Miscible Gas Research Articles

Technology Focus: EOR Modeling (January 2020)

Technology Focus The bulk of the literature on enhanced oil recovery (EOR) from the past year has been devoted to an improved understanding of trends started more than a decade ago with physical and numerical modeling. A quick review of the basics will be helpful for putting these developments in perspective. The concept of displacement in an EOR method requires bringing the mobility ratio of displacing fluid to that of displaced oil under unity [Kw µ o / Ko µw less than 1; Ko, Kw being relative permeabilities of displaced oil and displacing fluid (e.g., water), respectively, and µ o, µw being their respective viscosities], and increasing sweep efficiency (Es) of the displacement process. Various established EOR methods try to accomplish this in different ways, depending on the formation and oil types, aiming to keep costs and environmental impact down while obtaining high and quick recovery. Thus, polymers or foams have been used traditionally to increase viscosity of displacing fluids (µw). To reduce Kw/Ko, surfactant; alkaline; microbes, which create in-situ surfactants; or low-salinity water, which changes wettability to water, were used. Steam or hot water have also been used to reduce both Kw and µo. Miscible gas or solvent displacements were used to attack µo. Quite frequently, a combination of these mechanisms has been applied, alkaline/surfactant/ polymer being a good example. Similarly, to address improvement in sweep, blocking agents such as polymers, microgels, or microbes, or a combination of a couple of these mechanisms, have been applied. While the underlying mechanisms remain the same, major developments in EOR in recent years center on the use of engineered water or nanoparticles to reduce Kw, on the experimental development of chemicals that are less susceptible to high-temperature and high-salinity environments, or on the use of novel computational techniques and machine learning to design and monitor the flood operations better. The literature of the last year is an important reflection of that evolution, as the selected papers reflect. Recommended additional reading at OnePetro: www.onepetro.org. SPE 195553 Investigation of Pore-Scale Mechanisms of Microbial Enhanced Oil Recovery Using Microfluidics by Calvin Gaol, Clausthal University of Technology, et al. SPE 192110 Polymers and Their Limits in Temperature, Salinity, and Hardness: Theory and Practice by Eric Delamaide, IFP Technologies Canada, et al. SPE 192651 Performance Evaluation and Field Trial of Self-Adaptive Microgel Flooding Technology by Zhe Sun, China National Offshore Oil Corporation, et al.

Study of the impact of injection parameters on the performance of miscible sour gas injection for enhanced oil recovery

Sour gas reservoirs have faced critics for environmental concerns and hazards, necessitating a novel outlook to how the produced sour gases could be either utilized or carefully disposed. Over the years of research and practice, several methods of sour gas processing and utilization have been developed, from the solid storage of sulfur to reinjecting the sour gas into producing or depleted light oil reservoir for miscible flooding enhanced oil recovery. This paper seeks to investigate the impact of injection parameters on the performance of sour gas injection for enhance oil recovery. In designing a miscible gas flooding project, empirical correlations are used and the key parameter which impacts the phase behavior is identified to be the minimum miscibility pressure (MMP). A compositional simulator was utilized in this research work to study the effect of injection parameters such as minimum miscibility pressure, acid gas concentration, injection pressure and injection rate on the performance of miscible sour gas injection for enhanced oil recovery. The findings showed that methane concentration had a significant impact on the MMP of the process. Additionally, an increase in acid gas concentration decreases the MMP of the process as a result of an increase in gas viscosity, consequently extending the plateau period resulting in late gas breakthrough and increased overall recovery of the process.

