Enhanced Oil Recovery Applications Research Articles

Technology Focus: EOR Operations (June 2023)

While supply disruptions and price volatility are not new to the oil and gas industry, the dramatic drop in oil prices because of the COVID-19 pandemic severely affected global enhanced oil recovery (EOR) projects. To add fuel to the fire, the current geopolitical scenario leading to a surge in commodity prices and supply chain disruptions exacerbated this situation by negating any chances of recovery, at least in the short term. Concurrently, the rise in energy consumption and increasing demand for energy security worldwide warrants the need to increase global hydrocarbon production. However, rising environmental concerns with regard to greenhouse gas emissions, coupled with a decrease in the availability of easy-to-produce hydrocarbon resources, mandate the need for a gradual shift toward optimized recovery strategy in a sustainable and cost-efficient manner. As a result, current circumstances dictate focusing on low-cost and low-carbon EOR barrels to secure energy supply in the shorter term while continuing to develop innovative technologies and strategies for enhancing production in the longer term. Energy consumption for mature waterfloods increases sharply at higher water cuts primarily because of the recirculation of water through the existing swept pathways. Lower volumetric sweep in reservoirs leads to excessive water production and less oil recovery. To curb the menace of excess water production, conventional EOR techniques such as polymerflooding or in-depth conformance-control techniques are mostly implemented. Both methods have demonstrated cost savings because of reduced watercuts and reductions in CO2 generation by lowering reinjection of produced water. Additional costs of injectants, transport, and topside facilities, however, contribute to higher project costs. Early optimization measures for existing waterfloods using machine-learning (ML) approaches could enable optimal reservoir management and production by delineating reservoir heterogeneities more efficiently and predicting more-effective interwell connectivity. Furthermore, ML could contribute directly to the optimization and surveillance of EOR applications, which would subsequently affect the performance and the cost of such projects, thereby supporting the achievement of low-cost and low-carbon EOR barrels. Recommended additional reading at OnePetro: www.onepetro.org. SPE 214268 A Novel Approach To Combine Models To Evaluate Interwell Connectivity in a Waterflooded Reservoir With Limited Injection History by Yanfidra Djanuar, Dragon Oil, et al. SPE 210657 A Laboratory-to-Field Approach and Evaluation of Low-Salinity Waterflooding Process for High-Temperature/High-Pressure Carbonate Reservoirs by Hemanta Kumar Sarma, University of Calgary, et al. IPTC 22733 Like Cures Like Microbial Enhanced Oil Recovery in Biodegraded Crude by Thanapong Ketmalee, PTTEP, et al.

Chitosan derivatives as surfactant carriers for enhanced oil recovery – Experimental and molecular dynamic evaluations of polymer-surfactant interactions

Surfactant injections in enhanced oil recovery (EOR) are very efficient, lowering the oil-water interfacial tension (IFT) and altering rocks wettability. Although efficient, surfactant injection during EOR process is economically unfeasible due to the high-cost caused by surfactant losses due to adsorption or precipitation on the rock surface. One strategy to reduce these losses during the flooding process is using surfactant carriers such as nanoparticles, emulsions, and polymers. Polymers are good candidates because they can act in transportation, alter rock wettability, and improve sweeping efficiency. Recently, the potential of chitosan derivatives as wettability modifiers of carbonate rocks was demonstrated. This way, using chitosan derivatives as surfactant carriers is an interesting strategy due to its high storage capacity and environment-friendly product. In this study, cationized (TMC) and hydrophobized (TMC-C14) chitosan derivatives were synthesized, characterized, and evaluated as OADA (oleic acid diethanolamide) surfactant carriers for EOR. Interfacial tension tests evaluated the potential of OADA in low and high salinity medium. Particle size measurements, done by dynamic light scattering, and molecular dynamics simulations (MD), allowed the understanding of the interaction between TMC or TMC-C14 and the surfactant. The controlled surfactant release at the water/oil interface by chitosan derivatives was evaluated by IFT measurements and MD simulations. The results showed that OADA is an excellent surfactant whose IFT reaches 10−2 mN/m, and chitosan derivatives were able to carry the surfactant to the site containing the oil. Thus, chitosan derivatives are an efficient supramolecular surfactant carrier system that can minimize surfactant losses by adsorption on the rock surface, being an interesting alternative for EOR application.

