Immiscible Gas Research Articles

Experimental Evaluation of CO2-Soluble Nonionic Surfactants for Wettability Alteration to Intermediate CO2-Oil Wet during Immiscible Gas Injection

Summary The change in wettability of limestone reservoirs from oil-wet toward gas-wet can enhance crude oil production during immiscible CO2 injection. Therefore, in this research, we investigated the impact of wettability alteration to CO2-wet on oil recovery factor via dissolution of fluorine-free, CO2-philic, nonionic surfactants such as C4(PO)6 and C41H83O19 in CO2. Based on the cloudpoint measurements, the dissolution pressures of nonionic surfactants in supercritical CO2 ranged between 2,100 psi and 2,700 psi (below the reservoir pressure, i.e., 3,000 psi) at reservoir temperature, 65°C; these pressures are commensurate with CO2-enhanced oil recovery (EOR) pressures. Also, the C4(PO)6 and C41H83O19 can reduce the CO2-oil interfacial tension (IFT). Moreover, the CO2/C4(PO)6 and C41H83O19 solutions can change the limestone wettability from strongly oil-wet (Θ ~ 20o) to intermediate CO2/oil-wet (Θ = 95o and 110o) at reservoir conditions. The relative permeability curves also confirmed it by changing the curvature to the left and decreasing the residual oil saturation in both cases of CO2/C4(PO)6 and C41H83O19 solutions. The 20.8% and 13.1% additional oil recoveries were achieved during the 30,000 ppm CO2/C4(PO)6 and C41H83O19 solution scenarios, respectively, relative to the pure CO2 injection scenario. These nonionic surfactants are not able to make CO2-in-oil foam; therefore, wettability alteration and perhaps IFT reduction are the dominant mechanisms of EOR induced by the dissolution of nonionic surfactants in CO2, instead of CO2 mobility control. Consequently, the dissolution of fluorine-free, oxygenated, CO2-philic, nonionic surfactants (such as C4(PO)6 and C41H83O19) in CO2 at 30,000 ppm concentration can be a well-qualified candidate for altering the limestone wettability to intermediate CO2-oil-wet during the immiscible CO2 injection.

Enhanced oil recovery via dissolution of low molecular weight PDMS in CO2 during immiscible gas injection in matrix-fracture system

Oil recovery in natural fracture reservoirs can be improved by reducing the capillary force during the gravity drainage process in matrix-fracture system. In the current study, a modified gas was generated via dissolution of low molecular weight poly(dimethyl siloxane) (PDMS, average Mw 3780 g/mol, 10000 – 50000 ppm) in CO2 to enhance oil recovery at 50 °C or 70 °C and 3000 psi. Cloud point measurements indicated that PDMS dissolved in CO2 at pressures less than 3000 psi, which was below the minimum miscibility pressure (MMP) of ∼3600 psi at 70 °C determined with the vanishing interfacial technique. The solution density increased from 669.6 kg/m3 for pure CO2 to 780.3 kg/m3 for CO2/PDMS (50000 ppm) at 70 °C and 3000 psi, thereby reducing the density difference between the CO2-rich fluid and crude oil (ρo=865.2 kg/m3) in matrix-fracture system. Also, CO2-oil interfacial tension (IFT) was reduced from 65 to 15 dyn/cm via the dissolution of 50000 ppm PDMS in CO2. Therefore, it led to the CO2 diffusion coefficient increased in both reservoir-fluid saturated porous media and bulk oil scenarios 3–4 fold and 4–7 fold respectively in comparison to pure CO2 injection. These PDMS-induced changes reduced the capillary effects in gas-invaded zone, which consequently led to an increase in oil recovery of 25% points (from 31% to 56%) compared to pure CO2 injection in the case of capillary continuity during gravity drainage tests. For the field-scale, because the PDMS can dissolve in CO2 at pressures and temperatures which are commensurate with CO2 EOR, it is a promising CO2-philic chemical for increasing CO2 density and improving CO2 diffusion coefficient in gas invaded zone compared to conventional CO2 injection.

