Polymer Enhanced Oil Recovery Research Articles

Compact Viscosity Sensors for Downhole Enhanced Oil Recovery Polymer Fluid Degradation Monitoring

Summary There are currently no technologies available to measure polymer solution viscosities at realistic downhole conditions in a well during enhanced oil recovery (EOR). In this paper, custom-made probes using quartz tuning fork (QTF) resonators are demonstrated for measurements of viscosity of polymer fluids in the laboratory. The electromechanical response of the resonators was calibrated in simple Newtonian fluids and in non-Newtonian polymer fluids at different concentrations. The responses were then used to measure field-collected samples of polymer injection fluids. In the polymer fluids, the measured viscosity values by tuning forks were lower than those measured by the conventional rheometer at 6.8 s−1, closer to the solvent viscosity values. However, the predicted rheometer viscosity vs. QTF-measured viscosity showed a distinct exponential correlation (R2=0.9997), allowing for an empirical calibration between the two viscometers for fluids having the same solvent and polymer compositions. The QTF sensors produced acceptable viscosity measurements of polymer fluids within the required polymer concentration ranges used in the field and predicted field sample viscosities with less than 1–2 cp (or 10–20%) error from the rheometer data. Results were validated based on separate independent tests where the devices were used to measure the viscosity of Newtonian fluids and non-Newtonian polymer fluids in a series of consecutive dip tests, simulating more realistic usage. These devices can be used to measure either the “relative” viscosity changes from a polymer solution prior and post-injection or to measure a “calibrated” viscosity via empirical exponential correlation. The compact QTF sensors developed in this study can be easily integrated into portable systems for laboratory or wellsite deployment as well as logging tools for downhole deployment. This work also demonstrates the ability of these QTF devices to make sensitive viscosity measurements at high-frequencies, opening opportunities for their use in high-frequency rheology studies of EOR fluids.

Modification of Welan gum with poly(2-oxazoline) to obtain thermoviscosifying polymer for enhanced oil recovery

Thermoviscosifying polymers refer to a category of smart materials that exhibit a responsive behavior to environmental stimuli, specifically demonstrating a natural rise in viscosity of solutions as the temperature increases. The temperature-dependent behavior exhibited by thermally viscous polymers renders them potentially advantageous in the context of Enhanced Oil Recovery (EOR). There exists a dearth of research pertaining to the application of thermoviscosifying polymer for better recovery in reservoirs characterized by high temperatures and high salt content. In order to tackle the mentioned concerns, this study examined the utilization of welan gum modified with poly(2-oxazoline) as thermally responsive chain segments to enhance viscosity. The objective was to evaluate the ability to enhance viscosity under thermal conditions and to assess their effectiveness in displacement of reservoir oil in high temperature and high salt environments. This study aimed to establish a theoretical framework for understanding the correlation between the molecular structure and performance of novel thermally viscous polymers. Additionally, it sought to offer practical insights into designing the molecular structure of thermally viscous polymers suitable for polymer flooding in high temperature and high salt environments. Furthermore, the study proposed the application of these new thermoviscosifying polymers for EOR.

Assessment of World’s First Two Polymer Injectivity Tests Performed in Two Giant High-Temperature/High-Salinity Carbonate Reservoirs Using Single-Well Simulation Models and Pressure Falloff Tests Analysis