Interaction of crude oil with halogen-free ionic liquid-based catanionic surfactants

Chemical injection has proved to have superior performance in improving oil recovery. The injected chemicals are typically designed to participate in interfacial interactions at liquid–liquid and rock-liquid interfaces while having minimum adsorption onto the rock surface. This study endeavors to investigate the interfacial activity of several environmentally-friendly halogen-free ionic liquid-based catanionic surfactants synthesized via an ion exchange reaction between cationic imidazolium-based ionic liquids, [Cnmim][Cl] (n = 4,8,12), and anionic surfactants, sodium dodecyl sulfate, sodium dodecylbenzene sulfonate, and dioctyl sodium sulfosuccinate. Results revealed that the catanionic surfactant synthesized with medium-chain ionic liquid (n = 8) and sodium dodecyl sulfate exhibited higher interfacial activity, demonstrating a minimum crude oil-brine interfacial tension of 0.17 mN/m and wettability alteration index of 0.79. The results of the adsorption study also revealed the adsorption density of 2.19 mg/g onto the dolomite surface for 2000 mg/L of catanionic surfactant in seawater, which was considerably lower than cetyltrimethylammonium bromide adsorption (11.55 mg/g) in the control experiment. Finally, the surface energy analysis of liquid-rock interactions was conducted using the concept of work of adhesion to scrutinize the wettability alteration and adsorption processes, where a direct relationship between work of adhesion and adsorption density was proposed. According to the results of this study, medium chain ionic liquid-based catanionic surfactant containing dodecyl sulfate anion, exhibiting excellent interfacial activity and low adsorption tendency onto the dolomite surface, could be considered in future chemical enhanced oil recovery applications.

A comparative investigation of the effect of gas type on foam strength and flow behavior in tight carbonates

Foam generation technique has been practically applied to overcome gas mobility issue during enhanced oil recovery (EOR) processes. Incorporated with the utilized gas, the capability of foaming agent to generate persistent foam determines the flow performance under reservoir conditions. In this study, we first identified the surfactants with excellent phase behavior and foaming properties and, second, evaluated their bulk foam performance with different gases, including N2, CO2, and hydrocarbon gas (CH4) under high-pressure and high-temperature conditions. In bulk, the foam generated with the high-density gas, i.e., CO2, exhibited the greatest foamability but the lowest foam stability. With amidoamine oxide-based surfactant, CH4-foam was found to be more stable than N2-foam, while the opposite was observed for sulfobetaine-based surfactant. The most effective surfactant was later used to perform flow experiments on two tight carbonate rocks, including Minnesota Norther Cream Buff and Edwards limestone, with permeabilities of ∼0.8 and 16 mD, respectively. The core-flooding experiments showed that the optimum quality of CO2-foam was lower than that of N2- and CH4-foams. For a given flow rate and fixed foam quality, the steady-state strength followed the descending order of CH4-, N2-, and CO2-foam. However, in general, the difference in foam strength between N2- and CH4-foams was insignificant when the total flow rate was varied. We also found that the variation in rock permeability had a greater effect on the strength of the CO2-foam compared to those generated with N2 and CH4. In the presence of oil, the shear-thinning behavior of all foams was found more prominent. The increase in oil saturation had a more adverse effect on the strength of N2- and CH4-foams, particularly in the higher permeability rock. The results indicated that the foam strength, which is key in the effectiveness of foam EOR applications, is greatly influenced by several factors such as gas density, gas solubility in water, the presence of oil, and rock permeability.

