Computer Modelling Group Research Articles

Effect of Polymer Flooding on Oil Recovery Using Reservoir Simulation, Umm-Faroud Field, Sirt Basin, Libya

This work uses Polymer flooding as an Enhanced Oil Recovery (EOR) technique to increase the injected water viscosity to reduce the mobility ratio and improve sweep efficiency. A reservoir model was constructed using the reservoir-simulating method with Computer Modeling Group software (CMGs IMEX) to predict the oil production and water cut from Umm Foroud field, Sirt Basin, Libya. The models are based on data collected from 17 wells from the Umm Foroud field. Off which, five wells were utilized to build the models, while the other 12 wells were used to validate them. Three scenarios were made; the first was used to predict oil recovery with water injection only, with no polymer, the second model to predict oil recovery with polymer flooding of 10% concentration, and the third with polymer flooding of 20% concentration. The viscosity of water increased by two different concentrations of polymers. Results showed that when water viscosity increased, a significant reduction in mobility ratio occurred and hence, the sweep efficiency was improved. Oil production was improved (increased) in the second and third scenarios where the polymer-flooding scenario (10% and 20% polymer solution concentration) was used. However, the water cut was reduced when compared to water injection.

Numerical Simulation Study on Optimization of Development Parameters of Condensate Gas Reservoirs

Due to the retrograde condensation phenomenon in the development process, the fluid phase change is complex, and it becomes particularly difficult to accurately describe the fluid flow characteristics and residual oil and gas distribution characteristics during the development of condensate gas reservoirs. It is difficult to select the development program and subsequent dynamic adjustment for the efficient, reasonable, and sustainable development of condensate gas reservoirs. In this paper, the phase characteristics of condensate gas reservoirs are clarified; the basic fluid model is created by using computer modeling, using Win-Prop; and in view of the characteristics of the target condensate gas reservoirs, the CMG (Computer Modeling Group) numerical simulation method is applied to study the effects of six factors, the thickness of the reservoir, permeability, porosity, rock compression coefficient, the ratio of the vertical permeability to the horizontal permeability, and the injection of different media, on the development effect through the study of different development parameters of gas condensate reservoirs. The purpose of this study is to provide guidance for the rational development of condensate gas reservoirs in practical production.

An Analytical Method for Timely Predicting of Coal Seam Pressure during Gas Production for Undersaturated Coalbed Methane Reservoirs

Coal seam pressure is an important parameter for production performance evaluation and prediction of coalbed methane (CBM). CBM production from undersaturated CBM reservoirs can be divided into two stages according to critical desorption pressure. At present, few prediction models of coal seam pressure performance consider the comprehensive influence of critical desorption pressure, dissolved gas, matrix shrinkage, and stress sensitivity. For the purpose of accurately predicting coal seam pressure during gas production for an undersaturated coalbed methane reservoir, the material balance principle is used to establish the analytical method for predicting coal seam pressure, considering the comprehensive influence of the critical desorption pressure, dissolved gas, matrix shrinkage, and stress sensitivity. Then, the proposed method is verified against a numerical simulation case using a computer modelling group (CMG) and two actual coalbed methane wells. Finally, the sensitivities of influencing factors on the coal seam pressure are analyzed. The results show that good agreements were obtained between the calculated coal seam pressures using the proposed method and those from the CMG-GEM simulation case and actual CBM wells, with the relative errors all being less than 1%. When ignoring the influence of critical desorption pressure and mistaking pd for pi as well as ignoring Cs, the relative error can reach as high as 31.3%. The main factors affecting the coal seam pressure are the critical desorption pressure and free gas saturation. The proposed method is simple to use, and without shutting-in the well, it can provide an important basis for production performance evaluation and development strategies.

Single-Well Simulation for Horizontal Wells in Fractured Gas Condensate Reservoirs.