A CASE STUDY: DEPTH IMPACT ON RECOVERY OF IMMISCIBLE GAS INJECTION IN AN IRANIAN UNDERSATURATED OIL RESERVOIR

In saturated oil reservoirs, the pressure of the reservoir is gradually reduced with oil production, which ultimately leads to gas production of the reservoir and formation of a gas cap. After the period of natural depletion from oil reservoirs, it is necessary to use secondary and then tertiary methods of enhanced oil recovery (EOR). One of the most common methods, if gas is available, is gas injection. By injecting gas while pressure maintenance and re-pressuring to the initial pressure of the reservoir, the recovery factor increases. This increase in recovery factor mainly occurs due to maintenance or an increase in pressure and a decrease in interfacial tension (IFT) and viscosity. In Iran, except in one of the fields where gas injection is done with the aim of miscible gas injection, other gas injection projects are done with the aim of pressure maintenance. In these projects, the proper place for injection is not taken into consideration, and the gas is done in the highest part of the reservoir. The question was raised at what depth the gas injection should be done to be optimal. Therefore, one of the reservoirs in the south of Iran was selected, and a feasibility study was conducted with the aim of determining the most suitable injection point. In this study, the issue of the appropriate place for gas injection, whether it is in the gas cap, in the middle of the production column, or near the water/oil contact, has been investigated, and the results have been presented. Also, it is approved that the injection in a saturated reservoir has a higher recovery factor than under a saturated reservoir. Finally, injection near water/oil contact is known as the preferred option.

Laboratory simulation of CO2 immiscible gas flooding and characterization of seepage resistance

Laboratory simulation of CO2 immiscible gas flooding and characterization of seepage resistance

Laboratory Determination of Productivity of Bomu Oil Field (Oml 11 as Case Study) Using MEOR Process and Calcium Oxide Nanoparticles

The need for petroleum products in the world is increasing daily, this product can only be gotten from the refining of crude oil a naturally occurring mineral resource which is produced by degradation of organic materials. This crude is gotten from several wells drilled for the sole purpose of the production of this mineral resource but this wells are being shut-down and abandoned because of the decrease in the well’s productivity which causes losses to the operators and poor finances for the petroleum industry. Therefore, the need to increase the recovery of a well is been considered, these methods are called enhanced oil recovery method. These methods include Gas injection method, Steam Injection method, Chemical injection method (chemicals such as surfactants, polymers etc) Microbial method and the use of nanoparticles as additives to help increase the recovery process. The type of enhanced oil recovery used in this work is the microbial enhanced oil recovery, this method makes use of biosurfactants which can also be referred to as microbe surfactants. The biosurfactants are gotten from microorganism they act as surfactants which reduces the interfacial tension between the molecules of the substance and the interface, this biosurfactants can be used for many industrial purposes which includes bioremediation, oil recovery etc. Nanoparticles are also another aspect of the recent technology which can increase the recovery of our well providing more crude and finance for the petroleum industry. This work shows how biosurfactants and nanoparticles when used together can increase oil recovery. The ever-rising global demand for energy and the issue of large volumes of unrecovered oil after primary and secondary oil production operations are driving the development and/or advancement of enhanced oil recovery (EOR) techniques. Conventional EOR processes include thermal, immiscible and miscible gas injection, chemical, and microbial enhanced oil recovery