Production and characterization of a polysaccharide/polyamide blend from Pseudomonas atacamensis M7D1 strain for enhanced oil recovery application

Bio-based polymers have better salt and temperature tolerance than most synthetic polymers. The biopolymer solutions have high viscosity, which can lead to reducing the fingering effect and soaring the oil recovery rate. This work aims to produce and characterize a biopolymer from Pseudomonas Atacamensis M7D1 strain, modify the biopolymer yield using Printed Circuit Boards (PCBs) powder as an outer tension in the growth medium, and finally, evaluate the produced biopolymer function for Enhanced Oil Recovery (EOR) purposes. Using PCBs powder to trigger bacteria for higher production yield increases the biopolymer production rate eleven times higher than pure growth medium without additives. Different analyses were performed on the biopolymer to characterize its properties; Gel Permeation Chromatography (GPC) indicated that the produced biopolymer has an average molecular weight of 3.6 × 105 g/mol. This macromolecule has high thermal resistivity and can tolerate high temperatures. Thermal analysis (TGA/DSC) shows only 69.27 % mass lost from 25 °C to 500 °C. The viscosity of 0.5 wt% biopolymer solution equals 3cp, 3 times higher than water. The glass micromodel flooding result shows that biopolymer solution with 0.5 wt% concentration has a 42 % recovery rate which is 24 % higher than water flooding.

Modeling Viscosity of CO2-N2 Gaseous Mixtures Using Robust Tree-Based Techniques: Extra Tree, Random Forest, GBoost, and LightGBM.

Carbon dioxide (CO2) has an essential role in most enhanced oil recovery (EOR) methods in the oil industry. Oil swelling and viscosity reduction are the dominant mechanisms in an immiscible CO2-EOR process. Besides numerous CO2 applications in EOR, most oil reservoirs do not have access to natural CO2, and capturing it from flue gas and other sources is costly. Flue gases are available in huge quantities at a significantly lower price and can be considered economically viable agents for EOR operations. In this work, four powerful machine learning algorithms, namely, extra tree (ET), random forest (RF), gradient boosting (GBoost), and light gradient boosted machine (LightGBM) were utilized to accurately estimate the viscosity of CO2-N2 mixtures. To this aim, a databank was employed, containing 3036 data points over wide ranges of pressures and temperatures. Temperature, pressure, and CO2 mole fraction were applied as input parameters, and the viscosity of the CO2-N2 mixture was the output. The RF smart model had the highest precision with the lowest average absolute percent relative error (AAPRE) of 1.58%, root mean square error (RMSE) of 2.221, and determination coefficient (R 2) of 0.9993. The trend analysis showed that the RF model could precisely predict the real physical behavior of the CO2-N2 viscosity variation. Finally, the outlier detection was performed using the leverage approach to demonstrate the validity of the utilized databank and the applicability area of the developed RF model. Accordingly, nearly 96% of the data points seemed to be dependable and valid, and the rest of them were located in the suspected and out-of-leverage data zones.

The role of adsorption of a natural surfactant at oil–water interface in enhanced oil recovery: interfacial rheology, and structural, and emulsifying analyses

The enhanced oil recovery (EOR) method is widely used for recovering residual crude oil after implementing conventional oil recovery techniques. Chemical additives, such as surfactants, are considered beneficial for EOR. Their efficacy is assessed based on their ability to reduce interfacial tension, modify wettability, and establish a stable emulsion system. Understanding the mechanism of surfactant adsorption at the oil–water interface is critical for effectively implementing surfactant flooding. In this work, we have studied the adsorption of a natural surfactant synthesized from Eichhornia crassipes at the oil–water interface using numerous interfacial analyses. The results show substantial adsorption at the oil–water interface, indicated by a 27% increase in zeta potential (i.e. −25.2 to −37.2 mV) and ∼27 times increase in film elasticity (i.e. 0.15–4.12 Pa at 0.01 Hz frequency and 0.01% strain). The synthesized natural surfactant demonstrates a noteworthy improvement in the stability of the oil-in-water emulsion and interfacial rheological properties, indicating its potential application in EOR.