Fractured gas condensate reservoirs (FGCR) are a complex, special, and highly valuable type of gas reservoir, accounting for a significant proportion of gas reservoir development. In recent years, with the continuous advancement of horizontal well technology, it has become the main approach for the development of FGCR. The current model is unable to accurately represent the fluid distribution in the near-well area of horizontal wells due to the unique retrograde condensation phenomenon in GCR. Additionally, the presence of fractures complicates the solution of traditional analytical models. In response to this issue, this paper proposes a novel semianalytical model for horizontal wells in FGCR, which incorporates natural fractures, multiphase flow, and the influence of stress sensitivity on pressure response. A dual-porosity model is employed to simulate fractured reservoirs, and a four-region radial composite model is developed to characterize multiphase flow resulting from retrograde condensation in GCR. The pseudopressure transform, Pedrosa transform, Laplace transform, and Finite Cosine transform are utilized to address the nonlinear partial differential equation. A systematic verification of the semianalytical solution is confirmed through a comparison with the numerical solution from computer modeling group (CMG). We thoroughly explain the physical significance of the various features by identifying the 12 flow regimes of the typical curve. Furthermore, we offer a method for assessing the extent of retrograde condensation and the size of the retrograde condensate region based on the curve's characteristics. Finally, the pressure measurements recorded from the Bohai field are carried out to validate the accuracy of the proposed model. The results show that the predictions of the new model are in good agreement with the actual production data, demonstrating the proposed solution's applicability.

Numerical simulation study on impact factors to dynamic filtration loss

During drilling operations, naturally, fractured formations are prone to show serious mud losses, which hinder drilling and increase nonproductive time and costs. The influencing factors of dynamic fluid loss are important for optimizing drilling parameters, reducing drilling fluid loss, and protecting oil and gas reservoirs. In this study, we simulated the dynamic filtration loss of drilling fluid during drilling under formation conditions using commercial software CMG (Computer Modelling Group). The effects of filtration time, filtrate viscosity, pressure difference, internal filter cake permeability, and external filter cake permeability on filtration loss were investigated. The simulation results showed that the permeability of the external mud cake is an important factor to control the fluid loss, and the pressure consumed by the external mud cake with low permeability can account for more than 90% of the total pressure difference. When the permeability of the external mud cake is high, the permeability of the internal mud cake also has a significant influence on the dynamic fluid loss. Under formation conditions, the dynamic fluid loss of radial fluid loss is still proportional to the filtration time and pressure difference, and inversely proportional to the filtrate viscosity of drilling fluid. Under the simulated conditions, the pressure will quickly transfer to the boundary, and the formation pressure at the same position in the formation will gradually increase, while the increase is relatively small with a constant filtration rate. The results of this paper can be used to the real site for drilling optimization. This numerical analysis method can be easily applied to filtrate loss analysis, formation damage area calculation, and other radial flow-related study.

Enhanced Oil Recovery in the Field A123 by Using the Injection of Alkaline, Surfactant and Polymers

Abstract This paper is based on numerical simulations in order to improve the total oil production of field A123 by using an Alkaline-surfactant and polymer (ASP) injections method. The main objective of this paper is to carry out reservoir simulations job that will further permit to conclude if producing oil and gas in this field will be rentable or not. To achieve this objective, the computer Modelling Group software version 2015.10 (CMG 2015 software) is used to carry out the field numerical simulations. Based on the tests run, one injection well is selected and used as a main injector in order to execute the chemical injection schemes in the field. Four different scenarios are studied such as natural flow of oil as the base case (primary oil production), polymer flooding, alkaline-surfactant (AS) flooding and ASP flooding are considering in the injection process and important results from simulator are analyzed and interpreted. Sensitivity analyses are done especially focusing on chemical solution concentration, injection rate and duration of injection time. The results obtained shows an oil recovery factor (ORF) of 64.1554 for polymer flooding, 64.2026 for alkali-surfactant finally 64.8056 for the combined flooding (ASP flooding), respectively. Those results have a direct influence on reservoir pressure which changes after the injected fluids are introduced in the reservoir and therefore improve the production rate. By evaluating the feasibility of the project of polymer flooding combined to AS flooding considering oil prices fluctuations due to COVID 19, the net present value (NPV) is 873 484 102 USD which is the best for the field A123.

