Chemical Enhanced Oil Recovery Processes Research Articles

Adsorption reduction of a gemini surfactant on carbonate rocks using formic acid: Static and dynamic conditions

Surfactant flooding improves oil recovery by lowering the interfacial tension and/or altering the reservoir rock’s wettability. However, surfactant losses caused by adsorption on the surface of the rock weaken the efficiency of this chemical enhanced oil recovery process. This study focuses on reducing the adsorption of a cationic gemini surfactant on carbonate rocks using formic acid. High-performance liquid chromatography integrated with an evaporative light scattering detector was employed to quantify both static and dynamic surfactant adsorptions. The results showed that the surfactant’s adsorption on carbonate rocks was reduced dramatically by adding 1% formic acid to the surfactant solution. Static adsorption was reduced from 2.44, 1.62, and 1.51 mg/g-rock to 0.16, 0.14, and 0.13 mg/g-rock on Guelph dolomite, Guff dolomite, and Indiana limestone, respectively. The dynamic adsorption of the surfactant on Indiana limestone was reduced from 0.269 to 0.041 mg/g-rock. It is believed that the carboxyl group released by the formic acid-rock reaction shields the surfactant from the rock surface resulting in lower adsorption. This is evidenced by the surfactant solution’s pH dropping below the point of zero charge of the rock, causing the repulsion of the cationic surfactant molecules off the surface. This study provides a low-cost option that provides a remarkable reduction in cationic surfactant adsorption on carbonate rocks.

Static adsorption of a novel cationic gemini surfactant: A mineralogical study

Surfactants are deemed as an advantageous chemical in enhanced oil recovery (EOR) because of their potential of lowering the interfacial tension and modifying the wettability. However, the surfactant loss by adsorption on the rock surface is one of the major shortcomings of surfactant-based flooding techniques. The static adsorption of an in-house synthesized cationic gemini surfactant (GS12) is investigated as a function of mineral type, salinity, and concentration. Both clay and non-clay minerals have been examined. Surfactant adsorption was increased continuously by the increase of concentration till 1000 ppm and then an adsorption plateau was observed in all minerals except montmorillonite and kaolinite. It was found that clay minerals may cause more detrimental effects as compared to silicate minerals and carbonate minerals showed the least adsorption. The maximum amount of surfactant adsorbed on the mineral surface was in the order of montmorillonite > kaolinite > illite > K-feldspar > quartz > dolomite > calcite. Lower adsorption of GS12 was detected because of the presence of multivalent ions (Ca2+ and Mg2+). Methylene blue (MB) has been revealed as a novel adsorption inhibitor for cationic GS12 on various minerals. MB adsorbs on the negative binding sites of both clay and non-clay minerals. Therefore, an electrostatic repulsion takes place between the cationic dye (MB) and cationic GS12, leading to the reduction of GS12 adsorption on the mineral surface. Only the addition of 100 ppm of MB in the surfactant solution at the highest concentration (1500 ppm) reduced GS12 adsorption on quartz surface to 0.67 mg/g-rock. This study will help in designing the chemical EOR process using GS12 on carbonate formation containing silica and clay minerals as impurities.

A Perspective Review on the Current Status and Development of Polymer Flooding in Enhanced Oil Recovery Using Polymeric Nanofluids

The globally increasing demand for crude oil has prompted the oil industry to enhance oil production from primary, secondary, and tertiary recovery methods to fulfill the global requirement. Therefore, enhanced oil recovery (EOR) is expected to increase its importance in the coming years. Because of limited efficiency, applicability, and higher gas and thermal injection costs, chemical EOR processes have been considered as an alternative in some special cases. Chemical EOR processes are accepted widely because of their higher efficiency, economic and technical feasibility, and optimum capital cost. Therefore, research of novel chemical compounds is immense in the oil industry. Research of nanotechnology in the petroleum industry has attracted attention among all novel chemical compounds in the past few years. This work focuses on the review of previous research regarding the current scenario of polymer flooding, challenges of polymer flooding, polymeric nanofluid in EOR, recent developments in polymer flooding, characteristics of polymeric nanofluids, prospects, and economic feasibility for polymeric nanofluids’ applications in EOR. This paper also reviews the characterization of polymeric nanofluids such as rheology, stability, wettability alteration, interfacial tension reduction, and absorption control. It has been found from a literature review that polymeric nanofluids are more effective in oil recovery considering viscosity modification, stability enhancement, and chemical adsorption control. Oil recovery can be additionally increased by up to 10–15% original-oil-in-place applying polymeric nanofluids.

