Enhanced Oil Recovery Processes Research Articles

Numerical Investigation of Controllable Parameters Effect on Nanofluid Flooding in a Random Pore Generated Porous Medium

This study simulates the enhanced oil recovery process using nanofluids into a microporous medium. To obtain the optimum values that affect this process, design experiments with the general factorial method was performed. Four parameters included type of nanoparticles and the base fluids, diameter, and volume fraction of nanoparticle were considered. The porous medium was created with the commercial grid generation tool and Fluent software was used to solve the governing equations. Comparison of numerical results with the experimental data illustrates that they are in good agreement. In addition, results show that clay nanoparticles with formation water have the greatest impact on the oil recovery factor compared to other nanofluids. Also the nanofluid with higher amounts of nanoparticles in the base fluid and smaller diameter have better performance in improving the oil recovery factor. Therefore, for having the maximum oil recovery factor, the best combination of parameters is clay nanoparticles with 2 nm diameter and 5 vol. % in formation water.

On the Evaluation of Interfacial Tension (IFT) of CO2–Paraffin System for Enhanced Oil Recovery Process: Comparison of Empirical Correlations, Soft Computing Approaches, and Parachor Model

Carbon dioxide-based enhanced oil-recovery (CO2-EOR) processes have gained considerable interest among other EOR methods. In this paper, based on the molecular weight of paraffins (n-alkanes), pressure, and temperature, the magnitude of CO2–n-alkanes interfacial tension (IFT) was determined by utilizing soft computing and mathematical modeling approaches, namely: (i) radial basis function (RBF) neural network (optimized by genetic algorithm (GA), gravitational search algorithm (GSA), imperialist competitive algorithm (ICA), particle swarm optimization (PSO), and ant colony optimization (ACO)), (ii) multilayer perception (MLP) neural network (optimized by Levenberg-Marquardt (LM)), and (iii) group method of data handling (GMDH). To do so, a broad range of laboratory data consisting of 879 data points collected from the literature was employed to develop the models. The proposed RBF-ICA model, with an average absolute percent relative error (AAPRE) of 4.42%, led to the most reliable predictions. Furthermore, the Parachor approach with different scaling exponents (n) in combination with seven equations of state (EOSs) was applied for IFT predictions of the CO2–n-heptane and CO2–n-decane systems. It was found that n = 4 was the optimum value to obtain precise IFT estimations; and combinations of the Parachor model with three-parameter Peng–Robinson and Soave–Redlich–Kwong EOSs could better estimate the IFT of the CO2–n-alkane systems, compared to other used EOSs.

An Investigation of Mechanistic Foam Modeling for Optimum Field Development of CO2 Foam EOR Application

SummaryWhile there are a number of mechanistic foam models available in the literature, it still is not clear how such models can be used to guide actual field development planning in enhanced oil recovery (EOR) applications. This study aims to develop the framework to determine the optimum injection condition during foam EOR processes by using a mechanistic foam model. The end product of this study is presented in a graphical manner, based on the sweep-efficiency contours (from reservoir simulations) and the reduction in gas mobility (from mechanistic modeling of foams with bubble population balance).The main outcome of this study can be summarized as follows: First, compared to gas/water injection with no foams, injection of foams can improve cumulative oil recovery and sweep efficiency significantly. Such a tendency is observed consistently in a range of total injection rates tested (low, intermediate, and high total injection rates Qt). Second, the sweep efficiency is more sensitive to the injection foam quality fg for dry foams, compared to wet foams. This proves how important bubble-population-balance modeling is to predict gas mobility reduction as a function of Qt and fg. Third, the graphical approach demonstrates how to determine the optimum injection condition and how such an optimum condition changes at different field operating conditions and limitations (i.e., communication through shale layers, limited carbon dioxide (CO2) supply, cost advantage of CO2 compared to surfactant chemicals, etc.). For example, the scenario with noncommunicating shale layers predicts the maximum sweep of 49% at fg = 55% at high Qt, while the scenarios with communicating shale layers (with 0.1-md permeability) predicts the maximum sweep of only 40% at fg = 70% at the same Qt. The use of this graphical method for economic and business decisions is also shown, as an example, to prove the versatility and robustness of this new technique.