Enhanced Oil Recovery in the Field A123 by Using the Injection of Alkaline, Surfactant and Polymers

Abstract This paper is based on numerical simulations in order to improve the total oil production of field A123 by using an Alkaline-surfactant and polymer (ASP) injections method. Its main objective is to carry out reservoir simulations job, that will further permit to conclude if producing oil and gas in this field will be profitable or not. To achieve this objective, the Computer Modelling Group software version 2015.10 (CMG 2015 software) is used to carry out the field numerical simulations. Based on the tests run, one injection well is selected and used as a main injector in order to execute the chemical injection schemes in the field. Four different scenarios are studied such as natural flow of oil as the base case (primary oil production), polymer flooding, alkaline-surfactant (AS) flooding and ASP flooding are considering in the injection process and important results from simulator are analyzed and interpreted. Sensitivity analyses are done especially focusing on chemical solution concentration, injection rate and duration of injection time. The results obtained shows the base case simulations shows that, the reservoir produce oil naturally for 26 years for a quantity of 3,749,204.82 bbl and 864,412,318 SCF of gas. With the most significant case in the third scenario, the coupled effect of ASP optimize the quantities to 32,364,440.2 bbl for oil and 7,459,728,710 scf of gas produce. Also the oil recovery factor (ORF) is 64.1554% for polymer flooding, 64.2026% for alkali-surfactant and 64.8056% for the combined ASP flooding, respectively. These results have a direct impact on reservoir pressure which changes after the injected fluids are introduced in the reservoir and therefore improve the production rate. Thus, the feasibility of the project of polymer flooding combined to AS flooding, is up to 873,484,102 USD for the field A123.

Investigation into the key factors influencing the establishment and propagation of combustion front in ultra-deep high-temperature heavy oil reservoirs

The in-situ combustion technique is currently on the exploratory stage for ultra-deep high-temperature heavy oil reservoirs. In this work, the oxidation experiments of heavy oil were conducted using thermogravimetry, high-pressure differential scanning calorimetry, and combustion tube. Based on these experimental results, a reaction kinetics model was developed, which was then integrated into the Computer Modeling Group (CMG) STARS reservoir simulation software by adjusting stoichiometric numbers, kinetic parameters, and reaction enthalpy to match the experimental data obtained. Furthermore, a corrected reservoir simulation approach was employed, combining the variance analysis and a Pareto chart, to identify the key factors influencing the establishment and propagation of combustion front in the absence of electrical ignition. The results indicate that a reservoir temperature of 148 °C leads to the establishment of combustion front approximately 7 m away from the injection well, with a delay time of around 25.21 days. The Pareto chart reveals that reservoir temperature and water saturation are the primary controlling factors for combustion occurrence. Specifically, a reservoir temperature above 148 °C and water saturation below 60% increase the likelihood of combustion front formation. Among the examined factors, the reservoir temperature has the most significant effect on combustion front propagation. Once the reservoir temperature reaches 208 °C, a stable combustion front is formed, and the average temperature of combustion front remains around 400 °C throughout 8 years of model operation. When the water saturation was 50%, a consistently stable combustion front can be established within the first 6 years of model operation. However, beyond the 6th year, the average front temperature decreases below 400 °C. Therefore, it is recommended to introduce a certain amount of oxidation catalysts into the oil reservoirs after 6 years of air injection to enhance the combustion reactions. Increasing the air injection rate or pre-exponential factor does not have a significant effect on the average front temperature after 8 years of model operation, which remains below 350 °C. This study can provide significant references for future assessments and decision-making processes related to the application of ISC in ultra-deep high-temperature heavy oil reservoirs.