Adsorption of surfactant during chemical enhanced oil recovery

AbstractSurfactant is extensively used as chemicals during chemical enhanced oil recovery (CEOR) process. Effectiveness of surfactant CEOR process depends on several parameters like formation of micro emulsion, ultra‐low interfacial tension (IFT) and adsorption of surfactant. First two parameters enhance the effectiveness while the last parameter reduces the effectiveness. Micro emulsions are highly desirable for CEOR due to its low interfacial tension (IFT) value and higher viscosity. In this research the size of the emulsions were studied with particle size analyzer to study the liquid–liquid absorption process and the entrapment of oil drops inside surfactant drop. Initially, the average surfactant drop size was found to be 100 nm, after mixing the surfactant slug with reservoir crude, the size was increase up to 10 times. It signifies the formation of micro emulsion between surfactant and oil. Another attempt was done in this research to study the adsorption mechanism of surfactant on reservoir rock. The process of adsorption was studied by Langmuir and Freundlich isotherm to understand the adsorption phenomena. In this study, it was found that the adsorption follows Freundlich isotherm and the adsorption phenomena was chemical for surfactant flooding process. In chemical adsorption phenomena, the rate of adsorption is high because, surfactant molecules are adsorbed layer after layer by the rock surface. Use of alkali along with surfactant reduces adsorption of surfactant since, alkali blocked the active clay sites before interacting with surfactant and hence the adsorption isotherm was found to be Langmuir and phenomena was physical adsorption.

Decoding the Impact of Injection-Induced Fractures on the Sweep Efficiency of a Mature Polymer Flood through Pressure Falloff Analysis

Summary Polymer flooding is one of the most popular chemical enhanced oil recovery processes in the world, with many large-scale commercial field implementations. It improves mobility ratio and sweep efficiency over waterflooding. However, injection of high volumes of viscous fluid at high injection pressures almost inevitably induces fractures. Induced fractures are not necessarily negative for the flood, and they are documented to improve injectivity and reduce shear degradation of polymer. The big question is on their effect on areal and vertical sweep efficiency. Mangala is one of the largest and most commercially successful polymer floods in the world. The FM-1 unit has the highest stock tank oil initially in place among all the layers of Mangala. Polymer flood sweep efficiency in FM-1 is excellent despite the presence of injection-induced fractures and geological layering. Pressure falloff (PFO) studies are an important and inexpensive source of monitoring the growth of induced fractures in mature polymer floods. Extensive work has been done in the past to derive analytical solutions and numerically assisted solutions for polymer PFOs for non-Newtonian rheology and induced fractures with variable storage. There is also extensive and sometimes contradictory literature on polymer rheology in porous media at both high and low flux rates. Most of the work on polymer PFOs have published a few field examples or synthetic examples and addressed specific issues in depth. We have interpreted 40 PFOs carried out over a period of 1 year. All relevant data sources in the field on geomechanics, polymer rheology in core and rheometers, temperature logs, and saturation logs were integrated to get a consistent estimate for fracture half-length. The results provide insight into the role of induced fractures in improving the sweep efficiency of FM-1. The arguments are backed with literature survey. The work can be used by operators around the world to manage mature polymer floods. The observations mentioned in the work can be used by researchers to fine tune their work. Secondary hypothesis on polymer rheology in porous media is also derived out of the work, which may be of academic interest and merit further work. There are other important aspects of polymer flood PFOs, such as impact of suspended solids and rock dilation near wellbore, which have not been explored in the paper.