Eagle Ford Huff ‘n’ Puff Gas-Injection Pilot: Comparison of Reservoir-Simulation, Material Balance, and Real Performance of the Pilot Well

Summary In this study we compare real data from an Eagle Ford Shale huff ‘n’ puff (H&P) gas-injection pilot with reservoir simulation and tank material-balance calculations. The comparison is good and supports the conclusion that oil recovery from the Eagle Ford (and likely other shales) can be increased significantly using H&P. For H&P to work, the injected gas and the in-situ oil in the shale must be contained vertically and laterally following hydraulic fracturing. Containment is critical for the success of H&P. Containment implies that the injected gas flows into the hydraulic fractures, penetrates the tight matrix, and does not escape or leak outside the target stimulated reservoir volume (SRV). Vertical and lateral containment exists in the Eagle Ford as demonstrated previously (Ramirez and Aguilera 2016) with an upside-down distribution of fluids: Natural gas is at the bottom of the structure, condensate in the middle, and oil at the top. Two different matching and forecasting approaches are used in this study: reservoir simulation and tank-material-balance calculations. The results show a good history match of primary recovery and secondary recovery by H&P in the pilot well. The history match is good in the case of both reservoir simulation and tank material-balance calculations. Once a match is obtained, the simulation and material balance are used to forecast secondary recovery over a period of 10 years with sustained H&P injection of dry gas. The results indicate that dry-gas H&P can increase oil recovery from the Eagle Ford Shale significantly. Under favorable conditions, oil recovery can be doubled and even tripled over time compared with the primary recovery. The addition of heavier ends to the H&P gas injection can increase oil recovery even more, putting it on par with recoveries in conventional reservoirs. The benefit of H&P occurs in the case of both immiscible and miscible gas injection. The H&P benefits can likely be also obtained in other shale reservoirs with upside-down containment of dry gas, condensate, and oil. The novelty of this work is the combined use of reservoir simulation and tank material-balance calculations to match the performance of an H&P gas-injection pilot in the Eagle Ford Shale of Texas. We conclude that oil recoveries can be increased significantly by H&P.

A Multiphase, Multicomponent Reservoir-Simulation Framework for Miscible Gas and Steam Coinjection

SummaryThe solvent thermal resource innovation process (STRIP), a downhole steam-generation technology, has the capacity to show improved recovery factors with a significantly reduced environmental footprint compared with traditional thermal-enhanced-oil-recovery (TEOR) methods, most notably by delivering all the combustion heat to the pay zone. In this effort, a quarter-symmetry inverse-five-spot model and a multiphase, multicomponent reservoir-simulation framework were used to simulate the STRIP technology. Commercial simulators such as STARS - Thermal and Advanced Processes Reservoir Simulator [Computer Modelling Group Ltd. (CMG), Calgary, Alberta, Canada; CMG 2015b] often use the K-value approach to simulate TEOR. However, the method cannot simulate STRIP's carbon dioxide (CO2) and steam coinjection because the K-value method does not consider miscible gas injection. On the other hand, CMG's GEM - Compositional and Unconventional Simulator (CMG 2015a) includes the effects of miscible gases but does not provide comprehensive support for steam-injection processes, which are better handled by STARS. The novel simulation framework developed here leverages and combines the individual strengths of STARS (thermal features) and GEM (compositional features). In this framework, STARS simulated steam injection (but cannot directly simulate the effects of CO2) and was the governing model that synchronized temperature, pressure, and phase saturations for two parallel iterations of the GEM models (GEM-1 and GEM-2) at each timestep. Immiscible methane (CH4) was added to GEM models to maintain gas saturations equivalent to the STARS model. GEM-1 simulated hot-water and CH4 injection, but at increased rates to yield a pressure field and gas saturations equivalent to STARS. A final run of GEM-1 injected both CO2 and hot water and demonstrated the expected increase in oil production. Calibrated injection rates from GEM-1 were specified in GEM-2 to ensure equivalence of the pressure field. Next, the GEM-2 model also simulated hot-water and CH4 injection, but matched both water and oil productions along with oil saturations from the final GEM-1 run by altering relative permeabilities. Finally, the updated relative permeabilities were fed back to STARS, and iteration proceeded. Results from this framework were verified against a STARS steam-injection simulation. Finally, when considering coinjection of CO2, STRIP's superior performance was demonstrated through increased oil recovery and a lower steam/oil ratio (SOR).