Summary Polymer flooding is a mature enhanced oil recovery (EOR) technology that has been widely implemented around the world for more than 60 years. Polymer flooding mostly targets medium- to high-permeability sandstone reservoirs with moderate salinity, hardness, and temperatures. However, in the last few years, the envelope of polymer flooding has been expanded to harsher reservoir conditions of high-temperature and high-salinity mixed-wet to oil-wet heterogeneous carbonate reservoirs. Development of novel polymers and innovative field application concepts has allowed for the reconsideration of polymer-based EOR as a promising technology to improve sweep efficiency for these challenging reservoirs. Polymer injectivity is one of the key challenges for polymer flooding projects and requires a rigorous derisking program that includes laboratory and field testing. A comprehensive laboratory program was designed to assess and investigate polymer thermal stability, polymer rheology in porous media, adsorption, and injectivity using reservoir core samples. In addition, two polymer injectivity tests (PITs) were performed in two giant light oil (0.3 cp) carbonate reservoirs in onshore Abu Dhabi under harsh conditions of high salinity (>200 g/L), high divalent ions (>20 g/L), high temperature (>250°F), and H2S concentration of up to 40 ppm. The polymer used during the two PITs (PIT 1 2019 and PIT 2 2021) is a new generation of EOR polymer (SAV 10) with high 2-acrylamido-tertiary-butyl sulfonic acid content that was specifically developed to tolerate such harsh conditions. This paper is focused on the interpretation of the PITs and lessons learned for future polymer-based EOR projects. The detailed data acquired in both tests were used to evaluate the polymer injectivity at representative field conditions and in-depth mobility reduction. The PITs together with the extensive laboratory studies are part of a thorough derisking program for the upcoming world’s first innovative hybrid EOR multiwell pilots—simultaneous injection of miscible gas and polymer (SIMGAP) and simultaneous injection of water and polymer (SIWAP). Both PITs are composed of three stages that include a multirate waterflood baseline, polymer injection using different rates, and polymer concentrations followed by extended chase waterflooding. In addition, a sequence of multiple pressure falloff (PFO) tests was acquired during the PIT executions and analyzed to obtain the required uncertainty parameters for the history-matching exercise. Polymer preshearing was considered as part of both PIT programs with the aim to homogenize the polymer molecular weight distribution and reduce possible shear-thickening effects near the wellbore as per laboratory measurements. Two single-well 3D simulation models were built to incorporate the information from polymer laboratory studies and to interpret the large field data sets acquired during the PITs. Lessons learned from PIT 1 allowed us to optimize the PIT 2 design program and achieve better understanding of polymer characteristics. The interpretation of the pressure transient analysis (PTA) of the PFO tests and the 3D simulation models of the two PITs confirmed the generation of polymer banks and demonstrated effective propagation of the polymer into the reservoirs at target concentrations and representative rates of the future SIWAP and SIMGAP interwell pilots.

Exposure and effects of synthetic enhanced oil recovery polymers on the Norwegian Continental Shelf

Synthetic polymers are planned to be used for more efficient oil recovery from offshore oil reservoirs. Using synthetic polymers offshore may lead to these being released into the marine environment through produced water (PW) discharges, thereby causing environmental impacts in the ecosystem. In this study, we assess the impacts of discharging synthetic polymers on the Norwegian Continental Shelf (NCS). We use a numerical model called the Dose-related risk and effects assessment model (DREAM) to simulate discharges of polymers into the sea. DREAM assesses impact in terms of environmental impact factor (EIF) values of individual chemicals present in the PW. Two approaches are used: first, using a standard short-time/small-scale/near-field simulation procedure (50 by 50 km); second, using a non-standard long-term/large-scale/far-field simulation procedure (1200 by 1800 km). For the near-field simulations, the impact is assessed by estimating EIF values resulting from the discharge of 200 and 8000 kilodaltons (kDa) molecular weight fractions of Anionic Polyacrylamide (APAM) from a North Sea oil field. The results show higher EIF values for 8000 kDa compared to 200 kDa APAM. Far-field simulations are used because polymers appear to be resistant to microbial degradation and are thus expected to have long residence times in the sea. An increase in concentrations to harmful levels for aquatic species due to repeated discharges from multiple oilfields is thus possible. The results from the far-field simulations are used to establish relationships between the amount of polymer released annually and the resulting highest values of 100- and 75-percentile concentrations. The results indicate that polymers are not expected to build-up on the NCS and there is a significant margin between the expected polymer concentrations and the lowest concentrations at which toxic effects are observed. The established regression equations can be used to indicate maximum expected concentration values for future release scenarios.