Grand Challenges for the Oil and Gas Industry for the Next Decade and Beyond

_ The oil and gas industry faces a rapidly changing world of multiple challenges and opportunities, especially with growing climate and sustainability concerns. About a decade ago, SPE conducted a series of workshops to define the grand challenges in technology and R&D for the upstream oil and gas industry for the following decade. It identified 5 + 1 grand challenges (Table 1). To define the set of grand challenges for the next decade, in a much more unpredictable environment, we held an SPE workshop in Austin, Texas, in January 2023. Panelists from IOCs, NOCs, and service companies, as well as environmental and financial stakeholders in the emerging energy system, surveyed the rapidly changing energy landscape. The workshop then facilitated sessions of the more than 120 thought leader participants to define grand challenges that are impactful for society and our industry and have a significant R&D/technology component that is aligned with the capabilities of the SPE membership. We arrived at a list of five technical grand challenges: improved recovery from tight/shale resources, net-zero operations, carbon capture, utilization, and storage (CCUS), geothermal energy, and digital transformation. Additionally, we identified a sixth “bonus” nontechnical challenge—education and advocacy, since we believe that more effective engagement with thought leaders outside our industry will be required to advance and deploy new technologies in all five of these areas. Table 2 summarizes the technical challenges and their impacts. We believe that this work will help the industry focus its R&D and technology efforts on the highest-value activities for both industry and society. We now summarize each of these new grand challenges. Improved Recovery From Tight/Shale Resources Notwithstanding the rapid growth of non-hydrocarbon energy sources and carriers, oil and natural gas demand are projected to continue rising through 2050 (EIA 2023). In the past 20 years, horizontal drilling and hydraulic fracturing were combined to extract hydrocarbons from unconventional shale resources, which helped us meet rising global oil demand. However, production from existing shale oil wells declines quickly, and ultimate recoveries are often less than 10%. To meet global demand, we must improve recovery with minimal environmental impact. Tight and shale oil reservoirs have unique challenges. For example, shale reservoirs are subject to clay swelling and formation damage. Permeabilities are ultra-low, often on the order of nano-Darcys, which leads to extremely low flow rates and to transport dominated by diffusion. Thus, hydraulic and natural fractures are necessary, and geomechanics/rock compaction plays an important role. Many traditional improved oil recovery (IOR) strategies are challenging in tight and shale reservoirs. The small pores make waterflooding techniques difficult, and the low permeability hampers well-to-well methods. Thus, single-well, huff-and-puff strategies are the most common IOR methods. Injectants include miscible and immiscible gases (CO2, CH4, and N2) and chemicals (surfactants, solvents, and nanoparticles). In addition, thermal methods may allow control of oil viscosity and pressurization of the reservoir.

Simulation study of water and gas injection process into the Azadegan reservoir for enhanced oil recovery

AbstractIt is necessary to improve oil production from reservoirs. Various methods have been proposed to increase oil extraction from reservoir. Each method has specific challenges. In this research, the effect of water and gas injection in to Azadegan reservoir has been analyzed. Azadegan oil field is located south of Iran. In this study, water, immiscible gas and water alternating gas injected to reservoir and its effect on enhanced oil recovery have been investigated. Finally, a comparison between results of methods is provided. Results show that effective method for enhanced oil recovery is immiscible gas injection with 46% oil production efficiency and water alternating gas injection with 36% oil production efficiency. This study shows that oil production efficiency can be increased if duration of gas injection is increased. This study shows, increasing viscosity of water in water alternating gas scenario did not improve the production of Azadegan reservoir.

Decreasing Asphaltene Precipitation and Deposition during Immiscible Gas Injection Via the Introduction of a CO2-Soluble Asphaltene Inhibitor

Summary In this study, the ability of dilute concentrations of toluene to act as a CO2-soluble asphaltene stabilization agent capable of inhibiting asphaltene precipitation during immiscible CO2 injection was assessed. Phase behavior results indicated that 1,000 to 20,000 ppm toluene could readily dissolve in CO2 at cloudpoint pressures that are well below the formation pressure and typical CO2 minimum miscibility pressure (MMP) values during gas-based enhanced oil recovery (EOR). Single-phase solutions of the modified gas (CO2/toluene) were then combined with asphaltenic oils in oil swelling phase behavior tests to demonstrate that the presence of toluene increased the amount of CO2 that dissolved into reservoir crude oil at a specified temperature and pressure. However, asphaltene precipitation diminished, apparently because the effect of the increased asphaltene solvent strength of toluene was more significant than the increased amount of CO2 (an asphaltene antisolvent) that entered the oil-rich phase. During the injection of CO2/toluene solution into cores initially saturated with crude oil and brine, compared to the injection of pure CO2, asphaltene deposition declined during the injection of CO2/toluene mixtures for asphaltenic volatile and intermediate oils from 3.7 wt% to 0.7 wt% and 5.9 wt% to 1.7 wt%, respectively. Based on the asphaltene particle-size analysis, the CO2/toluene mixtures can stabilize oil particles and simultaneously reduce asphaltene aggregation more effectively than pure CO2.

A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs

Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. During WAG experiments, starting the injection cycles with water or gas did not have any impact on the ultimate oil recovery for both miscible and immiscible cases for one of the reservoirs, while WAG_G (WAG starting with gas injection) recovered more oil for another reservoir. Gravity has a significant impact on oil recovery for both miscible and immiscible gas injections. A significant difference is observed in oil recovery when comparing CO2 injection on 2-in.- and 4-in.-diameter core samples or when comparing horizontal vs. vertical immiscible gas injection and WAG experiment. The longer the CO2 slug size, the higher the oil recovery observed in gas injection experiments. The results of this study provide a rich and rarely available set of experimental data that can help improve and optimize gas and WAG injection in oil-wet carbonates.