A novel method for application of nanoparticles as direct asphaltene inhibitors during miscible CO2 injection

Asphaltene precipitation is one of the main technical challenges during the miscible gas injection. The asphaltene may deposit on the rock surface and it may change the reservoir wettability and reduces permeability. This paper focused on the asphaltene precipitation by liquid-free asphaltene inhibitors at reservoir conditions. The Fe3O4 and Al2O3 nanoparticles were used as direct asphaltene inhibitors (DAI) during CO2 injection. The cloud point pressures were measured to ensure that the CO2/nanoparticles mixtures are in single-phase conditions. After that, the vanishing interfacial tension technique was considered to evaluate the effect of DAI on minimum miscibility pressure. Moreover, the asphaltene precipitation during CO2/nanoparticles injection was studied for both volatile and intermediate live oils at reservoir conditions for DAI concentration varied from 500 to 3000 ppm. The results showed that the DAI can reduce the amounts of asphaltene precipitation during miscible CO2/nanoparticles injection at reservoir conditions. In addition, the CO2/nanoparticles injection reduced the asphaltene precipitation in comparison to pure CO2 injection. Also, the mixtures containing Fe3O4 can provide more performance than Al2O3 solutions, so the effect of solubility is more dominant than the aggregation impact during DAI injection.

Enhanced Recovery Technologies for Unconventional Oil Reservoirs

Management Unconventional resources have transformed the landscape of the oil and gas industry. The primary oil recovery factor ranges from 2–8% for the various shale plays throughout the US. Hence, it is imperative to develop the vast potential of unconventional reservoirs and increase the recovery factors beyond primary depletion by implementing IOR/EOR methods. This article describes the role of effective reservoir management and summarizes the detailed review of the advances in IOR/EOR technologies applied to unconventional oil reservoirs, as performed by the Energy Industry Partnership Team (EIP) at the University of Houston (Balasubramanian et al. 2018). That review•included: A thorough review of the pertinent published literature on IOR/EOR Results of EOR application to unconventionals shared by various operators in their investor presentations and from press reports Classifying IOR/EOR studies as laboratory experiments, numerical modeling, and field laboratory trials•(pilots) Analysis of field trials based on the representative shale plays. Most studies performed for the application of EOR technologies to unconventional oil reservoirs have been limited to experimental investigations and numerical simulation studies. The research revealed that miscible gas injection (produced field gases, CO2, etc.) is the most promising method among the EOR techniques, including miscible gas, waterflooding, surfactant, chemical, and polymer. Experimental studies showed the following: CO2 injection had the highest potential of improved recovery in unconventionals followed by produced gas injection. Surfactant injection showed the next best potential to increase oil recovery by altering the wettability of rock in laboratory experiments. The produced field gas injection pilots showed that sufficient injectivity was achieved mainly due to the injection-induced fractures and did not exhibit any significant effect of diffusion. Conformance control remains a big challenge due to the channeling of the gas through the fractures. Produced field gas injection pilots in the Eagle Ford formation have demonstrated the greatest success in increasing oil recovery. Many inconsistencies exist between laboratory investigations and field trials that need reconciliation and further research to bridge the gap. This methodical study elicits the learnings and challenges from the application of different IOR/EOR technologies to unconventionals at various scales (micro to macro to field scale). In addition, ideas for future research are recommended to improve the understanding of the complex mechanisms of EOR in unconventional oil reservoirs. Unconventional resources have changed the landscape of oil and gas industry in the US and the world. Oil production from unconventional tight oil reservoirs have accounted for more than 50% of total oil production in the US in the recent years. Todd et al. reported that unconventional oil reservoirs contributed to more than a 4 million•B/D increase in production between 2011 and•2014.

The Influence of the Type of Oil Model During the Displacement of Light Oil by Gas on Their Miscibility

The application of degassed oil instead of recombined oil model for a slim tube technique was investigated. It is found that the use of degassed oil is not recommended for modeling and studying of gas and oil miscibility under typical conditions of Western Siberia deposits. The previously estimated miscibility of light oil and associated gas was confirmed in case of application of recombined oil model or degassed oil at displacement from a slim tube. This occurs because of a gradual transition from the mode of immiscible displacement to the mode of limited-mixing displacement of oil and further to the mode of complete mixing as a result of the mass exchange of light oil and associated gas.