Synergistic effect of graphene oxide and partially hydrolyzed polyacrylamide for enhanced oil recovery: Merging coreflood experimental and CFD modeling approaches

The present study provides a comprehensive examination of GO-HPAM polymeric nanocomposite, contributing significantly to enhanced oil recovery (EOR). At the core of this investigation are a series of experimental tests and validations of simulations. The study examines the bonding effects, structural integrity, morphological interconnections, and stability of the GO-HPAM. The significance of reservoir and in-situ fluid conditions in the effort to improve EOR The GO-HPAM stabilization composite was developed, assessed, and examined for its extended core-flooding capabilities owing to its high energy characteristics. The simulation model was built on a Cartesian grid with fixed values for the bulk volume, injection rate, well completion, and rock-fluid properties using ANSYS Fluent. During the flooding experiment, the injections of 2 PV of brine, 0.50 PV of GO-HPAM, and 2 PV of chase water were precursors. The findings showed that 19.67% of the original oil could be recovered after injecting the nanocomposite fluid consisting of GO-HPAM. The GO-HPAM flooding gathered over 60% more oil than the traditional EOR polymer. Moreover, numerical modeling demonstrated a performance of the GO-HPAM combination comparable to the experimental results. The proposed synergetic fluid will assist researchers and industrialists in the design of an EOR process.

Technology Focus: Heavy Oil (April 2023)

_ Heavy oils are characterized by high-density, high-viscosity, and high-heavy-fraction components. One of the more common characteristics of heavy oil reservoirs is a low primary recovery factor, which is mainly because of unfavorable mobility ratios between oil and water, negligible solution drives, and faster decline of reservoir pressures because of relatively low oil compressibility. Most of the technologies that apply to heavy oil reservoirs need to address the mobility ratio or viscous forces before any flooding. Given the complex nature of heavy oil reservoirs, paper SPE 209328 present a comprehensive review of the latest technologies and work flows developed for heavy oil reservoir management. Although secondary oil production methods such as waterflooding, water-alternating-gas injection, and gas drive might not be efficient in recovery from heavy oil reservoirs, the applicability and success of these methods can be analyzed on a reservoir basis. The offtake and throughput management philosophy for heavy oil waterflooding is not the same as for classical light oil, and it could play a major role in recovery efficiency. The key point is to understand the nature of heavy oil and reservoir heterogeneity regarding their fluid and rock properties. Recent technology advances in hardware and software have enabled the industry with tools that allow achieving full-field high-resolution simulation modeling; therefore, performing a realistic reservoir simulation is achievable. This might decrease the loss of millions of dollars before field applications. Paper SPE 210185 presents an example of taking advantage of recent simulation technologies and presents a method and work flow under subsurface uncertainty for a large heavy oil field with complex geological characteristics, a long production history, and many wells. The work-flow design is applicable for other fields with similar characteristics and delivery objectives. Paper SPE 203783 discusses the results of a recovery-optimization study conducted in a heavy oil field in south Oman aimed at improving the understanding of deep bottom-up water injection. Recommended additional reading SPE 205449 First Successful Controlled Dumpflood in Deepwater Gulf of Mexico Results in Promising Incremental Rate and Recovery by Bilal A. Hakim, Talos Energy, et al. URTeC 2021-5077 Heavy Oil Polymer Enhanced Oil Recovery in the Challenging Alaskan Arctic—It Works! by A. Dandekar, University of Alaska Fairbanks, et al. SPE 212387 Evaluation of the Oil Recovery and Economic Benefit of the First-Ever Polymer flood Field Pilot To Enhance the Recovery of Heavy Oils on Alaska’s North Slope Using Machine-Assisted Reservoir Simulation by Cody Douglas Keith, University of Alaska Fairbanks