Field‐scale reactive transport assessment of CO2 storage in the Farnsworth unit through enhanced oil recovery practices

AbstractThe objective of this study was to investigate the transport and fate of CO2 injected into a sandstone reservoir in the western Farnsworth Unit, a hydrocarbon field in northern Texas. The study employed three‐dimensional multifluid‐phase numerical reactive solute and heat transport modeling. Model inputs were obtained from previous field characterization studies and calibrated to 8 years of historical production data. The CO2 in the models was injected through multiple wells for the first 25 years of the simulations according to a water‐alternating gas schedule. The simulations were carried out for a total of 1000 years in order to study the long‐term effects of CO2 injection.The results show that the largest fraction of the injected CO2 is stored in oil, followed by successively smaller amounts in the formation water, carbonate mineral phases, and as an immiscible gas phase. The small fraction of CO2 present as an immiscible gas, the most mobile phase for CO2, aids in the long‐term sequestration security of the injected CO2. The injected CO2 was found to migrate within a maximum radius of around 500 m of the injection wells. This means that changes in fluid pressure, temperature, composition, and reservoir mineralogy were also limited to occurring within this radius. This radius is very sensitive to model relative permeability and capillary pressure values, which were determined from history matching to the field production data. The models predicted dolomite to be the main mineral sink for the injected CO2. Quartz was another mineral predicted to precipitate, whereas calcite, albite, chlorite, illite, and kaolinite were predicted to dissolve. The changes in mineral abundance had minimal effect on porosity, implying that the permeability of the reservoir should also not change much because of CO2 injection. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

Variable fidelity surrogate well control optimization with multilevel wavelet based grids

Well control optimization is a complex task that, typically, requires a large number of flow simulations. These simulations are often computationally expensive, which imposes challenges for practical applications. This paper presents a variable fidelity surrogate framework for well control optimization that reduces the computational budget. The method associates a multilevel wavelet based local grid refinement with upscaling procedures to build proxy models in a hierarchical trust-region optimization framework. In the initial stage, lower fidelity samples are used to construct a surrogate model, representing the underlying trends of the objective function and guiding the optimizer in the exploration phase. In the next stages, higher fidelity wavelet based models are used to build new surrogate models, increasing the accuracy. Results are presented for two-dimensional immiscible gas injection and a three-dimensional water injection model. A comparison with the traditional single-level high fidelity surrogate optimization is conducted. Additionally, we verify the reliability of the trust-region update scheme based only on low fidelity samples. We show that the proposed strategy was able of achieving similar or better results than the traditional surrogate optimization, saving about 90% of the computation cost. Also, the low fidelity models were capable to correctly guide the trust-region update scheme.

A Computational Fluid Dynamics Study of Flared Gas for Enhanced Oil Recovery Using a Micromodel

The current handling of gas associated with oil production poses an environmental risk. This gas is being flared off due to the technical and economic attractiveness of this option. As flared gases are mainly composed of methane, they have harmful greenhouse effects when released into the atmosphere. This work discusses the effectiveness of using this gas for enhanced oil recovery (EOR) purposes as an alternative to flaring. In this study, a micromodel was designed with properties similar to a sandstone rock with a porosity of 0.4, and computational fluid dynamics (CFD) techniques were applied to design an EOR system. Temperature effects were not considered in the study, and the simulation was run at atmospheric pressure. Five case studies were carried out with different interfacial tensions between the oil and gas (0.005 N/m, 0.017 N/m, and 0.034 N/m) and different injection rates for the gas (1 × 10−3 m/s, 1 × 10−4 m/s, and 1 × 10−6 m/s). The model was compared with a laboratory experiment measuring immiscible gas flooding. Factors affecting oil recoveries, such as the interfacial tension between oil and gas, the viscosity, and the pressure, were studied in detail. The results showed that the surface tension between the oil and gas interphase was a limiting factor for maximum oil recovery. The lower surface tension recovered 33% of the original oil in place. The capillary pressure was higher than the pressure in the micromodel, which lowered the amount of oil that was displaced. The study showed the importance of pressure maintenance to increase oil recovery for immiscible gas floods. It is recommended that a wider set of interfacial tensions between oil and gas be tested to obtain a range at which oil recovery is maximum for EOR with flared gas.