Lattice Boltzmann method for miscible gases: A forcing-term approach.

A lattice Boltzmann method for miscible gases is presented. In this model, the standard lattice Boltzmann method is employed for each species composing the mixture. Diffusion interaction among species is taken into account by means of a force derived from kinetic theory of gases. Transport coefficients expressions are recovered from the kinetic theory. Species with dissimilar molar masses are simulated by also introducing a force. Finally, mixing dynamics is recovered as shown in different applications: an equimolar counterdiffusion case, Loschmidt's tube experiment, and an opposed jets flow simulation. Since collision is not altered, the present method can easily be introduced in any other lattice Boltzmann algorithms.

Enhanced Method-of-Characteristics Approach for Determination of Minimum Miscibility Pressure in Displacements with Bifurcated Phase Behavior

Determination of minimum miscibility pressure (MMP) is an imperative component of optimally designing miscible gas injection processes. Semianalytical method of characteristics (MOC) is superior to...

Laboratory Investigation Targets EOR Techniques for Organic-Rich Shales

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2890074, “Laboratory Investigation of EOR Techniques for Organic-Rich Shales in the Permian Basin,” by Shunhua Liu, SPE, Vinay Sahni, and Jiasen Tan, SPE, Occidental Oil and Gas, and Derek Beckett and Tuan Vo, CoreLab, prepared for presentation at the 2018 Unconventional Resources Technology Conference, Houston, 23–25 July. The paper has not been peer reviewed. Commercial production from light oil, organic-rich shales in the Permian Basin has largely come from a solution-gas-drive recovery mechanism as a result of horizontal drilling and multistage hydraulic fracturing. These onshore, capital-intensive developments feature steep production declines and low expected ultimate recoveries. This paper involved laboratory experiments introducing miscible gases into core samples to investigate enhanced oil recovery (EOR) mechanisms for Permian Basin shales to provide information to design field tests for a huff ’n’ puff (HNP) recovery process. Introduction The average recovery factor in the un-conventional resources is typically less than 10% with very steep decline rates, indicating enormous potential for EOR. In recent years, research efforts and field pilots of unconventional EOR have targeted the Bakken and Eagle Ford shales. Most focused on miscible-gas (either CO2 or produced gas) injection, while others investigated water-based chemical injection. This paper provides EOR fluid and core analyses in Permian Basin organic-rich shale, an unconventional hydrocarbon growth play with different geological, rock, and fluid properties from those of the Bakken and Eagle Ford plays. The experimental results from this paper were used to calibrate the operator’s unconventional EOR reservoir simulation and field pilot design. Fluid Experiments Fluid properties such as equation-of-state (EOS) and minimum miscibility pressure (MMP) are extremely important because they are the fundamental designing parameters for any gas EOR project. In this study, oil and gas samples were collected in the well from perforations inside the Wolfcamp formation of the Permian organic-rich shale. A gas/oil ratio (GOR) of 1230 scf/bbl was chosen to recombine the separator oil and gas on the basis of observed solution GOR values before any increase caused by the flowing bottomhole pressure falling below the bubblepoint pressure. The pressure/volume/ temperature (PVT) laboratory-testing program consisted of a constant-composition-expansion (CCE) test and a series of swelling tests with CO2. Using the recombined reservoir fluid (with a GOR of 1230 scf/bbl), a CCE test was performed at the reservoir temperature of 162°F to measure the bubblepoint pressure, single-phase oil density, and compressibility. The swelling test results were performed to tune an EOS to be used to calculate oil properties with increasing CO2 concentration during a CO2 flood. EOS Modeling An EOS model was generated to match the CCE data, viscosity data, and CO2 swelling-test data. To use this EOS for CO2 reservoir simulation, the reported system components were grouped, but the CO2 component was left ungrouped. Otherwise, it would be grouped with component C2. The minor component N2 was grouped with C1. All C4s and C5 were grouped together, as were the C6s. The C7+ components were divided into three pseudocomponents.