Evaluating the performance of designed terpolymers for polymer flooding

AbstractIn this work, polymeric materials designed for enhanced oil recovery (EOR) were evaluated for their intended application. Properties including viscosity, flow through porous media (resistance factor and residual resistance factor), and heavy oil displacement (incremental oil recovery) were assessed for designed terpolymers of 2‐acrylamido‐2‐methylpropane sulphonic acid (AMPS), acrylamide (AAm), and acrylic acid (AAc). The same properties were evaluated for two commercially available reference materials (e.g., partially hydrolyzed polyacrylamides or HPAM) with similar characteristics, which allowed for direct comparison between the newly designed terpolymers and materials that are currently on the market for the polymer flooding application. The incremental oil recovery directly associated with polymer flooding, which includes both the polymer flooding and post‐polymer waterflooding stages (excluding the initial waterflooding injection (or secondary) oil recovery), demonstrates that the designed terpolymers provided a higher incremental recovery (42% and 58%) than the reference materials (33% and 46%). Therefore, the terpolymers provided a higher contribution to incremental (or enhanced) oil recovery than the typical HPAM. Additionally, both designed terpolymers showed better injectivity in unconsolidated porous media and are less likely to cause plugging than the commercially available reference materials. Therefore, using a targeted design approach ultimately led to polymeric materials with excellent performance for EOR polymer flooding applications.

Characterization of Nonlinear Viscoelastic Properties of Enhanced Oil Recovery Polymer Systems Using Steady-Shear Rheometry

SummaryEnhanced oil recovery (EOR) polymer systems such as hydrolyzed polyacrylamide (HPAM) solutions flowing in porous media at high fluxes were reported to cause shear-thickening, a nonlinear viscoelastic (NLVE) phenomenon. Bulk rheological studies are usually performed to characterize the viscous and viscoelastic behaviors of polymer solutions in porous media. To characterize the viscoelastic properties, oscillatory shear rheology based on linear viscoelastic (LVE) data and extensional rheology based on NLVE data have been used. Although both extensional flow and high-speed shear flow can stretch and thicken polymer solutions in a nonlinear fashion, steady-shear rheometry has been used to measure only the viscous and thinning behavior of HPAM systems. In this paper, (a) the thickening ability of HPAM polymer systems formulated with contrasting salinity and molecular weight (MW) concentration is characterized in bulk shear rheometry to analyze if the thickening in the pure shear field correlates with the thickening behavior reported in porous media and other rheometry and (b) the thickening intensity of the polymer solutions of varying salinity concentration in the bulk shear field is compared with the reported mechanical degradation effects in the literature.The shear-thickening index obtained by fitting a power-law model to thickening data in steady-shear rheograms is higher for the high-saline, high-MW low-concentration HPAM systems that have inherently higher nonlinear viscoelasticity. Furthermore, the thickening behavior observed due to salinity variation in bulk steady shear contrasts with linear oscillatory shear behavior but conforms to the thickening behavior observed in porous media and in the extensional field. This signifies that polymer-EOR researchers performing comparative studies on low-salinity and high-salinity polymer floods, and having a shear rheometer at their disposal, must look beyond linear oscillatory rheology and make use of nonlinear steady-shear rheology. There is a direct relation between the shear-thickening index of saline HPAM solutions and their mechanical degradation intensity. This paper shows that the high-speed data in steady-shear rheometry that are usually ignored in EOR literature have useful information and the notion that HPAM solutions are purely thinning in the bulk shear field needs to be reconsidered.

Can Supramolecular Polymers Become Another Material Choice for Polymer Flooding to Enhance Oil Recovery?

High molecular polymers have been widely studied and applied in the field of enhanced oil recovery (EOR). At present, the focus of research has been changed to the design of polymer networks with unique properties such as anti-temperature and anti-salinity, good injection and so on. Supramolecular polymers have high viscoelasticity as well as excellent temperature, salt resistance and injection properties. Can supramolecular polymers become another material choice for polymer flooding to enhance oil recovery? The present review aims to systematically introduce supramolecular polymers, including its design strategy, interactions and rheological properties, and address three main concerns: (1) Why choose supramolecular polymers? (2) How do we synthesize and characterize supramolecular polymers in the field of oilfield chemistry? (3) What has been the application progress of supramolecular polymers in improving oil recovery? The introduction of a supramolecular interaction system provides a new idea for polymer flooding and opens up a new research direction to improve oil recovery. Aiming at the “reversible dynamic” supramolecular polymers, the supramolecular polymers are compared with the conventional covalent macromolecular polymer networks, and the challenges and future research directions of supramolecular polymers in EOR are discussed. Finally, the author’s viewpoints and perspectives in this emerging field are discussed.