Carbon Dioxide Sequestration in Low Porosity and Permeability Deep Saline Aquifer: Numerical Simulation Method

Abstract The saline aquifer is the most reliable place where anthropogenic carbon dioxide gas storage has shown a promising future. This paper evaluates and predicts the capacities of different carbon dioxide storage trapping mechanisms in storing carbon dioxide gas in low porosity and permeability deep saline aquifers by using commercial reservoir simulator software i.e., Computer modeling group (CMG). Four carbon dioxide storage trapping modeled and simulated were structural or stratigraphic trapping mechanisms, residual trapping mechanisms, solubility trapping mechanisms, and mineral trapping mechanisms. Carbon dioxide gas was injected into a deep saline aquifer for 15 years, followed by 833 years of post-injection. To reflect the real field reality and have a reasonable approximation of the amount of carbon dioxide which can be stored in an aquifer, this paper included water vaporization effects that occur during carbon dioxide injection and water injection operations so as to optimize residual and solubility trapping mechanisms as the most important trapping mechanisms. Furthermore, the effects of different important parameters such as salinity, vertical-to-horizontal permeability ratio, injection rate, bottom hole pressure, and temperature on each carbon dioxide trapping mechanism were analyzed. Results revealed that each carbon dioxide trapping mechanism has a different capacity for storing carbon dioxide and could be either affected linearly or nonlinearly with various parameters. Higher aquifer temperatures are not recommended for carbon dioxide storage because most of the carbon dioxide gas is stored as free gas, which increases the risk of leakage in case of mechanical failure or imbalance. Excess salinity is the only factor that reduces aquifer storage capacity. Furthermore, it was found that an aquifer with a lower vertical-to-horizontal permeability ratio is recommended for carbon dioxide storage because it increases carbon dioxide stored in an immobile phase, which avoids risk leakages. There was an increase of 43.2% and a decrease of 16.84% for minimum and maximum vertical-to-horizontal permeability (kv/kh) ratios, respectively, compared to the base for residual trapping mechanisms. Also, there was a decrease of carbon dioxide dissolved by 19% at maximum kv/kh ratios and an increase of 58% at minimum kv/kh ratios, compared to the base case. Further, there was an increase of carbon dioxide trapped by 96.4% and dissolved by 97% when water was injected at a higher rate compared to the base case (no water injection). Thus, a high injection rate is suggested to enhance residual and solubility trapping mechanisms. It is recommended that the carbon dioxide injection rate and bottom hole pressure be kept at optimal levels to avoid mechanical failure due to aquifer pressures building up, which can increase the risk of leakages and must be monitored and controlled at the surface using pressure gauges or sensor technology.

Simulation of Gas-Water Two-Phase Flow in Tight Gas Reservoirs Considering the Gas Slip Effect

A mathematical model for the gas-water two-phase flow in tight gas reservoirs is elaborated. The model can account for the gas slip effect, stress sensitivity, and high-speed non-Darcy factors. The related equations are solved in the framework of a finite element method. The results are validated against those obtained by using the commercial software CMG (Computer Modeling Group software for advanced recovery process simulation). It is shown that the proposed method is reliable. It can capture the fracture rejection characteristics of tight gas reservoirs better than the CMG. A sensitivity analysis of various control factors (initial water saturation, reservoir parameters, and fracturing parameters) affecting the production in tight gas wells is conducted accordingly. Finally, a series of theoretical arguments are provided for a rational and effective development/exploitation of tight sandstone gas reservoirs.