The utilization of Surfactant on enhanced oil recovery chemical injection to maintain energy in Indonesia

The needs of oil in the world for the transportation, industry, power plant and other fields drive us to be more consumptive in the utilization. Oil needs in Indonesia that keeps on increasing along the years is unequal with the number of oil exploration activity, which further create a scarcity on fossil energy fuel source availability. If Indonesia is unable to discover new oil sources as soon as possible, Indonesia is predicted to become oil importer in 2025. Oil production is known to be practiced through three steps which are primary recovery, secondary recovery, and tertiary recovery. At this moment, several oil wells in Indonesia have reached final stages of secondary recovery. If the production activity on these wells is continued, the recovered oil will never be able to reach optimum result and will unable to cover the production cost. Because of that, oil development and production management projects will never be able to run. The offered solution to fulfill this energy needs is by conducting tertiary recovery method known as Enhanced Oil Recovery (EOR). EOR method is known to be able to optimize oil recovery as much as 30% of total remaining reserve on an oil or gas field. One of EOR method that will be the focus in this research is chemical injection or chemical flooding, where a certain chemical compound is injected into the reservoir with an objective of reservoir physical or chemical manipulation to facilitate oil production to the surface. The material required for chemical flooding are surfactant, alkali, and polymer. On the previously conducted research at EOR Laboratory Universitas Trisakti is aimed to observe the impact of surfactant concentration on water formation salinity on phase and interfacial tension (IFT) tests to improve surfactant performance on EOR process to optimize recovery factor (RF) or oil production. Chemical ingredients used in this research are anionic surfactants which are Alpha Olein Sulfonate (AOS) and paraffin oil. The utilization of surfactant solution concentration is 0.5%, 1%, 1.5% and 2%. Meanwhile formation salinities are at 10,000 ppm, 15,000 ppm, and 20,000 ppm. The emulsion formed from the phase test is an upper phase. The factor of emulsion phase formation is high interfacial tension and the utilized surfactant basic ingredient is a petroleum based ingredient. The result of IFT measurement on surfactant solution possess a value range of 16 dyne/m to 41 dyne/m. Based on the research result and conducted analysis, the utilized AOS surfactant in this research is proven to be able to lower significant IFT of water and oil on emulsion percentage formed and stable at 18.75% on 1.5% concentration with water salinity of 15,000 ppm.

Hybrid Application of Nanoparticles and Polymer in Enhanced Oil Recovery Processes.

Nowadays, the addition of nanoparticles to polymer solutions would be of interest; however, the feasible property of nanoparticles and their impact on oil recovery has not been investigated in more detail. This study investigates the rheology and capillary forces (interfacial tension and contact angle) of nanoparticles in the polymer performances during oil recovery processes. Thereby, a sequential injection of water, polymer, and nanoparticles; Nanosilica (SiO2) and nano-aluminium oxide (Al2O3) was performed to measure the oil recovery factor. Retention decrease, capillary forces reduction, and polymer viscoelastic behavior increase have caused improved oil recovery due to the feasible mobility ratio of polymer–nanoparticle in fluid loss. The oil recovery factor for polymer flooding, polymer–Al2O3, and polymer–SiO2 is 58%, 63%, and 67%, respectively. Thereby, polymer–SiO2 flooding would provide better oil recovery than other scenarios that reduce the capillary force due to the structural disjoining pressure. According to the relative permeability curves, residual oil saturation (Sor) and water relative permeability (Krw) are 29% and 0.3%, respectively, for polymer solution; however, for the polymer–nanoparticle solution, Sor and Krw are 12% and 0.005%, respectively. Polymer treatment caused a dramatic decrease, rather than the water treatment effect on the contact angle. The minimum contact angle for water and polymer treatment are about 21 and 29, respectively. The contact angle decrease for polymer treatment in the presence of nanoparticles related to the surface hydrophilicity increase. Therefore, after 2000 mg L−1 of SiO2 concentration, there are no significant changes in contact angle.