Effects of oligomers dissolved in CO2 or associated gas on IFT and miscibility pressure with a gas-light crude oil system

The solubility of an oligomer in a supercritical gas solvent (e.g. CO2 or associated gas (AG) mixture) and the subsequent effects on the phase behaviour, interfacial tension (IFT) and miscibility pressure of the in-situ oil/oligomer-thickened gas system at a molecular level are crucial to understanding and designing a thickened miscible gas injection (MGI) process. We have conducted cloud point pressure measurements, which revealed that the phase behaviour of P-1-D-thickened CO2 would follow a UCST (upper critical solution temperature) trend while P-1-D-thickened AG mixture would lie close to a LCST (lower critical solution temperature) behaviour. Moreover, our measured equilibrium IFTs of crude oil/P-1-D-thickened CO2 system and crude oil/PVEE-thickened CO2 system were found to be slightly lower than those of the crude oil/CO2 system. This results in a slight reduction in the MMP (minimum miscibility pressure) and considerable reduction in the first contact miscibility pressure (Pmax). We found the dissolution of P-1-D in the AG mixture to cause an increase in the equilibrium IFT for the crude oil/P-1-D-thickened AG mixture system, resulting in an increase in both of the MMP and Pmax. This indicates that the dissolution of an oligomer may have a considerable effect on the crude oil/thickened gas IFT behaviour at a pressure close to the cloud point pressure.

Determination of the minimum miscibility pressure using the eclipse 300 simulator and compare it with the laboratory results

Gas miscibility injection is one of the most effective ways to increase oil extraction. The Minimum miscibility pressure is an important parameter in the miscibility gas injection processes, which is very important for determining the type of injection gas and the design of injection facilities.1 In the industry, the minimum miscibility pressure is usually measured by slim tube, which is a relatively costly and time-consuming test, and may sometimes be counterproductive due to its specific problems, in spite of the high cost and time consuming costs. In this study, using the eclipse 300 simulator, the minimum miscibility pressure was calculated for 11 oil reservoirs with different injectable gases in the process of gas miscibility injection after simulation and compared with the experimental results of these 11 reservoirs and by calculating error percentage, the applicability of this method has been investigated.

Comparison of base gas replacement using nitrogen, flue gas and air during underground natural gas storage in a depleted gas reservoir

ABSTRACT Base gas is considered as an important factor in the storage operation as it remains permanently in the reservoir and maintains the reservoir pressure along the production cycle. Depending on the reservoir under consideration, base gas may occupy as little as 15% or as much as 75% of the total underground gas storage (UGS) reservoirs. Providing and injecting the cushion gas has the most contribution to the cost of the storage operations. Therefore, part of the base gas can be replaced by a cost-effective gas such as nitrogen, flue gas or air to reduce the costs of the investment. Some degree of mixing takes place when two miscible gases come into contact with one another that affects the quality of the produced natural gas. Therefore, the process needs to be studied and controlled. In this study, the feasibility of underground gas storage and the substitution of the base gas by a cheaper gas, i.e., nitrogen, flue gas, and air, are investigated in a partially depleted dry gas reservoir with very low initial pressure. To do so, a comparative study is performed among nitrogen, flue gas and air as the alternative gases to the base gas. In addition, the effect of flue gas composition on the performance of base gas replacement and ultimate gas recovery is investigated. Pure CO2 is considered as flue gas with zero mole% N2. In the end, the effect of the reservoir properties on mixing between the gases is studied. The results indicated that it is possible to substitute 24.8% of the base gas by nitrogen to obtain a 16.2% increase in the gas recovery of the reservoir. In this case, the ultimate recovery reaches 50.90%. Using flue gas as the alternative gas, the results showed a 15.6% increase in the gas recovery of the reservoir, obtained by substituting 23.9% of the base gas. The ultimate recovery using flue gas is 50.31%. According to the results, flue gas can be used as an appropriate option to replace the base gas of the UGS reservoir under consideration, and hence, there would be no more need for separation and purification of N2 and CO2. Increasing the CO2 composition in the flue gas up to 46.6 mole% leads to a decrease in the base gas replacement amount. When the composition increases above 46.6 mole%, the amount of the replaced gas does not change. However, in this composition range, more flue gas is injected into the reservoir, which has environmental advantages. The highest injection rate of the flue gas is obtained when the flue gas contains 100 mole% of CO2. The main problem in using air as the base gas is the high viscosity of air which requires a high injection pressure. According to the results, using air as the replacement gas, 21.3% of the base gas is substituted by air. In this case, gas recovery increases by 13.9% with respect to the reservoir depletion scenario and the ultimate recovery reaches 48.62%.