Experimental and modeling study of hydrophobic associative polyacrylamide for enhanced oil recovery in carbonate reservoir

In this study, hydrophobic associative polyacrylamide (HAPAM) was used in conjunction with the chemical flooding technique in a low-permeability carbonates reservoir. To test the efficacy of the proposed method, both a model and an experiment were created. Experiments were run to compare the relative permeability (Kr) curves, oil recovery rates, and rheological, physical, aging time, and petrophysical features of brine water and polymer flooding in a core. The purpose of these tests was to show how HAPAM can be used to boost oil recovery. Computer Modelling Group (CMG), a simulator, was then used. An oil-and-brine (or HAPAM solution) grid in three dimensions (3D) was developed. The validity of the suggested simulator was established by comparing its results to those obtained from commercial software and from the majority of brine or polymer flooding experiments. The developed simulator was used to undertake additional research into the non-Newtonian flow of brine or polymer solution in porous media. The experimental consequences indicated that the polymer solution has a shear thinning viscosity curve and flow behavior index. Shear thinning, viscosity, shear resistance, aging time, density, surface tension, and interfacial tension, and the water wet relative permeability curve are all improved by the adding 1500 ppm HAPAM to brine water. Moreover, oil recovery was about 80%. There was a strong agreement between the results of the modeling study and the experiments.

Simulation of stability or failure of a combustion front during in-situ combustion in a Post-SAGD process

The highly viscous nature of heavy oil/bitumen in the Lloydminster area leads to difficulty for oil recovery and production. In-situ combustion (ISC) is an attractive candidate as a post-SAGD (steam assisted gravity drainage) operation to improve oil mobilization and maximize oil production. The objective of the study was to demonstrate that the stability or failure of a combustion front when in-situ combustion is implemented in a post-SAGD reservoir can be realistically simulated on the basis of a sound understanding of the underlying chemical reactions, whose rates and stoichiometry have been determined from laboratory measurements. This accomplishment represents a significant step towards an improved application of the in-situ combustion processes.The simulations were performed with the Computer Modelling Group's (CMG) commercial simulator STARS. Four dominant ISC chemical reactions (i.e., pyrolysis of non-volatile oil, low-temperature oxidation, pyrolysis of partially oxidized oil, and combustion) were developed on the basis of available experimental data. Material and energy balances were applied. A representative fluid properties package was obtained by tuning components' parameters to match with available vapor-liquid equilibrium data. ISC was initiated after the steam-assisted gravity drainage stage had been simulated. By successively reducing the simulated initial (pre-SAGD) oil saturation in steps, it was shown that the combustion front changed from stable propagation to being extinguished at a low initial oil saturation around 0.06, for which a combustion-front temperature of 400 °C was maintained. The residual oil saturation approached zero after combustion.

Numerical approach for enhanced oil recovery with polymer flooding using CMG-STARS program

The polymer recovery efficiency of cationic polyacrylamide (PAM) has been evaluated for use as polymer flooding in the Basra oil reservoir Initially, rheological, physical and petro physical were studied. Additionally, the polymer flooding core flooding experiment has been tested to see how well PAM solutions can be recovered. The comparative study between experimental and numerical study for PAM solution has been accomplished in terms of rheological properties , relative permeability curve and oil production. The results showed that PAM solution exhibit shear thinning effect which can efficiently improve the macroscopic sweep efficiency as well as microscopic displacement efficiency, and viscosity increase with high concentration. The overall recovery efficiency of 94.61 % from sandstone was determined for 2500ppm PAM flooding. By contrast, brine water flooding was found to be 47.76%, showing that it was less effective than PAM solution. Cost analysis is another factor that affects a project's success. To support the experimental results, a simulation by the Computer Modelling Group (CMG) study has also been conducted.