Improvement to Gravity Drainage Recovery by Repressurization as a Criterion to Screen and Rank Naturally Fractured Reservoirs for Gas Injection

Summary Many of the naturally fractured carbonate reservoirs of the Middle East exhibit low natural-depletion recoveries. The reason is that most of their oil reserves are stored in the low-permeability host rocks and are left behind by the fast advancing gas/oil contact (GOC) and water/oil contact (WOC) in fractures. Producing the remaining oil in the large gas-invaded zone of these reservoirs has been a crucial reservoir management issue. We show in this study using experimental observations, analytical calculations, and numerical investigations that repressurizing naturally fractured reservoirs (NFRs) by crestal immiscible gas injection has the potential to produce a large portion of this remaining oil by improving gravity drainage (GD) through two main mechanisms. One is that at higher pressures, the gas-oil interfacial tension (IFT) and hence the capillary forces that control recovery by GD are lessened, allowing additional recovery. This mechanism is aided by the other one, which is swelling of the oil at higher pressures. In this way, repressurization is thought to be not only a means for pressure maintenance but also a methodology for enhanced-oil recovery (EOR). This is confirmed by both laboratory studies and field performance of large-scale gas injection projects. Despite the desire for implementation of projects of repressurization, gas availability and cost of these projects are important concerns, requiring a cost-benefit analysis. Screening and ranking methodologies have been previously presented for some EOR techniques but not for repressurization by gas in NFRs. Evaluating the performance of gas injection in NFRs is often done using methodologies such as numerical simulations, which are in-depth, costly, and tedious. The methodology developed here is simple, requiring spreadsheet calculations. To develop the methodology, we first obtain simple relations to calculate additional GD recovery by considering the interplay of capillary and gravity forces in a matrix block subjected to pressurization by equilibrium gas injection and then use experimental data from literature to show that these relations can predict primary and secondary GD recoveries to a good approximation. We also show by mechanistic studies using a history-matched numerical model that IFT reduction and oil swelling are the main mechanisms contributing to additional oil recovery. Then, we propose a methodology to screen and rank candidate NFRs for gas injection that uses commonly available reservoir data and is based upon two criteria, these being additional oil recovered from a matrix block by pressurization and required volume of gas to produce an additional barrel of oil. We then implement this methodology to more than 20 Iranian NFRs and identify six reservoirs with potential for additional recovery of more than 20%. By quantifying and including the uncertainties associated with the reservoir data, we illustrate that for the reservoirs under study, capillary pressure parameters along with matrix-block height are the main parameters affecting GD recovery and should be characterized more accurately.

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.

Experimental Evaluation of Foam Diversion for EOR in Heterogeneous Carbonate Rocks

Immiscible gas injection applied to heterogeneous carbonate reservoirs can be inefficient due to poor conformance control. Foam mobility control is proposed in this work as a solution for gas conformance issues in such reservoirs. A unique experimental program was developed to evaluate alkyl polyglucoside (APG) stabilized foam for foaming ability, emulsion-forming tendency and resistance to oil. Dynamic methane foam behavior is systematically studied through single and dual injection core flooding experiments, simulating foam diversion during immiscible methane flooding in a layered reservoir with a significant layer permeability contrast. Results show a stable foam-oil system with no viscous emulsions at very high formation brine salinity (144,000 ppm total dissolved solids). Single-core floods for the high permeability layer (Unit-A) showed that foam viscosity of 27 cP could be achieved at 11% oil saturation (So). Under similar oil-wet condition, the low permeability zone (Unit-B) could generate foam of 21 cP at 18.9% So, indicating an increase in injected fluid mobility reduction with permeability. Dual-core injection experiments, which is designed to evaluate accurately fluid diversion capacity of such foams, reveals remarkable dynamic foam behaviors. While the water-wet condition indicates the scalability of foam behaviors (i.e., the ability of foam to control fluid mobility against the variation of rock permeability) between the single and composite core systems, the oil-wet condition confirms good foam resistance to residual oil that resulted in an increase in Unit B production from 46 to 82%, and 74 to 85% for Unit-A. Moreover, dual-core floods representing premature waterfloods (i.e., higher oil saturation) shows even more dramatic incremental oil recovery (44 to 81% in Unit-A and 17.5 to 71% in Unit-B), evidencing the ability of foam to self-viscosify with permeability variation at varying oil saturations.