Molecular Simulation of Enhanced Oil Recovery in Shale

Enhanced oil recovery (EOR) techniques (miscible/near miscible gas injection, chemical flooding and thermal) aim at increasing oil recovery factor, over which that would be achieved from natural depletion and pressure maintenance methods. As we embark on more complex EOR processes (e.g. miscible hydrocarbon/non-hydrocarbon, surfactant/polymer, smart water and combination of the three), complex phase equilibria, complicated rock/fluid interaction, and sophisticated transport through porous media will create a number of key technical challenges that must be addressed. The issue is significantly increased in unconventional resources as the physics behind the process is not very well understood.For these resources, effective enhanced oil recovery (EOR) techniques are required to displace oil from nanoscale shale matrix. Due to small permeability, it is difficult to conduct water and chemical flooding in these resources. Maintaining a stable flood front in immiscible gas flooding due to the severe fingering phenomenon in fractured shale formations. Gas huff-n-puff becomes the most suitable EOR method in shale reservoir development. For decades, CO2 (EOR) techniques that have been successfully applied in conventional reservoirs to improve oil production. In this work, we will investigate the physics behind CO2 injection into organic nanopores of shale using molecular dynamics simulations. A 3D kerogen structure is used with dodecane to study the huff-n-puff process at a molecular level. Results show that there is an optimal soaking time after which the recovery factor is not affected by soaking time anymore. Furthermore, carbon dioxide has high affinity to be adsorbed to kerogen walls and therefore desorbing the hydrocarbon molecules.

Study on multiple‐contact phase behavior in natural gas injection for enhanced oil recovery in Tarim Basin, China

AbstractThe crude oil samples used in the study was from high‐pressure and high‐temperature (HPHT) reservoirs of Donghetang Oilfield in Tarim Basin in northwestern China. Crude oil–hydrocarbon gas multiple‐contact test and swelling tests are conducted to study the characteristics of phase behavior after hydrocarbon gas is injected into in the formation crude oil. The effect of different amounts of the injected hydrocarbon gas on saturation pressures of reservoir fluid is analyzed. The experimental results are regressed through PVTsim software. The authors use a state‐of‐the‐art HPHT pressure–volume–temperature (PVT) system to conduct the first contact miscibility pressure and swelling tests. Study results show that the multiple‐contact miscibility pressure is on the curve of saturation pressure of reservoir fluid versus the amount of injected gas. Furthermore, the first contact miscibility pressure is at the point of the curve where the tangent is zero. Multiple‐contact experiment is an important method for studying the mechanisms of miscible hydrocarbon gas flooding.