Formation damage simulation of a multi-fractured horizontal well in a tight gas/shale oil formation

Formation damage in drilling comes from drilling fluid invasion due to high differential pressure between a wellbore and the formation. This mechanism happens with fracture fluid invasion of multi-fractured horizontal wells in tight formations. Some multi-fractured wells show production rates and cumulative productions far lower than expected. Those damaged wells may sustain further impact such as well shutting due to unexpected events such as the COVID-19 outbreak and then experience a further reduction in cumulative production. This paper focuses on the root causes of formation damage of fractured wells and provides possible solutions to improve production. A simulation study was conducted using Computer Modelling Group software to simulate formation damage due to fracture fluid invasion and well shut-in. Simulation results revealed that the decrease in cumulative hydrocarbon production due to leak-off and shut-in of the simulated well could range from 20 to 41%, depending on different conditions. The results showed that the main causes are high critical water saturation of tight formations, low drawdown, and low residual proppant permeability under formation closure stress. The sensitivity analysis suggests two feasible solutions to mitigate formation damage: optimizing drawdown during production and optimized proppant pack permeability of the hydraulic fracturing process. Optimizing pressure drawdown is effective in fixing leak-off damage, but it does not mitigate shut-in damage. Formation damage due to shut-in should be prevented in advance by using an appropriate proppant permeability. These key findings enhance productivity and improve the economics of tight gas and shale oil formations.

Simulation of carbon dioxide mineralization and its effect on fault leakage rates in the South Georgia rift basin, southeastern U.S.

Over the past few decades, measured levels of atmospheric carbon dioxide have substantially increased. One of the ways to limit the adverse impacts of increased carbon dioxide concentrations is to capture and store it inside Earth's subsurface, a process known as CO2 sequestration. The success of this method is critically dependent on the ability to confine injected CO2 for up to thousands of years. Establishing effective maintenance of sealing systems of reservoirs is of importance to prevent CO2 leakage. In addition, understanding the nature and rate of potential CO2 leakage related to this injection process is essential to evaluating seal effectiveness and ultimately mitigating global warming.In this study, we evaluated the impact of common chemical reactions between CO2 and subsurface materials in situ as well as the relationship between CO2 plume distribution and the CO2 leakage within the seal zone that cause mineralization. Using subsurface seismic data and well log information, a three-dimensional model consisting of a reservoir and seal zones was created and evaluated for the South Georgia Rift (SGR) basin in the southeastern U.S. The Computer Modeling Group (CMG, 2017), was used to model the effect of CO2 mineralization on the optimal values of fault permeability permeabilitydue to fluid substitution between the formation water and CO2. The model simulated the chemical reactions between carbon dioxide and mafic minerals to produce stable minerals of carbonate rock that form in the fault. Preliminary results show that CO2 migration can be controlled effectively for fault permeability values between 0.1-1 mD. Within this range, mineralization effectively reduced CO2 leakage within the seal zone.

Simulation of Water Influx and Gasified Gas Transport during Underground Coal Gasification with Controlled Retracting Injection Point Technology

Underground coal gasification (UCG) may change the energy consumption structure from coal-dominated to gas-dominated in the years to come. Before that, three important problems need to be solved, including failure of gasification due to large amounts of water pouring into the gasifier, environmental pollution caused by gas migration to the surface, and low calorific value caused by poor control of the degree of gasification. In this study, a geological model is first established using the computer modeling group (CMG), a commercial software package for reservoir simulation. Then, the inflow of coal seam water into the gasifier during the controlled retracting injection point (CRIP) gasification process is simulated based on the geological model, and the maximum instantaneous water inflow is simulated too. Meanwhile, the migration of gasified gas is also simulated, and the migration discipline of different gases is shown. Finally, the pressure distributions in two stages are presented, pointing out the dynamic pressure characteristics during the UCG process. The results show that (a) the cavity width, production pressure, and gasifier pressure are negatively correlated with the maximum instantaneous water inflow, while the initial formation pressure, injection pressure, coal seam floor aquifer energy, and temperature are positively correlated; (b) CO2 is mainly concentrated near the production well and largely does not migrate upward, O2 migrates upward slowly, while CH4, CO and H2 migrate relatively quickly. When the injection–production pressure difference is 2 MPa, it takes 33.5 years, 40 years, and 44.6 years for CH4, CO, and H2 to migrate from a depth of 1000 m to 200 m, respectively. When the pressure difference increases to 4 MPa, the gas migration rate increases about two-fold. The aquifer (3 MPa) above a coal outcrop can slow down the upward migration rate of gas by 0.03 m/day; (c) the pressure near the production well changes more significantly than the pressure near the injection well. The overall gasifier pressure rises with gasifier width increases, and the pressure distribution always presents an asymmetric unimodal distribution during the receding process of the gas injection point. The simulation work can provide a theoretical basis for the operation parameters design and monitoring of the well deployment, ensuring the safety and reliability of on-site gasification.