Technology Focus: EOR Operations (June 2022)

In this article, I will focus on chemical enhanced oil recovery (EOR). What is its current status, and what is its future? Chemical EOR is defined as the addition of a chemical to injection water for enhancing oil recovery. Typically, and traditionally, there are three types of chemicals added to water: polymers, surfactants, and alkalis. In simple terms, the polymers increase the viscosity of injected water, thus improving its mobility, similar to adding a small amount of corn starch to thicken soups. The surfactants reduce the interfacial tension (IFT) between the oil and water, dislodging the stuck oil, similar to how a laundry detergent works in our washers to clean our clothes. Alkalis are surfactant-forming compounds that react with the organic material in the oil and form surfactants in situ. The surfactants then reduce the IFT and enhance recovery. Chemical EOR has been practiced since oil was discovered and water was injected to produce it. The world produces less than 1 million BOPD from chemical EOR. The bulk of this (more than 80%) is from polymerflooding for mostly medium to heavy oils. Surfactants and alkalis have been tested, but their field performance has been poor. They perform extremely well in experiments and laboratories. Up to 100% of the oil can be produced in the laboratory using surfactants, if enough pore volumes are injected. Therein lies the first clue as to why surfactants have failed. Too many pore volumes are needed. The main reason is adsorption on the rock surface. Most of it is adsorbed, and it does not propagate far enough into the reservoir for it to perform its magic. Another reason is its degradation in harsh reservoir conditions. A third reason is economics and the high initial investments for facilities. Combination flooding including surfactant/polymer, alkali/surfactant/polymer, and others have been tried with limited success. In my humble opinion, chemical EOR equals polymer EOR, at least from a total-oil-production point of view. Some purists and scientists may disagree, but that’s all right. The papers that follow are examples of polymer EOR from China, Europe, and Oman. One is an excellent paper that shares lessons learned from extensive polymerflooding experience in China. Another describes lessons learned from pilots in Austria. A third shares some of the challenges encountered in pilot-testing polymers from Oman. The challenge for academia and research institutes is this: How can we make robust surfactants, reduce their adsorption on rocks, and reduce their cost? It’s food for thought for future researchers and graduate students. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200178 - Polymer Stability at Harsh Temperature and Salinity Conditions by Tormod Skauge, Energy Research Norway, et al. SPE 200166 - Cost-Efficient Polymer Full-Field Development by Fast-Tracking Nap Concept in Horizontal Polymer Injectors by Faisal Saadi, Petroleum Development Oman, et al.

Robust Value Quantification of Enhanced Oil Recovery Methods Using Ensemble-Based Optimization

Summary Over the last decades, the development of different oil reservoirs with gas or chemical enhanced oil recovery (EOR) methods have been studied, and the EOR effects of the recovery methods are found to be sensitive to fluid and rock properties in the reservoirs. The use of a single reservoir model with the assumption of known reservoir parameters is not enough to guarantee an accurate prediction of EOR effects. The best decision related to the injection strategies of EOR methods can be appropriately found using an optimization setup that accounts for the uncertainty quantification in the reservoir. In this paper, we present mathematical tools for optimizing and ranking the value of the commonly used EOR methods. The methodology is demonstrated with Smartwater, carbon dioxide (CO2), and polymer EOR methods on synthetic 2D and 3D oil reservoirs. To capture the uncertainties in the reservoirs, we use an ensemble of geological realizations obtained by engineering upscaling of the initial model. The usefulness of this study is to improve the understanding of the actual benefit of EOR methods and to provide a methodology that quickly allows users to appropriately predict EOR injection strategies that maximize the annually discounted economic values of the injected and production data. The control variables of optimization problems include EOR gas rate or chemical concentration, water rates, oil rate, or bottomhole pressures. An ensemble-based optimization method with covariance adaptation is used to solve the optimization problem. For the different reservoirs considered, we find the optimal well controls for EOR methods. A comparative study of the economic benefits of the optimal solutions of EOR methods using optimized waterflooding as a reference point is presented. CO2 is found to rank high compared with other EOR methods in both cases. Finally, we investigate the effect of different injection costs of CO2 on the optimization results of CO2 EOR methods for the 3D reservoir field.

