilots, doing pilots, in the planning stage, trying to do the same thing,” he said.

Foam Diversion in Heterogeneous Reservoirs: Effect of Permeability and Injection Method

SummaryFoam can divert flow from higher- to lower-permeability layers and thereby improve the injection profile in gas-injection enhanced oil recovery (EOR). This paper compares two methods of foam injection, surfactant-alternating-gas (SAG) and coinjection of gas and surfactant solution, in their abilities to improve injection profiles in heterogeneous reservoirs. We examine the effects of these two injection methods on diversion by use of fractional-flow modeling. The foam-model parameters for four sandstone formations ranging in permeability from 6 to 1,900 md presented by Kapetas et al. (2015) are used to represent a hypothetical reservoir containing four noncommunicating layers.Permeability affects both the mobility reduction of wet foam in the low-quality-foam regime and the limiting capillary pressure at which foam collapses. The effectiveness of diversion varies greatly with the injection method. In a SAG process, diversion of the first slug of gas depends on foam behavior at very-high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. (2015). Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This favors diversion away from high-permeability layers that receive a large surfactant slug. However, there is an optimum surfactant-slug size: Too little surfactant and diversion from high-permeability layers is not effective, whereas with too much, mobility is reduced in low-permeability layers. For a SAG process, injectivity and diversion depend critically on whether foam collapses completely at irreducible water saturation.In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with injection time. Injectivity is extremely poor with foam injection for these extremely strong foams, but for some SAG foam processes with effective diversion it is better than injectivity in a waterflood.