Estimation of Local Equilibrium Foam Model Parameters as Functions of the Foam Quality and the Total Superficial Velocity.

In this paper, the behavior of foam in a porous medium is studied in order to understand the effect of the fluid velocity on foam properties. This aspect is crucial during foam injection, as due to radial effects the foam velocity largely decreases around the injection well. The foam properties are detailed through the use of a new local equilibrium foam model parameter estimation approach using an improved new shear function and based on the most widely used STARS model developed by the Computer Modeling Group (CMG). A new mode of calculation of the STARS model parameters is then presented in order to allow both a semiautomated fitting of several quality scan pressure curves and a consideration of the role of the total velocity. The approach is tested through column experiments done at various velocities and gas fractions. Furthermore, the proposed model is also tested on literature results in order to validate it for very different experimental conditions. This study and the fitted results are then used to understand, on both our column experiments and the literature data, the existence of two shear effects and their origins.

Dual Benefits of Enhanced Oil Recovery and CO2 Sequestration: The Impact of CO2 Injection Approach on Oil Recovery

Injection of CO2 to enhance oil recovery is widely used due to its multiple advantages such as mobilizing the oil and sequestration of carbon dioxide. Injection of CO2 can enhance oil recovery by reducing oil viscosity and improving overall fluid mobility. However, several problems are associated with CO2 injection such as viscous fingering, gravity override, and CO2 channeling that results in early gas breakthrough, low sweep efficiency, and low ultimate oil recovery. In this study, dual benefits of CO2 injection are presented: enhancing oil recovery and sequestering carbon dioxide. In this work, different scenarios of field scale simulation were conducted to evaluate oil recovery during CO2 injection, and the CMG (Computer Modeling Group) software package was used. Three main scenarios were examined which are CO2 injection into the reservoir, CO2 injection into the aquifer, and CO2 injection into the aquifer followed by waterflooding. Also, three well configurations were utilized—all injectors and producers are drilled vertically, all wells are drilled horizontally, and vertical injectors and horizontal producers are used. Therefore, the oil recovery profiles were examined for nine scenarios over a 20-year period. In all simulated models, CO2 injection was started at the residual oil saturation (Sor) conditions, to represent the cases of depleted oil reservoirs. The results indicated that the highest oil recovery of 73% of the original oil-in-place (OOIP) can be achieved by injecting CO2 into the reservoir, utilizing vertical injectors and producers. While injecting CO2 into aquifers can significantly enhance oil recovery by around 68–70% of the OOIP, using horizontal wells can provide more oil recovery (67.7%) than that using vertical wells (54.8%), in the same conditions. Moreover, around 7,928 tons of carbon dioxide can be sequestered in underground formations, on average. Finally, CO2 injection outperformed the conventional waterflooding, where 68 and 12% of the OOIP were obtained, respectively. Overall, injection of CO2 into the depleted reservoir can provide dual benefits of CO2 sequestration and improved oil recovery. CO2 can be injected into the water zone resulting in a slow release of CO2 which will reduce the fluid viscosity, enhance oil recovery, and reduce the greenhouse effect.