Numerical study of real gas effects during bubble collapse using a disequilibrium multiphase model

An explicit density-based solver of the Euler equations for inviscid and immiscible gas–liquid flow media is coupled with real-fluid thermodynamic equations of state supporting mild dissociation and calibrated with shock tube data up to 5000 K and 28 GPa. The present work expands the original 6-equation disequilibrium method by generalising the numerical approach required for estimating the equilibrium pressure in computational cells where both gas and liquid phases co-exist while enforcing energy conservation for all media. An iterative numerical procedure is suggested for taking into account the properties of the gas content as derived from highly non-linear real gas equations of state and implemented in a tabulated form during the numerical solution. The developed method is subsequently used to investigate gaseous bubble collapse cases considering both spherical and 2D asymmetric arrangements as induced by the presence of a rigid wall. It is demonstrated that the predicted maximum temperatures are strongly influenced by the equations of state used; the real gas model predicts a temperature reduction in the bubble interior up to 41% space-averaged and 50% locally during the collapse phase compared to the predictions obtained with the aid of the widely used ideal gas approximation.

Thermodynamically consistent modeling of immiscible gas–liquid flow in porous media

Modeling of immiscible gas–liquid two-phase flow with gas compressibility in porous media plays an important role in shale gas production, geological sequestration of carbon dioxide, and underground gas storage. The second law of thermodynamics is universally recognized as an essential principle any promising model should obey. The existing models have no proper concept of free energies for such a problem, thereby failing to obey this law. In this paper, we first introduce free energies to account for the liquid–gas capillarity effect and gas compressibility, and then using the second law of thermodynamics, we rigorously derive a thermodynamically consistent model for immiscible gas–liquid two-phase flow in porous media. The proposed free energy that describes the capillarity effect is verified by the laboratory data. For gas flow, we use molar density rather than pressure as the primary variable and take the Helmholtz free energy density determined by a realistic equation of state to characterize the gas compressibility. Numerical simulation results are also presented to demonstrate the thermodynamical consistency of the model and the applicability to simulate the liquid and gas displacement processes.

Application of Surfactant-based enhanced oil recovery in carbonate Reservoirs: A critical review of the opportunities and challenges

The oil productionfromcarbonate formations is low because of complicatedcompositions, formation heterogeneity, oil-wet/mixed wet conditions, etc. Primary recovery depends on the reservoir's natural resources for production and is often supplemented by secondary recovery methods such as water flooding or immiscible gas injection to generate an artificial drive and complement reservoir energy. Tertiary recovery strategies should be used to mobilize residual oil saturation and increase oil recoveries from these reservoirs using various chemical flooding and chemical agent systems. Polymer flooding, surfactant flooding, alkali flooding, and combinations of these flooding methods are different types of Chemical floodingEOR (C-EOR) technology. Surfactant flooding procedures have been regarded as reliable EOR methodsfor field utilization because they minimize interfacial tensions and modify reservoir rock wetting characteristics, reducedcapillary forces and thus promote oil recovery. This paper provides a review of field projects and large-scale operations of surfactantfloodingin carbonate reservoirs. The fundamentalprocesses of various chemical systems, as well as the interactions of various compoundswith reservoir rocks and fluids, have been examined. After a sequence of assessment steps, the required surfactant flooding for a range of specific reservoir conditions is determined. The properties of a surfactant such as formulation and characteristics of reservoirs such as temperature, salinity, pH, rock permeability, formation type, wettability and other considerations are discussed. Moreover, since carbonate reservoirs are distinguished with a considerableheterogeneity, high temperature, and high salinity conditions, surfactant and polymer choosingfor these kind of reservoirs is a difficult process that requires experimental test to obtain the best quantity and composition of chemicals. Field project design and technical insights can be used to generate innovative strategies that will have a direct effect on the internationaloil supply in the immediate future.