Reservoir heterogeneity controls of CO2-EOR and storage potentials in residual oil zones: Insights from numerical simulations

Residual oil zones (ROZs) have large potential for CO2 enhanced oil recovery (EOR) and geologic storage. During CO2 injection, the migration of CO2 in ROZs controls the performance of both EOR and storage. However, it has not been clearly visualized and understood that how geological heterogeneity factors control the transport of CO2 in ROZs. In this study, the oil recovery performance and geologic storage potential during continuous CO2 injection in a representative ROZ are studied based on geostatistical modelling and high-fidelity three-phase flow simulation. We examined the influence of autocorrelation length of permeability, global heterogeneity (Dykstra–Parsons coefficient), and permeability anisotropy on cumulative oil recovery and CO2 retention fraction. Simulation results indicate that, as the permeability autocorrelation length increases, the cumulative oil recovery and CO2 storage efficiency decrease. This results from the accelerated migration of CO2 along high permeability zones (i.e., gas channeling). The increase in global heterogeneity and permeability anisotropies can lead to low oil recovery and poor CO2 sequestration performance, depending on the degree of CO2 channeling. The net utilization ratio of CO2 (CO2 retained/oil produced) unfavorably increases with both autocorrelation length and Dykstra–Parsons coefficient, but decreases with the increase in kv/kh. Such a decrease is attributed to enlarged swept volume induced by gravity override. The study provides important implications for field-scale CO2 EOR and storage applications in ROZs.

Impact of surface-modified silica nanoparticle and surfactant on the stability and rheology of oil-in-water Pickering and surfactant-stabilized emulsions under high-pressure and high-temperature

Emulsions have a wide range of applications, and with the advancement in the use of nanoparticles to form stable Pickering emulsions, it is important to understand their rheological properties to infer their stability under high-pressure and high-temperature (HPHT) compared to the emulsion formed using conventional surfactants. In oil and gas production strategies, oil often forms an emulsion with brine either within reservoirs or at surface facilities in the presence of natural or artificial surfactants. Nanoparticles are also being explored to increase oil recovery from matured reservoirs. In various instances, stable emulsions are either formed in-situ (within the reservoir) or at surface facilities or injected into the reservoir to mobilize the trapped oil. It is also essential to understand their rheology for efficient oilfield application. This study investigates the impact of surface-modified silica nanoparticles (Ludox CL), NaCl salt, and surfactant on the stability of oil-in-water Pickering and surfactant-stabilized emulsions under high-pressure (0.1–10) MPa and high-temperature (303–363) K conditions. The viscosity of emulsion samples was measured at varying shear rates (0.1–1000) s−1. The viscoelastic behavior (G′, G″, η*, and δ) of the Pickering emulsion and surfactant-stabilized emulsion were also measured. The stability of the emulsions was measured in terms of changes in emulsion viscosity and droplet diameter. Both emulsions showed non-Newtonian shear thinning behavior and an increase in droplet diameter under HPHT conditions. However, the surfactant-stabilized emulsion exhibits a greater degree of change in emulsion viscosity and droplet diameter than the Pickering emulsion. It indicates that the Pickering emulsion showed better stability than the surfactant-stabilized emulsion under HPHT conditions. Hence, Pickering emulsions are an incredibly promising tool that might be employed in HPHT applications, especially for enhanced oil recovery applications, due to their better rheological stability.

A-Priori screening of deep eutectic solvent for enhanced oil recovery application using COSMO-RS framework

This study investigates the potential of Deep Eutectic Solvent (DES) in Enhanced Oil Recovery (EOR) via interfacial tension (IFT) reduction mechanism. The effectiveness of 217 DES in the IFT reduction mechanism that ultimately assist in EOR is investigated via COnductor-like Screening MOdel for Real Solvent (COSMO-RS) theory and the sigma moment model. Genetic algorithm (GA) is employed to estimate the constants of COSMO-RS theory and sigma moment model. IFT prediction of representative Omani heavy crude oil in 217 DES in the brine system is reported and analyzed at the mole fraction of DES in brine ranging from 1 × 10-3 to 5 × 10-1 with variation in temperature from 298.15 K to 353.15 K. The highest and the lowest values thus obtained for IFT are 560.8 and 0.2 mN/m. There are 26 DESs capable of reducing IFT by more than 50%, while another 10 DESs show a reduction capability of more than 75%. The optimum concentration of DES to maximize IFT reduction is further analyzed.