Styrene intermolecular associating incorporated-polyacrylamide flooding of crude oil in carbonate coated micromodel system at high temperature, high salinity condition: Rheology, wettability alteration, recovery mechanisms

Polymer flooding is one of the most well-known research interests in the enhanced oil recovery (EOR) due to the excess oil production and limited petroleum reserve. Commercial polymers such as polyacrylamide (PAM) and its hydrolyzed form (HPAM) can be easily degraded at high temperature, high salinity, and high shear rate in attempt to the EOR purposes for the harsh reservoir conditions. In this work, a hydrophobically modified copolymer consisting of acrylamide and styrene (HSPAM) was produced via inverse emulsion polymerization as a wettability modifier and viscosifying agent, applicable under harsh reservoir conditions to direct insights into the synergic oil recovery pore scale mechanisms and overcoming the aforementioned challenges through the EOR process. In the first part of this study, a set of analytical techniques including FTIR, NMR, TGA, and molecular weight measurement was carried out, confirming successfully incorporation of styrene monomer in water-soluble skeleton and higher thermal resistivity of HSPAM compared with HPAM. By analyzing the rheological behavior of HSPAM under harsh reservoir conditions, it was found that the viscosity of HSPAM aqueous solution was increasingly influenced by the total dissolved solids, even up to 40,572 mg/L. In the second part, stability tests, contact angle (CA), interfacial tension (IFT), and carbonate coated glass micromodel flooding experiments were conducted by deionized water (DIW), seawater (SW) and formation brine (FB) in the absence and presence of HSPAM and HPAM. HSPAM illustrated a great stability in seawater and formation brine in comparison with HPAM after 120 days at 80 °C. The presence of HSPAM in seawater resulted in a more water-wet state up to 42° compared to HPAM by contact angle of 31° after 72 h. Findings provided synergic oil recovery mechanisms approved by emulsification and coalition phenomena to show a better wettability alteration and IFT reduction for HSPAM in spite of HPAM alongside drastically improving the brine-based flooding performance, yielding an ultimate recovery of about 82% original oil in place (OOIP).

Simulation of Foam Enhanced-Oil-Recovery Processes Using Operator-Based Linearization Approach

SummaryFoam injection is a promising enhanced-oil-recovery (EOR) technology that significantly improves the sweep efficiency of gas injection. Simulation of foam/oil displacement in reservoirs is an expensive process for conventional simulation because of the strongly nonlinear physics, such as multiphase flow and transport with oil/foam interactions. In this work, an operator-based linearization (OBL) approach, combined with the representation of foam by an implicit-texture (IT) model with two flow regimes, is extended for the simulation of the foam EOR process. The OBL approach improves the efficiency of the highly nonlinear foam-simulation problem by transforming the discretized nonlinear conservation equations into a quasilinear form using state-dependent operators. The state-dependent operators are approximated by discrete representation on a uniform mesh in parameter space. The numerical-simulation results are validated by using three-phase fractional-flow theory for foam/oil flow. Starting with an initial guess depending on the fitting of steady-state experimental data with oil, the OBL foam model is regressed to experimental observations using a gradient-optimization technique. A series of numerical validation studies is performed to investigate the accuracy of the proposed approach. The numerical model shows good agreement with analytical solutions at different conditions and with different foam parameters. With finer grids, the resolution of the simulation is better, but at the cost of more expensive computations. The foam-quality scan is accurately fitted to steady-state experimental data, except in the low-quality regime. In this regime, the used IT foam model cannot capture the upward-tilting pressure gradient (or apparent viscosity) contours. 1D and 3D simulation results clearly demonstrate two stages of foam propagation from inlet to outlet, as seen in the computed-tomography (CT) coreflood experiments: weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. OBL is a direct method to reduce nonlinearity in complex physical problems, which can significantly improve computational performance. Taking its accuracy and efficiency into account, the data-driven OBL-based approach could serve as a platform for efficient numerical upscaling to field-scale applications.