Evaluation of carbon dioxide storage and miscible gas EOR in shale oil reservoirs

This paper presents a new perspective on modeling of CO2 and miscible gas injection into shale oil plays for potential enhanced oil recovery (EOR) and CO2 storage. Our major points are the conceptual understandings of the dominant trapping and the oil recovery mechanisms behind miscible gas injection. This paper investigates the efficiency of miscible gas (solvent) injection into shale oil reservoirs with a wide range of permeability (from 1 to 100 µD). We set up a large-scale numerical model to simulate and capture the important mechanisms behind various miscible gas injection and geological storage scenarios. This numerical study demonstrates that injecting miscible gas such as CO2 and recycled gas rich in ethane substantially increases oil recovery in shale oil reservoirs. Numerical simulation models reveal that miscibility and CO2 adsorption, along with gas diffusion, are important physical mechanisms. However, recycled-enriched gas injection demonstrated a larger oil recovery rate compared to miscible CO2 injection. On the other hand, CO2 trapping is considerable, because of adsorption and other traditional trapping mechanisms in shale plays. The amount of CO2 trapped in unconventional reservoirs can be a significant fraction of the total injected amount (∼25 to50% including the important and dominant trapping mechanisms, e.g. CO2 dissolution in oil and water, adsorption, residual, and mobile gas saturations). Results show that molecular diffusion can speed CO2 flux delivery to larger matrix area and thus contribute to oil recovery, and become trapped and adsorbed on minerals or organic contents.

Investigation of Asphaltene Deposition at High Temperature and under Dynamic Conditions

Asphaltene deposition is one of the major flow assurance problems that can potentially deteriorate due to the current tendencies to produce from the deep-water environment or as a result of enhanced oil recovery operations based on miscible gas injection. The deposited asphaltenes in the wellbores and on the surface of the oilfield pipelines can impede the productivity of the wells significantly. The comprehensive understanding of the mechanisms and the techniques to control asphaltene deposition at high temperature and under dynamic conditions can help resolve this critical issue. Thus, it is imperative to develop reliable, straightforward, and inexpensive tools to investigate the asphaltene deposition tendency and the performance of asphaltene inhibitors in the laboratory. In this work, a new stainless steel packed bed column deposition system that was inspired by the work of Vilas Boas Favero et al. was successfully developed. The packed bed design allows the feasibility of investigating a variety of f...

Huff 'n' Puff Gas-Injection Pilot Improves Oil Recovery in the Eagle Ford

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189816, “Huff ’n’ Puff Gas-Injection Pilot Projects in the Eagle Ford,” by B. Todd Hoffman, SPE, Montana Tech, prepared for the 2018 SPE Canada Unconventional Resources Conference, Calgary, 13–14 March. The paper has not been peer reviewed. The Eagle Ford formation has produced approximately 2 billion bbl of oil during the last 7 years, yet its potential may be even greater. Using improved oil-recovery (IOR) methods could result in billions of additional barrels of production. While a number of companies have field-tested an IOR method called huff ’n’ puff gas injection, most of the published results are from laboratory and modeling studies. This paper evaluates the results of these field tests and discusses the potential of the huff ’n’ puff method in the formation. Introduction The Eagle Ford formation, formed during the late Cretaceous, is a laminated calcareous organic rich shale. The shale was deposited in a low-energy anoxic marine shelf environment, which allowed for rapid deposition and burial of abundant organic material. The Eagle Ford is divided typically into two sections: the Upper, which was deposited during a regional marine regression, and the Lower, which was deposited during a transgressional period and tends to have more organic-rich black shale. The Eagle Ford is laterally continuous and spatially extensive throughout much of southern Texas. The matrix permeability of the reservoir is low enough that typical hydrocarbon migration is restricted, causing the oil-rich rocks to be stratigraphically higher than the gas-filled ones. Results of Previous Huff ’n’ Puff Pilot Projects The huff ’n’ puff process involves injecting a miscible gas into a well and then, after some time has passed, producing back from that same well. Data have been collected on seven pilot projects in the Eagle Ford that have been completed during the last 5 years. Data from four of these seven are discussed in this synopsis. All of the pilots used hydrocarbon gas, but the composition of the gas varied across the locations. In addition, all of the field trials used a huff ’n’ puff injection scheme. Pilot A. The first pilot was a single isolated well where the nearest offset producers were more than 2 miles away. This provided some assurance that the injected gas would not migrate to other wells. The oil rates for the well indicated a positive response to the process. Each cycle increased the production rate to approximately half of the well’s initial rate. Once the oil rate began to drop, another injection cycle was started. This is encouraging because not only the first cycle but also subsequent cycles were able to increase production.