A review of fluid displacement mechanisms in surfactant-based chemical enhanced oil recovery processes: Analyses of key influencing factors

Surfactant-based oil recovery processes are employed to lower the interfacial tension in immiscible displacement processes, change the wettability of rock to a more water-wet system and emulsify the oil to displace it in subsurface porous media. Furthermore, these phenomena can reduce the capillary pressure and enhance spontaneous imbibition. The key factors affecting such immiscible displacement process are temperature, salinity and pH of the fluids, surfactant concentration and adsorption. Therefore, before any surfactant flooding process is applied, extensive studies of fluid-fluid and rock-fluid interactions are needed. The use of other chemicals along with surfactants in chemical enhanced oil recovery (cEOR) processes have been widely considered to exploit the synergy of individual chemicals and complement the weakness arises from each of them during immiscible displacement of fluids in porous media. Therefore, such combinations of chemicals lead to alkaline-surfactant (AS), surfactant-polymer (SP), alkaline-surfactant-polymer (ASP), and nanoparticle-surfactant (NS) flooding processes, among others. In this review study, we categorised the role and displacement mechanisms of surfactants and discussed the key factors to be considered for analysing the fluid displacement in porous media.

Application of α-MnO2 nanoparticles for residual oil mobilization through surfactant polymer flooding.

Injection of surfactant and polymer slug is among the most effective chemical enhanced oil recovery processes. The only problem encountered with the surfactant polymer (SP) flooding is the loss of surface-active agents that reduce the efficiency of surfactants in the chemical slug. Various attempts to modify SP flooding have been made previously so that the surfactant loss due to adsorption could be reduced. Nanoparticles (NPs) are one of the most effective ways of reducing surfactant adsorption as surfactant particles are held in the liquid phase by nanoparticles, resulting in lower surfactant losses due to adsorption. However, the high cost of the NPs limits their use on the field scale. To encounter this problem, the present study focuses on the application of the manganese dioxide NPs, synthesized through a green route that is economically viable. These NPs are found to be cost-effective as compared to commercially available NPs as well as the synthesis of these NPs does not require the use of toxic chemicals. The 1000ppm NPs effectively reduced the surfactant adsorption by 46%. The surface tension was lowered from 29.4 to 26.1 mN/m when 1000ppm NPs were applied to 2500ppm surfactant solution. Also, the nanoparticles were found to increase the viscosity of the chemical slug by increasing the solid particles present in the slug. The sand pack flooding experiments were carried out to assess the crude oil mobilization ability of the NPs assisted SP flooding. The oil recovery was found to increase from 5% of the original oil in place, resulting in ~ 75% of the crude oil recovery, which was only ~ 70% when NPs were not introduced into the system.

Comprehensive Review on the Role of Surfactants in the Chemical Enhanced Oil Recovery Process

With a constant upsurge in energy demand, production from depleted and harsh reservoirs through enhanced oil recovery techniques (EOR) has significantly increased. Among many EOR techniques, chemical EOR (cEOR) is one of the most widely used methods of oil extraction. Surfactants used in cEOR are instrumental in reducing interfacial tension (IFT) and altering the wettability of rock, which leads to additional oil recovery. This review draws attention to detail on surfactants from fundamentals to field scale. Properties of surfactants like phase behaviors, critical micelle concentration (CMC), hydrophilic–lipophilic balance and deviation, zeta potential, and their importance are discussed in depth. The presence of a saline environment, polymer, cosurfactant, and other factors affecting the performance of surfactant during the cEOR process are also elaborated. Key findings on surfactant adsorption on reservoir rock with other influencing aspects have also been reported in this study. Types of surfactants, from basic to the likes of polymeric, viscoelastic, Gemini, natural, and their effects on oil recoveries have been analyzed and compared. Special emphasis on emerging aids for surfactant flooding such as applications of nanotechnology, use amphoteric Janus particles, and synergies of surfactant–low salinity water flooding, along with their mechanisms and recent advances have been thoroughly duscussed. Lastly, the review delineates discerning criteria for the selection of surfactants, reviews recent field applications, and outlines the challenges that the industry faces while implementing surfactant cEOR. It has been found that exhaustive studies have been conducted on sandstones with success. However, extreme temperature and saline conditions in the case of carbonate reservoirs limit the applicability of surfactants, and the pursuit to accomplish its efficacy continues.