Review on chemical enhanced oil recovery: Utilization of ionic liquids and deep eutectic solvents

The increasing demand for oil production requires the extraction of oil obtained from not only primary and secondary stages, but also tertiary recovery methods in order to meet increasing global demand on the power requirement. Therefore, enhanced oil recovery (EOR) is expected to increase their relevance in the coming years. Physical gas injection and thermal methods have been used for EOR for a while; however, due to its limited applicability and high operating cost, chemical-based EOR processes have been considered a promising alternative considering higher efficiency, technical and economic feasibilities, and reasonable capital cost requirements. Therefore, the search and design of new chemical compounds are of pivotal relevance for the oil and gas industry to boost reservoir production. Among the new types of compounds considered for chemical EOR, ionic liquids (IL) and deep eutectic solvents (DES) have gained considerable attention over the last few years. The purpose of this review is to review the database of published work on these compounds and analyze ILs and DESs performance in the EOR process. The possible mechanisms of action of both types of fluids, their suitability, and problems, as well as economic factors, are studied. The details of experimental results on rock wettability, core flooding performance and interfacial tension data for both ILs and DESs have been examined. The pros and cons of these fluids compared to the available traditional chemical enhanced oil recovery methods have been discussed, and the marginal effect on EOR performance via ILs and DESs has been highlighted. Guidelines for designing and developing new ILs and DES for EOR have been provided to obtain more sustainable and environmentally friendly chemicals suitable for EOR operations.

The potential of polymer for enhanced oil recovery process on oil refinery: A literature research

The objective of this research is to obtain evidence that polymer can be utilized as injection fluid in Enhanced Oil Recovery process. Polymer is one of chemical compounds in Chemical Enhanced Oil Recovery (CEOR). The method utilized in this research is reference collection regarding Enhanced Oil Recovery which further observed and reviewed, especially the ones connected with polymer utilization as injection fluid. Polymer injection is a method conducted after primary and secondary recoveries processes. The clearest and most significant mechanism of polymer application is to improve sweep efficiency by decreasing thickness level and improving water injection profile. Polymer injection is a tertiary recovery step, conducted after oil can no longer be produced although the capacity only reaches 60%. This means that there is still 40% of total capacity yet to be produced. This polymer injection is commonly utilized to obtain remaining oil reserve because of its relatively simple application, low cost, and able to produce a relatively large volume of oil reserve.

Preferential imbibition in a dual-permeability pore network

Abstract

Assessment of CO2 capture technologies for CO2 utilization in enhanced oil recovery

AbstractCO2 capture is considered to be a viable means of reducing the harmful environmental impacts of the fossil fuel usage. The net cost of CO2 capture can be reduced and, consequently, the adoption of CO2 capture methods can be enhanced by developing revenue streams for the captured CO2. Enhanced oil recovery (EOR), which is the process of withdrawing crude from oil reservoirs after primary and secondary withdrawal, is viewed as an attractive means of CO2 utilization. The EOR process has the capacity to take large volumes of CO2 captured from power plants and use them for the production of incremental oil. The process which is known as CO2‐EOR has synergistic benefits for the oil and gas and power generation industries. Different CO2 capture technologies are currently being used and their suitability of supplying captured CO2 for utilization in EOR may not be similar. This study analyzes the ease of utilization of CO2 captured from power plants in EOR applications. The analysis is done by comparing different capture technologies in terms of cost and purity of CO2 captured and their suitability of integration with the EOR. The results determine that the post‐combustion CO2 capture is the most EOR friendly technique in terms of CO2 stream purity, while the chemical looping combustion (CLC) is the most EOR amenable in terms of the capture cost. The results show that the CO2 capture efforts from power plants using CLC can be fully covered by additional oil revenue at oil prices above $27.9 per barrel ($175.5/m3). © 2021 The Authors. Greenhouse Gases: Science and Technology published by Society of Chemical Industry and John Wiley & Sons, Ltd.