Design of injected water salinity for enhanced oil recovery applications in sandstone reservoirs using coupled flow-geochemical simulation

Many previous studies have highlighted the effect of injected fluid salinity on recovery performance and effluent analysis in sandstone reservoirs. However, the complex interactions between the oil, original formation water, injected water, and rocks make capturing all the relevant mechanisms difficult. This paper presents a simulation study where complex mechanisms and interactions are represented, including multiple ion exchange, mineral dissolution, wettability alteration, pH variation, and electrical double layers. The models are used to examine how the salinity of injected water may affect oil recovery and compositions of the effluent fluids. The results show that the wettability changes caused by ion exchange and mineral dissolution/precipitation reactions may strongly affect the recovery performance of low-salinity water injection. In contrast, mineral dissolution/precipitation effects are less significant for high-salinity water injection. In addition, the complex interactions between these processes also affect the pH in the effluent (producing) streams.

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.

Formulation for chemical EOR: Development and evaluation of an ASP formulation In customer field conditions

AbstractAlkali surfactant polymer (ASP) flooding is an enhanced oil recovery (EOR) technology with an impressive potential for increasing incremental oil production from conventional hydrocarbon bearing reservoirs. A challenge to ASP application is the complexity of determining an effective formulation, typically requiring extensive laboratory screening of nearly countless combinations of surfactants and cosolvents. This paper focuses on demonstrating the utility of the hydrophilic–lipophilic deviation (HLD) concept for EOR application to simplify surfactant formulation workstreams seeking an economically viable ASP formulation for field application. In describing work performed for EOR application of ASP under customer conditions using crude oil, the discussion covers the initial evaluation of the promising surfactant formulation (interfacial tension and solubility), the improvement upon the formulation via HLD principles, and the evaluation of the improved surfactant formulation (coreflood studies). The final ASP formulation identified consisted of a 9 to 1 mixture of alkyl propoxy sulfate sodium salt (APS) to alkyl ethoxy sulfate sodium salt (AES) totaling 2000 ppm active surfactant content, 2.0 wt% Na2CO3, and 3000 ppm polyacrylamide polymer (all commercially available products). This formulation had ultra‐low interfacial tension and favorable mixing behavior under reservoir conditions. In coreflood studies, the final formulation reproducibly achieved cumulative oil recovery of 96.4%–98.5% of original oil in place with only 0.3 PV of ASP injection with a chase alkali polymer injection.

A Comprehensive Review on Utilizing Nanomaterials in Enhanced Oil Recovery Applications

Chemicals are a pivotal part of many operations for the oil and gas industry. The purpose of chemical application in the subsurface reservoir is to decrease the mobility ratio between the displaced fluid and the displacing one or to increase the capillary number. These have been the favorable mechanisms for Enhanced Oil Recovery (EOR). Recently, it became a mainstay with EOR researchers looking for effective and efficient materials that can be economically feasible and environmentally friendly. Therefore, when the development of chemicals reached a peak point by introducing nanosized materials, it was of wondrous interest in EOR. Unlike other sizes, nanoparticles display distinct physical and chemical properties that can be utilized for multiple applications. Therefore, vast amounts of nanoparticles were examined in terms of formulation, size effect, reservoir condition, viscosity, IFT, and wettability alteration. When a holistic understanding of nanoparticles is aimed, it is necessary to review the recent studies comprehensively. This paper reviews the most recently published papers for nanoparticles in oil in general, emphasizing EOR, where most of these publications are between the years 2018 and 2022. It covers a thorough comparison of using nanoparticles in different EOR techniques and the expected range of oil recovery improvements. Moreover, this paper highlights the gaps existing in the field-scale implementation of NPs in EOR and opens space for research and development. The findings of this review paper suggest that the selection of the best NPs type for an EOR application is critical to the reservoir rock properties and conditions, reservoir fluids type, EOR mechanism, chemicals type (surfactant/polymer/alkaline), chemicals concentration used in the flooding process, and NPs properties and concentration.