Effect of capillary pressure parameter and volume fraction of nanoparticles on EOR process in a 3D geometry

Significant influence of nanoparticles on increasing oil recovery rate in Chemical Enhanced Oil Recovery process has been confirmed in several experimental studies. In the modeling, the changes in reservoir porosity and permeability were investigated. Using a number of modeling and experimental studies, some thermophysical properties of nanofluids including viscosity and fluid density were also calculated. The results of this study can be used to create a saturation profile over time in 3D. Also, the effect of capillary pressure parameter and volume fraction (VF) of nanoparticles on the efficiency of oil extraction from porous medium (PM) was investigated. The results indicate that the capillary pressure parameter, although accelerating the process of oil recovery from the PM, however, when this parameter is large, the amount of saturated oil remaining in the medium is ultimately higher which has opposite impact on the Enhanced oil recovery (EOR) process using nano-flooding. However, increasing the VF concentration of the nanoparticles, despite its effect on the reduction of porosity and absolute permeability of the reservoir, based on the results of the model, has a positive effect on the oil recovery from the PM, reducing the residual of the saturated oil in the medium.

A Selection Flowchart for Micromodel Experiments Based on Computational Fluid Dynamic Simulations of Surfactant Flooding in Enhanced Oil Recovery

A selection flowchart that assists, through Computational Fluid Dynamics (CFD) simulations, the design of microfluidic experiments used to distinguish the performance in Chemical Enhanced Oil Recovery (CEOR) of two surfactants with very similar values of interfacial tension (IFT) was proposed and its use demonstrated. The selection flowchart first proposes an experimental design for certain modified variables (X→: porosity, grain shape, the presence of preferential flowing channels, and injection velocity). Experiments are then performed through CFD simulations to obtain a set of response variables (Y→: recovery factor, breakthrough time, the fractal dimension of flow pattern, pressure drop, and entrapment effect). A sensitivity analysis of Y→ regarding the differences in the interfacial tension (IFT) can indicate the CFD experiments that could have more success when distinguishing between two surfactants with similar IFTs (0.037 mN/m and 0.045 mN/m). In the range of modifiable variables evaluated in this study (porosity values of 0.5 and 0.7, circular and irregular grain shape, with and without preferential flowing channel, injection velocities of 10 ft/day and 30 ft/day), the entrapment effect is the response variable that is most affected by changes in IFT. The response of the recovery factor and the breakthrough time was also significant, while the fractal dimension of the flow and the pressure drop had the lowest sensitivity to different IFTs. The experimental conditions that rendered the highest sensitivity to changes in IFT were a low porosity (0.5) and a high injection flow (30 ft/day). The response to the presence of preferential channels and the pore shape was negligible. The approach developed in this research facilitates, through CFD simulations, the study of CEOR processes with microfluidic devices. It reduces the number of experiments and increases the probability of their success.

Clay Analysis of Upper Assam Basin for Chemical Enhanced Oil Recovery

The success and failure of different chemical enhanced oil recovery (CEOR) techniques can control to a large extent by the presence of different types of clay, its surface area and the reactivity of the clay with the injected chemicals during CEOR techniques. Therefore, reservoir clay analysis is important to study the CEOR process in general and to formulate the CEOR slug in particular. This study pertains to the underground porous media of upper Assam basin. In this paper effective porosity, absolute permeability, minerals and clays present in porous media is studied. Effective porosities were determined to estimate the total pore volume and more importantly the connecting pores and the throat volumes. The absolute permeability are exclusively the properties of the porous media, which determines the ease of flow of fluid through the porous media. Rock petrography study was done by examining the thin sections under optical microscope, Scanning Electron Microscope (SEM) and X-ray Diffractometer (XRD). From these studies the mineral and clay content of the reservoir was characterized, which helps to study the feasibility of a CEOR in upper Assam basin. This petrography study provides two and three dimensional accurate description of minerals of reservoir rock and clay particles. The porous media is a sandstone with high porosity and low absolute permeability. The clays present are smectite, kaolinite and illite with a dominance of smectite and kaolinite, conforming to the swelling and disintegration.