A Single-Well Gas-Assisted Gravity Drainage Enhanced Oil Recovery Process for U.S. Deepwater Gulf of Mexico Operations

The U.S. Deepwater Gulf of Mexico (DGOM) area that has some of the most prolific oil reservoirs is still awaiting the development of a viable enhanced oil recovery (EOR) process. Without it, DGOM will remain severely untapped. Exorbitant well costs, in excess of $200 million, preclude having extensive injection patterns, commonly used in EOR design frameworks. Aside from injection patterns, even operationally waterflooding has met with significant challenges because of injectivity issues in these over pressurized turbidities. The gas-assisted gravity drainage (GAGD) EOR process, that holds promise for deepwater environments because of lesser injectivity issues, among others, has been adapted in this work to overcome these limitations. A novel design in the form of a single well—gas assisted gravity drainage (SW-GAGD) process, has been demonstrated to emulate the benefits of a GAGD process in a cost-effective manner. Unlike conventional GAGD processes, which need multiple injectors and separate horizontal production wells, the SW-GAGD process just uses a single well for injection and well production. The performance of the process has been established using partially scaled visual glass models based on dimensional analyses for scale up of the process. The recovery factor has been shown to be in the range of 65–80% in the immiscible mode alone, and the process is orders of magnitude faster than natural gravity drainage. A toe-to-heel configuration of the SW-GAGD process has also been tested and for the configuration to be immune from reservoir layering, the toe of the well should ideally end at the top of the payzone. Better sweep of the payzone and consequent high recovery factor of 80% OOIP was observed, if the heel part of the bottom lateral is located in a lower permeability zone.

One-Pot synthesis of modified-cationic surfactants for enhanced oil recovery applications in carbonate reservoirs

In this study two cationic surfactants, dodecyltriethylammoniumbromide (C12TEAB) and hexadecyltriethylammoniumbromide (C16TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C12TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C16TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C12TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C16TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 °C, then the IFT increases with increasing temperature. For C12TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C16TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C12TEAB surfactant, the contact angle varied from 96.4° to 54.5°. In similar study using C16TEAB surfactant the contact angle changed from 92° to 46.1°. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs.

Influence factors on CO2 solubility in cycloalkanes and cycloalkane volume expansion: Temperature, pressure and molecular structure

In CO2 enhanced oil recovery process, the interactions between CO2 and oil components are complex since crude oil is a mixture of n-alkanes, cycloalkanes, aromatics, resin, asphaltene and other compounds. To investigate the effects of temperature, pressure and molecular structure on CO2 solubility in cycloalkanes and the resulting cycloalkane volume expansion, the solubility of near critical and supercritical CO2 in cyclopentane (CP), cyclohexane (CH), methylcyclohexane (MCH), methylcyclopentane (MCP) and ethylcyclohexane (ECH) and the volume expansion factor of cycloalkanes at diverse temperature and pressure were measured. It was observed that increasing temperature decreases CO2 solubility, while CO2 solubility increases with pressure increasing. Compared with CP and CH, it's harder for CO2 to dissolve in their methyl or ethyl substituents. For homologues, CO2 solubility decreases with carbon number increasing. The volume expansion factor and solubility have a same variation tendency with temperature, pressure and molecular structure. The experimental results of solubility were correlated with Fornari's model and PR equation of state with the maximum average absolute relative deviation (AARD) of 2.8% and 6.8%, respectively. The excess molar volume of CO2 + cycloalkane mixtures was calculated to be negative and increases with pressure.

Preliminary feasibility study on using a nano-composition in enhanced oil recovery process: neural network modeling

In the present work, a 5W50 oil as an oil and petroleum derivative is used to check its viscosity behavior after adding nano-compositions to it. Viscosity reduction in an oil derivative after adding a specific mixture of nanomaterials is a trump card in the enhanced oil recovery process. So, a composition of MWCNT and TiO2 nanoparticles with the composition ratio of 2/3 is added to the mentioned oil derivative. Interestingly, a 15% reduction in the viscosity in comparison with the pure oil is observed at a temperature of 45 °C and a concentration of 0.05%. The more viscosity reduction will result in a more significant oil recovery. Hence, satisfactory results of viscosity behavior at 45 °C could keep the scientific groups hopeful to have more viscosity reduction at higher temperatures and especially at oil well temperature. The selected solid volume fraction of 0.05%, as the lowest studied amount, makes the proposed composition more economic and reasonable. The suitable performance of the introduced nano-composition encouraged the present research group to predict its rheological behavior by using the response surface method and artificial neural network.