New Approach to Alternating Thickened–Unthickened Gas Flooding for Enhanced Oil Recovery

Direct gas thickening is a conventional mobility control method to improve volumetric sweep efficiency for miscible gas injection (MGI) projects. However, the viability of this approach with technically feasible thickeners has not been verified at the field-scale due to a combination of high costs and/or environmental issues. One approach to make this technique economically more attractive is the implementation of an alternating injection scheme (similar to water-alternating-gas (WAG)) that would require less of the thickened gas compared with a continuous injection scheme. In this study, the effectiveness of this approach where a miscible alternating injection of thickened associated gas (TAG) or thickened CO2 (TCO2) with unthickened AG is explored in both nonfractured and fractured composite carbonate cores. Twelve core-flooding experiments were conducted using different injection schemes (i.e., continuous unthickened, continuous thickened, and alternating thickened–unthickened). These tests demonstrate...

Minimum miscibility pressure computation in eor by flare gas flooding

The technical feasibility of using flare gas in the miscible gas flooding enhanced oil recovery (MGF-EOR) is evaluated by comparing the minimum miscibility pressure (MMP) obtained using flare gas to the MMP obtained in the conventional CO2 flooding. The MMP is estimated by the multiple mixing cell calculation method with the Peng-Robinson equation of state using a binary nC5H12-nC16H34 mixture at a 43%:57% molar ratio as a model oil. At a temperature of 323.15 K, the MMP in CO2 injection is estimated at 9.78 MPa. The MMP obtained when a flare gas consisting of CH4 and C2H6 at a molar ratio of 91%:9% is used as the injection gas is predicted to be 3.66 times higher than the CO2 injection case. The complete gas-oil miscibility in CO2 injection occurs via the vaporizing gas drive mechanism, while flare gas injection shifts the miscibility development mechanism to the combined vaporizing / condensing gas drive. Impact of variations in the composition of the flare gas on MMP needs to be further explored to confirm the feasibility of flare gas injection in MGF-EOR processes. Keywords: flare gas, MMP, miscible gas flooding, EORAbstrakKonsep penggunaan flare gas untuk proses enhanced oil recovery dengan injeksi gas terlarut (miscible gas flooding enhanced oil recovery atau MGF-EOR) digagaskan untuk mengurangi emisi gas rumah kaca dari fasilitas produksi migas, dengan sekaligus meningkatkan produksi minyak. Kelayakan teknis injeksi flare gas dievaluasi dengan memperbandingkan tekanan pelarutan minimum (minimum miscibility pressure atau MMP) untuk injeksi flare gas dengan MMP pada proses MGF-EOR konvensional menggunakan injeksi CO2. MMP diperkirakan melalui komputasi dengan metode sel pencampur majemuk dengan persamaan keadaan Peng-Robinson, pada campuran biner nC5H12-nC16H34 dengan nisbah molar 43%:57% sebagai model minyak. Pada temperatur 323.15 K, estimasi MMP yang diperoleh dengan injeksi CO2 adalah 9.78 MPa. Nilai MMP yang diperkirakan pada injeksi flare gas yang berupa campuran CH4-C2H6 pada nisbah molar 91%:9% sangat tinggi, yakni sebesar 3.66 kali nilai yang diperoleh pada kasus injeksi CO2. Pelarutan sempurna gas-minyak dalam injeksi CO2 terbentuk melalui mekanisme dorongan gas menguap (vaporizing gas drive), sementara pelarutan pada injeksi flare gas terbentuk melaui mekanisme kombinasi dorongan gas menguap dan mengembun (vaporizing/condensing gas drive). Pengaruh variasi komposisi flare gas terhadap MMP perlu dikaji lebih lanjut untuk menjajaki kelayakan injeksi flare gas dalam proses MGF-EOR.Kata kunci: flare gas, MMP, miscible gas flooding, EOR