Double-Chain Single-Head modification of extracted saponin from Anabasis Setifera plant and its effects on chemical enhanced oil recovery process by surfactant-alkali slug injection into carbonate oil reservoirs

Recently, several studies have dealt with the use of plant-derived surfactants in chemical water injection into oil reservoirs as a main method of Enhanced Oil Recovery (EOR). Some of the advantages of using them in comparison with using expensive chemical surfactants are being environmentally friendly, cheap and available. There are plenty of plants that could be employed as sources of natural surfactants owing to the saponin in their tissues. Even though the plants extracts have weaker performances than engineered surfactants in reducing Interfacial Tension (IFT), synthesizing and modifying the structure of the saponin of these plants can increase its surface activity and result in the optimal values of EOR parameters. The current work was conducted to modify the structure of the saponin of Anabasis Setifera plant through esterification as Double-Chain Single-Head. Thermal Gravimetric Analysis (TGA), Proton Nuclear Magnetic Resonance (1H NMR), and Fourier-Transform Infrared Spectroscopy (FTIR) were performed for temperature stability analysis and characterization. Surface tension experiments were performed in order to estimate the Critical Micelle Concentration (CMC) of the modified surfactant. Additionally, to prove the surfactant performance in EOR process, we did IFT and oil drop Contact Angle (CA) tests, evaluation of the salinity effects of Formation Water (FW), and various salts on IFT, CA, and flooding with optimum fluid in a carbonate plug. The results indicate low-IFT creation at CMC, carbonate rock wettability alteration to moderate wettability, and an increase in the oil recovery factor of about 19% in surfactant-alkali slug injection at optimal alkali and salinity conditions.

Surfactant-Polymer Interactions in a Combined Enhanced Oil Recovery Flooding

The traditional Enhanced Oil Recovery (EOR) processes allow improving the performance of mature oilfields after waterflooding projects. Chemical EOR processes modify different physical properties of the fluids and/or the rock in order to mobilize the oil that remains trapped. Furthermore, combined processes have been proposed to improve the performance, using the properties and synergy of the chemical agents. This paper presents a novel simulator developed for a combined surfactant/polymer flooding in EOR processes. It studies the flow of a two-phase, five-component system (aqueous and organic phases with water, petroleum, surfactant, polymer and salt) in porous media. Polymer and surfactant together affect each other’s interfacial and rheological properties as well as the adsorption rates. This is known in the industry as Surfactant-Polymer Interaction (SPI). The simulations showed that optimum results occur when both chemical agents are injected overlapped, with the polymer in the first place. This procedure decreases the surfactant’s adsorption rates, rendering higher recovery factors. The presence of the salt as fifth component slightly modifies the adsorption rates of both polymer and surfactant, but its influence on the phase behavior allows increasing the surfactant’s sweep efficiency.

Development of a compositional reservoir simulator for chemical enhanced oil recovery processes

To make decisions and ensure successful field development, oil companies use numerical simulation tools, including hydrodynamic simulators. This work is devoted to the development of a reservoir simulator based on a new formulation of partial differential equations of the chemical compositional model, as well as its testing by comparing the results of traditional and ASP flooding simulation with similar results of well-known simulators.

Application of Fractional Flow Theory for Analytical Modeling of Surfactant Flooding, Polymer Flooding, and Surfactant/Polymer Flooding for Chemical Enhanced Oil Recovery

Fractional flow theory still serves as a powerful tool for validation of numerical reservoir models, understanding of the mechanisms, and interpretation of transport behavior in porous media during the Chemical-Enhanced Oil Recovery (CEOR) process. With the enrichment of CEOR mechanisms, it is important to revisit the application of fractional flow theory to CEOR at this stage. For surfactant flooding, the effects of surfactant adsorption, surfactant partition, initial oil saturation, interfacial tension, and injection slug size have been systematically investigated. In terms of polymer flooding, the effects of polymer viscosity, initial oil saturation, polymer viscoelasticity, slug size, polymer inaccessible pore volume (IPV), and polymer retention are also reviewed extensively. Finally, the fractional flow theory is applied to surfactant/polymer flooding to evaluate its effectiveness in CEOR. This paper provides insight into the CEOR mechanism and serves as an up-to-date reference for analytical modeling of the surfactant flooding, polymer flooding, and surfactant/polymer flooding CEOR process.

Comprehensive Investigation of Dynamic Characteristics of Amphoteric Surfactant-Sulfonated Polymer Solution on Carbonate Rocks in Reservoir Conditions.