The effect of middle phase emulsion and interfacial tension of Sodium Lignosulfonate surfactant synthesized from bagasse to Enhanced Oil Recovery

Enhanced Oil Recovery (EOR) is an effort to increase oil recovery after primary recovery and secondary recovery. One method used is chemical injection using surfactants. Sodium Lignosulfonate (SLS) is one of the anionic surfactants commonly used in the EOR process. Sodium Lignosulfonate can be made by bagasse synthesis, as an alternative to the use of lignosulfonate surfactant. The purpose of this study was to determine the effect of the middle phase emulsion and interfacial tension on the recovery factor results. The method used is the core injection. The injection fluid used is Sodium Lignosulfonate surfactant which has been tested for its characteristics. This research uses core flood devices and synthesized Berea cores. Core injection is carried out in several variations of salinity and surfactant concentration. The results of the study show that the largest recovery result is at 1.5% 15000 ppm with a recovery factor of 5.34% where the emulsions are the least among other compositions but the emulsions are stable at 48 hours and the IFT value is also relatively low at 4.34 mN/m. The lowest recovery results are at 1.5% 4000 ppm with a recovery factor of 3.24% where the emulsions are highest but the emulsions are stable at 336 hours, and the IFT value is relatively high at 10.40 mN / m. Based on this study it can be concluded that if the middle phase emulsion is quickly stable and the IFT value is low it will result in enhanced oil recovery.

Evaluation of the Effectiveness of Continuous Gas Displacement for EOR in Hydraulically Fractured Shale Reservoirs

SummaryThe main objective of this study is to analyze and describe quantitatively the effectiveness of continuous gas displacement as an enhanced oil recovery (EOR) process to increase production from multifractured shale oil reservoirs. The study uses CH4 continuously injected through horizontal wells parallel to the production wells as the displacement agent and investigates the effects of various attributes of the matrix and of the induced and natural fracture systems.This numerical simulation study focuses on the analysis of the 3D minimum repeatable element (stencil/domain) that can describe a hydraulically fractured shale reservoir under production. The stencil is discretized using a very fine (millimeter-scale) grid. We compare the solutions to a reference case that involves simple depressurization-induced production (i.e., without a gas drive). We monitor continuously (a) the rate and composition of the production stream and (b) the spatial distributions of pressure, temperature, phase saturations, and relative permeabilities.The results of the study indicate that a continuous CH4-based displacement that begins at the onset of production does not appear to be an effective EOR method for hydraulically fractured shale oil reservoirs over a 5-year period in reservoirs in which natural or induced fractures in the undisturbed reservoir and/or in the stimulated reservoir volume (SRV) can be adequately described by a single-medium porosity and permeability. Under these conditions in a system with typical Bakken or Eagle Ford matrix and fracture attributes, continuous CH4 injection by means of a horizontal well parallel to the production well causes a reduction in water production and an (expected) increase in gas production but does not lead to any significant increase in oil production. This is attributed to (a) the limited penetration of the injected gas into the ultralow-k formation, (b) the dissolution of the injected gas into the oil, and (c) its early arrival at the hydraulic fracture (HF; thus, short circuiting the EOR process by bypassing the bulk of the matrix), in addition to (d) the increase in the pressure of the HF and the consequent reduction in the driving force of production and the resulting flow. Under the conditions of this study, these observations hold true for domains with and without an SRV over a wide range of matrix permeabilities and for different lengths and positions (relative to the HF) of the gas injection wells.