Citric acid-based N-alkyl amides for enhanced oil recovery application in the carbonate reservoir: Sustainable laboratory-scale synthesis and recovery performance

Various chemical compounds and nanoparticles have been developed and utilized for upstream oilfield applications, regardless of their environmental impact. The majority of these oilfield chemicals were designed from oil-based starting materials and synthesized in multi-steps using hazardous solvents. However, there is an urge to improve sustainability in developing oilfield chemicals to reduce CO2 emissions and utilize eco-friendly materials. Herein, we propose a sustainable synthesis of citric acid-based N-alkyl amides using solvent-free reaction and green starting material. The N-alkyl amide compounds were prepared by condensation reaction between citric acid and N,N-dimethyl-1,3-propanediamine (DMPA) or N,N-diethylethylenediamine (DEEA). The resulting compounds demonstrated good stability in reservoir conditions and were used for enhanced oil recovery. The structure/property relationships between the N-alkyl amides and their oil recovery performance were investigated systemically. The CA-based N-alkyl amides resulted in cumulative oil recovery of 44.7%–48.3%, which is 90% higher than the commonly used surfactants such as α-Olefin Sulfonate (AOS) and Cetrimonium bromide (CTAB). This study paves the way to develop green-based materials for upstream applications to move toward efficient and cleaner production.

Red beet plant as a novel source of natural surfactant combined with ‘Smart Water’ for EOR purposes in carbonate reservoirs

The use of natural green surfactants has become one of the most popular techniques for enhanced oil recovery (EOR) because these types of surfactants are environmentally-friendly, efficient, sustainable, and less expensive than commercial surfactants. In the current study, the extraction of natural surfactant from the Red Beet (RB) plant is introduced for EOR applications in carbonate reservoirs. Characterization analyses using TGA, FT-IR, 1H NMR, and FESEM were carried out to assess the nature of the extracted saponin as the surfactant agent. The physicochemical characterization points to a nonionic surfactant. The role of salinity, with varying NaCl concentrations, in ‘smart water’ flooding using the RB surfactant was then investigated. According to the measured interfacial tension (IFT), the critical micelle concentration (CMC) of the extracted surfactant from the RB plant was 2500 ppm, and the IFT value at the CMC point was 9.92mN/m for deionized water. The parametric flooding study revealed that the RB surfactant injection as the source of the green surfactant (at its CMC value with 15,000 ppm NaCl as the optimum salinity) contributed, as the tertiary recovery, to an extra 26.29 % of the original oil in place (OOIP) because of a considerable decrease in contact angle from 151.4° to 42.14° and a decline in IFT values from 33.87 to 9.27 mN/m.

Species Distribution in Bicontinuous Phase Systems for Enhanced Oil Recovery Probed by Single-Sided NMR.

Multiphase aqueous-organic systems where a bicontinuous phase is in equilibrium with an excess organic and aqueous phase find various applications in industry. These systems─also known as Winsor III─are complex not only for the different phases that develop therein but also because they are multicomponent systems. In this work, we explore for the first time the use of a benchtop low-field single-sided NMR to determine the species distribution in Winsor III systems. The proposed methodology provides information at macroscopic and microscopic levels. In particular, we show the use of single-sided NMR to determine the phases' dimensions and the species distribution in a polymer-based bicontinuous system. The phases' dimensions and limits can be resolved with micrometric precision and are indicative of the bicontinuous phase stability. The species distribution is determined by means of spatially resolved NMR relaxation and diffusion experiments. It was observed that the salinity of the aqueous phase also impacts the species distribution in the bicontinuous system. Experiments show that the additive and the polymer are mainly located in the bicontinuous phase. As the salinity of the aqueous phase increases, the amount of organic components in the bicontinuous phase decreases as a consequence of the species distribution in the system. This influences the total amount of recovered organic liquid from the organic phase. The information is obtained in a relatively fast experiment and is relevant to the system's possible applications, such as enhanced oil recovery (EOR). This methodology is not only circumscribed to its application in EOR but can also be applied to the study of any emulsion or microemulsion systems without sample size or geometry constraints.