To recover the remaining oil after water flooding, amphoteric surfactant–sulfonated polymer (S-P) flooding has attracted attention as a tertiary oil recovery technique. Oil recovery by S-P flooding not only is influenced by reservoir heterogeneity but also depends on chemical adsorption and interactions of S-P solution with the surface of rocks. This paper presents comprehensive laboratory results related to the dynamic adsorption, resistance factor (RF), residual resistance factor (RRF), and adsorbed layer thickness of S-P solution on the surface of carbonate rocks. Three core flooding experiments were conducted. The S-P solution was composed of an amphoteric surfactant (0.2 wt %) and sulfonated polymer solution (0.2 wt %) in seawater. The S-P solution was injected until the effluent concentration reached the inlet concentration. Seawater was injected after S-P injection to displace S-P solution until the effluent concentration reduced to a minimum value or constant value for desorption study. Total organic carbon (TOC) and Hyamine methods were used to determine the adsorption of the polymer and surfactant, respectively. The individual amount of dynamic adsorption and the total amount of adsorption of S-P solution onto carbonate rock were determined and compared with the results of single adsorption of a surfactant solution published previously. The residual resistance factor, resistance factor, and adsorbed layer thickness of S-P solution on carbonate rocks were calculated based on the differential pressure before and after injecting the S-P solution. We found that the dynamic adsorption, RF, RRF, and adsorbed layer thickness of the S-P solution strongly depends on pore geometry or reservoir properties. Some of the relationships are proposed for the first time. The loss of injectivity and liquid permeability during S-P solution injection are evaluated in detail in this paper. This paper presents insights into the dynamic adsorption, residual resistance factor, resistance factor, adsorbed layer thickness, and injectivity of S-P solution on carbonate rocks with reservoir parameters, which could help in designing the chemical enhanced oil recovery process in carbonate reservoirs.

Overcoming Challenges in Chemical EOR During Polymer Breakthrough

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194689, “Challenges in Selection and Use of Production Chemicals With Chemical EOR Operations During Polymer Breakthrough Phase,” by Robert Zagitov, Panneer Selvam Venkat, and Ravindranthan Kothandan, Cairn Oil and Gas, et al., prepared for the 2019 SPE Oil and Gas India Conference and Exhibition, Mumbai, 9-11 April. The paper has not been peer reviewed. In chemical enhanced oil recovery (EOR), challenges are expected regarding production chemistry and production-facilities operations. Partially hydrolyzed polyacrylamide (HPAM) is used widely for controlling mobility ratios. Complex in water chemistry and rich in positively charged divalent ions, flooded polymer, having a negative charge, interacts with divalent ions of produced water (PW). The complete paper discusses the importance of adequate preparation and the approaches used to overcome challenges of EOR operations, including handling back-produced polymer. Introduction The Mangala field in northwest India, discovered in January 2004, is part of the Barmer Basin. The primary reservoir unit in this field is the Fatehgarh group, a high-quality quartzose sandstone reservoir having high net-to-gross ratio, high porosity (21-28%), and multidarcy permeability (200 millidarcy to 20 darcy) with an average permeability of approximately 5 darcy. The reservoir contains waxy crude with gravity ranging from 20 to 28 °API. A primary recovery efficiency of less than 10% stock-tank oil initially in place is estimated on the basis of simple depletion; thus, the base field-development plan envisaged implementation of waterflooding from the start of production to maintain reservoir pressure and sweep reserves. Detailed laboratory studies have established that aqueous-based chemical EOR processes are best suited for these viscous oil fields. Full-field polymer flooding has been implemented in the Mangala field, with an injection at the time of writing of nearly 400,000 B/D of polymerized injection water (IW) with average polymer concentration of approximately 2,500 ppm. HPAM is mixed with source water to create a mother solution of 15,000-ppm concentration at a central polymer facility and is distributed through a pipeline network to 15 well pads, where it is diluted with IW to achieve a viscosity of approximately 30 cp for injection. Artificial lift is achieved either by jet pump or electrical submersible pump. Average water cut is 80% at the time of writing.