Asphaltene Precipitation and Deposition under Miscible and Immiscible Carbon Dioxide Gas Injection in Nanoshale Pore Structure

Summary Asphaltene precipitation and deposition is considered one of the prevailing issues during carbon dioxide (CO2) gas injection in gas enhanced oil recovery techniques, which leads to pore plugging, oil recovery reduction, and damaged surface and subsurface equipment. This research provides a comprehensive investigation of the effect of immiscible and miscible CO2 gas injection in nanopore shale structures on asphaltene instability in crude oil. A slimtube was used to determine the minimum miscibility pressure (MMP) of the CO2. This step is important to ensure that the immiscible and miscible conditions will be achieved during the filtration experiments. For the filtration experiments, nanocomposite filter paper membranes were used to mimic the unconventional shale pore structure, and a specially designed filtration apparatus was used to accommodate the filter paper membranes. The uniform distribution (i.e., same pore size filters) was used to illustrate the influence of the ideal shale reservoir structure and to provide an idea on how asphaltene will deposit when utilizing the heterogeneous distribution (i.e., various pore size filters) that depicts the real shale structure. The factors investigated include immiscible and miscible CO2 injection pressures, temperature, CO2 soaking time, and pore size structure heterogeneity. Visualization tests were undertaken after the filtration experiments to provide a clear picture of the asphaltene precipitation and deposition process over time. The results showed an increase in asphaltene weight precent in all experiments of the filtration tests. The severity of asphaltene aggregations was observed at a higher rate under miscible CO2 injection. It was observed that the miscible conditions have a higher impact on asphaltene instability compared to immiscible conditions. The results revealed that the asphaltene deposition was almost equal across all the paper membranes for each pressure used when using a uniform distribution. Higher asphaltene weight percent were determined on smaller pore structures of the membranes when using heterogeneous distribution. Soaking time results revealed that increasing the soaking time resulted in an increase in asphaltene weight precent, especially for 60 and 120 minutes. Visualization tests showed that after 1 hour, the asphaltene clusters started to precipitate and could be seen in the uppermost section of the test tubes and were fully deposited after 12 hours with less clusters found in the supernatant. Also, smaller pore size of filter membranes showed higher asphaltene weight percent after the visualization test. Chromatography analysis provided further evaluation on how asphaltene was reduced though the filtration experiments. Microscopy and scanning electron microscopy (SEM) imaging of the filter paper membranes showed the severity of pore plugging in the structure of the membranes. This research highlights the impact of CO2 injection on asphaltene instability in crude oil in nanopore structures under immiscible and miscible conditions. The findings in this research can be used for further research of asphaltene deposition under gas injection and to scale up the results for better understanding of the main factors that may influence asphaltene aggregation in real shale unconventional reservoirs.

Prediction of Oil Recovery Factor in Stratified Reservoirs after Immiscible Water-Alternating Gas Injection Based on PSO-, GSA-, GWO-, and GA-LSSVM

In this study, we solve the challenge of predicting oil recovery factor (RF) in layered heterogeneous reservoirs after 1.5 pore volumes of water-, gas- or water-alternating-gas (WAG) injection. A dataset of ~2500 reservoir simulations is analyzed based on a Black Oil 2D Model with different combinations of reservoir heterogeneity, WAG hysteresis, gravity influence, mobility ratios and WAG ratios. In the first model MOD1, RF is correlated with one input (an effective WAG mobility ratio M*). Good correlation (Pearson coefficient −0.94), but with scatter, motivated a second model MOD2 using eight input parameters: water–oil and gas–oil mobility ratios, water–oil and gas–oil gravity numbers, a reservoir heterogeneity factor, two hysteresis parameters and water fraction. The two mobility ratios exhibited the strongest correlation with RF (Pearson coefficient −0.57 for gas-oil and −0.48 for water-oil). LSSVM was applied in MOD2 and trained using different optimizers: PSO, GA, GWO and GSA. A physics-based adaptation of the dataset was proposed to properly handle the single-phase injection. A total of 70% of the data was used for training, 15% for validation and 15% for testing. GWO and PSO optimized the model equally well (R2 = 0.9965 on the validation set), slightly better than GA and GSA (R2 = 0.9963). The performance metrics for MOD1 in the total dataset were: RMSE = 0.050 and R2 = 0.889; MOD2: RMSE = 0.0080 and R2 = 0.998. WAG outperformed single-phase injection, in some cases with 0.3 units higher RF. The benefits of WAG increased with stronger hysteresis. The LSSVM model could be trained to be less dependent on hysteresis and the non-injected phase during single-phase injection.