Simulation models for the minimum velocity for foam generation and propagation

Foam injection is a promising means of reducing the relative mobility of gas, and hence improving the sweep efficiency of gas, in CO2 and H2 storage, soil-contaminant removal in aquifer remediation, enhanced oil recovery, and matrix-acid well stimulation. Theory (Rossen and Gauglitz, 1990; Ashoori et al., 2012) and experiments (Gauglitz et al., 2002; Yu et al., 2019, 2020) indicate that both foam generation and propagation in steady flow in porous media require the attainment of a sufficiently large superficial velocity or pressure gradient ∇P. Here we examine several foam-simulation models for their ability to represent a minimum velocity, or trigger, for foam generation. We define criteria for representation of such a trigger. For simplicity, we assume a homogeneous porous medium and absence of an oleic phase. We examine the Population-Balance (PB) models of Kam and Rossen (2003) and one of its variants (Kam, 2008), and the PB model of Chen et al. (2010); and the implicit-texture (IT) models in CMG-STARS (Computer Modeling Group, 2017) and of Lotfollahi et al. (2017).Our result show that the PB models of Kam and Rossen and its variant, and the IT models of CMG-STARS and of Lotfollahi et al. do represent a minimum velocity for foam generation. They achieve this by modeling an abrupt decrease in gas mobility with increasing pressure gradient over some range of ∇P. The model of Chen et al. (2010) is based on the model of Kovscek and Radke (1996), which was not intended to represent a trigger for foam generation (Kovscek and Radke, 1993). We cannot say categorically whether it could predict a trigger for any set of model parameter values. Instead, we derive criteria that must be satisfied by the choice of parameters to represent a trigger for foam generation.In simulations of radial foam propagation the STARS foam model predicts that foam propagation fails at the radius at which local ∇P cannot maintain strong foam, not at a greater velocity and ∇P as seen in experiments (Yu et al., 2020). In addition, we identify a fundamental challenge in representing foam generation at the large ∇P at the wellbore in a numerical simulation: conventional simulators do not represent ∇P at the wellbore. Foam generation at the very high superficial velocity at the well radius is not represented in the absence of truly exceptional grid refinement.

Polymer flooding and its effects on enhanced oil recovery special reference to Upper Assam Basin

Chemical Enhance oil Recovery (CEOR) technology is getting more attention since energy crises are getting worse and frightened. Successful application of polymer flooding depends on the evaluation of rheological and solution properties of injected slug at reservoir conditions, which is function of polymer concentration, salinity, temperature and shear rate. Poly acryl amide (PAM) is commonly used polymer in polymer flooding technique. However, comparative study with other polymers such as xanthan gum (XG) is required while selection of appropriate polymer for CEOR. In present study, the recovery efficiency of PAM and XG as a polymer has been evaluated for application as chemical EOR agent for tertiary phase polymer flooding in Upper Assam basin. The comparative study between PAM and XG has been done in terms of rheological properties. Core flooding experiment of polymer flooding has also been tested to determine the recovery efficiency of the PAM and XG polymer solutions. The results showed that these polymers exhibit favorable salt tolerance, temperature resistance, and recoverable viscosity after shearing, reasonable thickening behavior and improved viscosity enhancement properties due to presence of hydrophobic association in the polymer main chains. Core flooding experiment of polymer flooding has also been tested to determine the recovery efficiency of the PAM and XG polymer solutions. Results show that macroscopic sweep efficiency is the dominant factor during recovery. While an injection of hydrogel polymer to the reservoir is to increase a viscosity of fluid containing water so that the fluid is more difficult to flow than the oil, and as a result, the oil production increases. Shear thinning behavior was observed in case of PAM indicating predominance of the frontal advance theory. As PAM seems to be following both piston like movement and frontal advance theory it can be efficiently enhancing the macroscopic sweep efficiency as well as microscopic displacement efficiency. The overall recovery efficiency of 53% of OOIP was determined for PAM flooding. The overall recovery efficiency by XG polymer flooding was found to be 45%, signifying its lesser efficiency in comparison to PAM. Success of the projects also depends on cost analysis. Simulation by Computer Modelling Group (CMG) study has also been carried out to validate the experimental findings.