Investigating the Effect of Wettability on Sand Production in the Presence of Smart Water and Smart Nanofluid: an Experimental Study

In recent years, research activity to increase oil recovery from hydrocarbon reservoirs by smart water (SW) injection has risen sharply. Smart water injection is one of the most efficient and low-cost methods in the improved and enhanced oil recovery (IOR/EOR) process. One of the active mechanisms of smart water to increase the oil production is wettability alteration of the rock surface from oil-wet to water-wet conditions. Recently smart water injection into unconsolidated sandstone reservoirs due to disturbance of the rock surface equilibrium causes instability of formation particles and sand production. One of the main factors disturbing the equilibrium and sand production is the sandstone surface's wettability alteration mechanism caused by disjoining pressure and stresses on the rock surface. Reduction of the reservoir permeability and closure of fluid flow paths and consequent reduction of oil production are among the main damages of sand production. In this study, a complete study on optimum smart water design based on the least sedimentation due to mixing has been done by formation water compatibility tests and analysis on divalent ions through the Taguchi design. Then the water wet sandstones were converted to oil-wet condition by model oil (stearic acid + normal heptane) in different concentrations. The wettability effect of water wet, neutral wet oil-wet on the amount of sand production in the presence of smart water in the reservoir conditions was fully investigated. To prevent sand production, a very effective chemical method of nanoparticles was used. By stabilizing silica nanoparticles (SiO2) with an optimum concentration of 2000 ppm in smart water (pH = 8), according to the results of the zeta potential and Dynamic light scattering (DLS) test, the effect of wettability on sand production in the presence of smart nanofluid was fully investigated. The test results show a significant reduction in sand production and a rapid wettability alteration towards smart nanofluids' water-wet conditions. This indicates the improvement of fluid for enhanced oil recovery processes in unconsolidated sandstone reservoirs.

A model for interpretation of nanoparticle-assisted oil recovery: Numerical study of nanoparticle-enhanced spontaneous imbibition experiments

Oil-wet reservoirs suffer from an incomplete oil recovery. It is possible to use nanoparticles (NPs) to alter the reservoir rock wettability to a more water wet condition, and thus increase and accelerate oil recovery. Numerous experimental studies reported the proper potential of NPs as an oil recovery agent. In addition, several modeling studies investigated the physics of nanoparticle injection into porous media. However, rarely the proposed models were validated using experimental nanoparticle-assisted oil recovery data. This paper introduces a novel workflow to interpret nanoparticle-enhanced oil recovery processes. The workflow uses a dynamic wettability alteration approach to mimic the transition of the rock wettability from an oil-wet condition to a more water-wet condition. This approach implements a concentration dependent weighting factor, which updates residual oil saturation, capillary pressure and relative permeabilities at each grid block in different time steps.The model equations are solved numerically using a finite difference scheme. Afterwards, the numerical model is implemented to interpret a series of nanoparticle-assisted spontaneous imbibition experiments. An excellent agreement between numerical and experimental results is achieved, which verifies the performance of the proposed workflow. The results reveal that the presented approach is valid enough to be used for the modeling of nanoparticle-assisted oil recovery processes. In conclusion, the findings of this study could provide a better understanding of the performance of nanoparticles in both forced and spontaneous enhanced oil recovery processes.

A New Way of Compositional Simulation without Phase Labeling

SummaryCurrent relative permeability models rely on labeling a phase as “oil” and “gas” and cannot therefore capture accurately the effect of compositional variations on relative permeabilities and capillary pressures in enhanced oil recovery processes. Discontinuities in flux calculations caused by phase labeling problems not only cause serious convergence and stability problems but also affect the estimated recovery factor owing to incorrect phase mobilities.We developed a fully compositional simulation model using an equation of state (EoS) for relative permeabilities (kr) to eliminate the unphysical discontinuities in flux functions caused by phase labeling issues. The model can capture complex compositional and hysteresis effects for three-phase relative permeability. Each phase is modeled separately based on physical inputs that, in part, are proxies to composition. Phase flux calculations from one gridblock to another are also updated without phase labels. The tuned kr-EoS model and updated compositional simulator are demonstrated for simple ternary cases, multicycle three-phase water-alternating-gas (WAG) injection, and three-hydrocarbon-phase displacement with complex heterogeneity. The approach improves the initial estimates and convergence of flash calculations and stability analyses, as well as the convergence in the pressure solvers. The new compositional simulator allows for high-resolution simulation that gives improved accuracy in recovery estimates at significantly reduced computational time.