Numerical evaluation of a combined chemical enhanced oil recovery process with polymer and nanoparticles based on experimental observations

Polymer flooding is the most widely implemented chemical enhanced oil recovery (CEOR) process. However, polymer degradation, caused by chemical, thermal, and mechanical stresses, is still the most notable limitation on the implementation of the technology at the field scale. Recent studies have shown that the addition of nanoparticles in a traditional polymer flooding can improve operating conditions and hydrocarbon production. Thus, a comprehensive numerical simulation study is presented to model the performance of the co-injection of polymers with nanoparticles in oil reservoirs. An articulated process was followed to take into account most of the physical and chemical mechanisms of the technique. Initially, a conceptual model was developed by identifying relevant mass transport and surface mechanisms, and their dynamics. The following phases are accounted in the model: oleic, volatile, and aqueous. Then, local mass balance equations were written for the following components: oil, gas, water, solid nanoparticles and polymers. An extended black-oil model for the hydrocarbon and aqueous phases was used. Constitutive equations were specified for polymer adsorption, rheology, degradation, and nanoparticles retention and remobilization, as well. The numerical strategy was described for numerically solving the Jacobian matrix. The model was subsequently validated in two steps: initially, the simulation results of a polymer flooding are compared to the ones obtained using a commercial software. Then, the nanoparticles transport and retention on the solid matrix was validated with experimental core-flooding tests reported in specialized literature. A set of numerical experiments of the co-injection of polymer-nanoparticles were done, showing that the synergy between both chemical species allowed to retain the viscoelastic network, which considerably improves operational and production parameters. This investigation provides a powerful tool for Oil & Gas industry and can be used to design novel CEOR deployment strategies in sandstone reservoirs.

Comparison of Chemical-Component Transport in Naturally Fractured Reservoirs Using Dual-Porosity and Multiple-Interacting-Continua Models

SummaryWe propose a workflow to optimize the configuration of multiple-interacting-continua (MINC) models and overcome the limitations of the classical dual-porosity (DP) model when simulating chemical-component-transport processes during two-phase flow. Our new approach captures the evolution of the saturation and concentration fronts inside the matrix, which is key to design more effective chemical enhanced-oil-recovery (CEOR) projects in naturally fractured reservoirs. Our workflow is intuitive and derived from the simple concept that fine-scale single-porosity (SP) models capture fracture/matrix interaction accurately; it can hence be easily applied in any reservoir simulator with MINC capabilities. Results from the fine-scale SP model are translated into an equivalent MINC model that yields more accurate results compared with a classical DP model for oil recovery by spontaneous imbibition; for example, in a water-wet (WW) case, the root-mean-square error (RMSE) improves from 0.123 to 0.034. In general, improved simulation results can be obtained when selecting five or fewer shells in the MINC model. However, the actual number of shells is case specific. The largest improvement in accuracy is observed for cases where the matrix permeability is low and fracture/matrix transfer remains in a transient state for a prolonged time. The novelty of our approach is the simplicity of defining shells for a MINC model such that the chemical-component-transport process in naturally fractured reservoirs can be predicted more accurately, especially in cases where the matrix has low permeability. Hence, the improved MINC model is particularly suitable to model chemical-component transport, key to many CEOR processes, in (tight) fractured carbonates.

The effectiveness of computed tomography for the experimental assessment of surfactant-polymer flooding

The Surfactant-Polymer (SP) process is a type of Chemical Enhanced Oil Recovery (CEOR) method. They are still a challenge for the petroleum oil industry mainly because of the difficulty in designing and forecasting the process behavior on the field scale. Therefore, understanding of the phenomena associated with a CEOR process is of vital importance. For these reasons, this work discusses the benefits of Computed Tomography (CT) uses for the experimental assessment of a SP process. The research includes a literature review that allows identifying the main CT usages for petroleum engineering and a discussion concerning the effectiveness of mathematic expressions proposed for the tomography images treatment of two-phase flow displacement. The conducted experimental methodology can be reproduced to assess the benefits of any chemical Enhanced Oil Recovery (EOR) process with CT. Thus, this paper assesses the conventional waterflooding (WF) and SP flooding as secondary and tertiary oil recovery methods. The developed study allowed us to evaluate through CT images the porosity and the saturation profiles along the rock sample. Also, CT processed data enabled checking the volumetric material balance and determine the oil Recovery Factor (RF). The doubled checked SP data showed an RF increase of 17 and 10 percentage points for secondary and tertiary chemical injection schemes respect to conventional waterflooding. Finally, comparative results of the water cut (Wcut) evidenced the mobility ratio improvement and reduction on the remaining oil saturation.