Polymer efficiency and sulfate concentration for hybrid EOR application to an acidic carbonate reservoir

Polymers play an important role in hybrid enhanced oil recovery (EOR), which involves both a polymer and low-salinity water. Because the polymer commonly used for low-salinity polymer flooding (LSPF) is strongly sensitive to brine pH, its efficiency can deteriorate in carbonate reservoirs containing highly acidic formation water. In this study, polymer efficiency in an acidic carbonate reservoir was investigated experimentally for different salinity levels and SO42− concentrations. Results indicated that lowering salinity improved polymer stability, resulting in less polymer adsorption, greater wettability alteration, and ultimately, higher oil recovery. However, low salinity may not be desirable for LSPF if the injected fluid does not contain a sufficient number of sulfate (SO42−) ions. Analysis of polymer efficiency showed that more oil can be produced with the same polymer concentration by adjusting the SO42− content. Therefore, when river water, which is relatively easily available in onshore fields, is designed to be injected into an acidic carbonate reservoir, the LSPF method proposed in this study can be a reliable and environmentally friendly method with addition of a sufficient number of SO42− ions to river water.

A Systematic Investigation of Polymer Influence on Core Scale Wettability Aided by Positron Emission Tomography Imaging.

Polymers have been used as viscosifying agents in enhanced oil recovery applications for decades, but their influence on rock surface wettability is rarely discussed relative to its importance: wettability largely controls fluid flow in porous media and changes in wettability may significantly influence subsequent system performance. This paper presents a two-part systematic investigation of wettability alteration during polymer injection into oil-wet limestone. The first part of the paper determines wettability and wetting stability on the core scale. The well-established Amott-Harvey method is used, and five full cycles performed with repeated spontaneous imbibition and forced displacements. Wettability alterations are measured in a polymer/oil system, to determine polymer influence on wettability, and evaluated towards simpler brine/oil and glycerol/oil systems, to determine reproducibility and uncertainty related to the method and fluid/rock system. Polymer injection into oil-wet limestone core plugs is shown to repeatedly and reproducibly reverse the core wettability towards water-wet. Wettability changed both quicker and towards stronger water-wet conditions with polymer solution as the aqueous phase compared to brine and glycerol. The second part of the paper attempts to explain the observed behavior; by utilizing in situ imaging by Positron Emission Tomography, an emerging imaging technology within the geosciences. High resolution imaging provides insight into fluid flow dynamics during water and polymer injections, identifying uneven displacement fronts and significant polymer adsorption.

Thermoresponsive Block Copolymer Core-Shell Nanoparticles with Tunable Flow Behavior in Porous Media.

With the purpose of investigating new polymeric materials as potential flow modifiers for their future application in enhanced oil recovery (EOR), a series of amphiphilic poly(di(ethylene glycol) methyl ether methacrylate-co-oligo(ethylene glycol) methyl ether methacrylate) [P(DEGMA-co-OEGMA)]-based core-shell nanoparticles were prepared by aqueous reversible addition-fragmentation chain transfer-mediated polymerization-induced self-assembly. The developed nano-objects were shown to be thermoresponsive, demonstrating a reversible lower-critical solution temperature (LCST)-type phase transition with increasing solution temperature. Characterization of their thermoresponsive nature by variable-temperature UV-vis and dynamic light scattering analyses revealed that these particles reversibly aggregate when heated above their LCST and that the critical transition temperature could be accurately tuned by simply altering the molar ratio of core-forming monomers. Sandpack experiments were conducted to evaluate their pore-blocking performance at low flow rates in a porous medium heated at temperatures above their LCST. This analysis revealed that particles aggregated in the sandpack column and caused pore blockage with a significant reduction in the porous medium permeability. The developed aggregates and the increased pressure generated by the blockage were found to remain stable under the injection of brine and were observed to rapidly dissipate upon reducing the temperature below the LCST of each formulation. Further investigation by double-column sandpack analysis showed that the blockage was able to reform when re-heated and tracked the thermal front. Moreover, the rate of blockage formation was observed to be slower when the LCST of the injected particles was higher. Our investigation is expected to pave the way for the design of "smart" and versatile polymer technologies for EOR applications in future studies.