Experimental Investigation of a Mechanically Stable and Temperature/Salinity Tolerant Biopolymer toward Enhanced Oil Recovery Application in Harsh Condition Reservoirs

In search of robust polymers for enhanced oil recovery (EOR) application in reservoirs with harsh conditions, a water-soluble biopolymer was thoroughly investigated in this work to evaluate its applicability in such reservoirs. The experimental data revealed that compared to the commonly used EOR polymer, HPAM, the biopolymer was more efficient in thickening a brine solution as a result of its peculiar conformation. The presence of an electrolyte has almost no effect on the rheology of the biopolymer solution, even at an extremely high salt concentration (20 wt% NaCl). The relation between viscosity and the concentration curve was well fitted to the power-law model. Moreover, the rigid polymer chains rendered the polymer solution superior tolerance to elevated temperatures and salinity, but also led to considerable retention within tight porous media. The adsorption behavior was characterized by the average thickness of the hydrodynamic adsorbed layer on sand grains. The mechanical degradation was assessed by forcing the polymer solutions to flow through an abrupt geometry at ultra-high shear rates. The slight viscosity loss compared to HPAM proved the high mechanical stability of this polymer. These properties made it a promising alternative to HPAM in polymer flooding in the near future for high permeability oil reservoirs with harsh conditions.

Improved Enhanced Oil Recovery Polymer Selection Using Field-Flow Fractionation

Summary Various polyacrylamide polymers have been successfully applied in chemical enhanced oil recovery (EOR) projects. These polymers are characterized by high molecular weights (MWs) to achieve high viscosifying power. The selection of polymers for chemical EOR is a crucial step in the field testing and implementation of such EOR projects. The reason is that per-pattern operating expenditures (OPEX) are one of the sensitive cost drivers for such projects. The important parameters for the selection of polymers are the filtration ratio, viscosifying power, polymer retention, and stability of the polymers at reservoir conditions. The MW distribution (MWD) of the polymers has a major impact on polymer properties and performance. Measuring the MWD is challenging using conventional methods. Field-flow fractionation (FFF) enables the determination of the distribution to select and quality check various polymers. Multiangle light scattering (MALS) was used as the main detector. Polymers with high MWs (>1 MDa) are used for EOR to obtain highly viscous aqueous solutions. The MWD of the polymers is crucial for the solution characteristics. Conventional analysis of polymers is performed using either viscometry, which is able to determine the average MW but does not give information on MWD, or size-exclusion chromatography (SEC), which is restricted to MWs of <20 MDa. FFF is based on the analytes flowing at different speeds in a channel-dependent on their size and mass. This effect leads to separation, which is then used to determine the MWD. FFF allows determining the MW and MWD of various ultrahigh MW polyacrylamides (HPAAMs). The FFF measurements showed that, despite similar MWs being claimed, substantial differences in MWD are observed. This technology allowed the quantification of the MWD of HPAAMs up to an MW of 5 GDa. Furthermore, gyration radii of the HPAAM molecules were determined. Selecting polymers on viscosifying power only is not addressing issues related to different MWs and MWDs such as selective polymer retention and degradation of the high molar mass part of the distribution. The results were used to improve the polymer selection for chemical EOR projects. In addition to viscosifying power and price, also the MWD and changes of the MWD in the porous medium are considered in the selection of the polymer. Overall, this work presents a new technique for the analysis of ultrahigh MW EOR polymers, which enables the possibility to determine the full range of polymer MWDs. This available information enhances the EOR polymer selection process addressing selective polymer retention and mechanical degradation in addition to the viscosifying power of polymers.

A review of polymer flooding for enhanced oil recovery

Oil has a significant role as the principal source of energy in a society with rising energy demand. According to the annual report 2021 by Shelf Drilling (a leading provider of jack-up contract drilling services), the world oil consumption grew by 0.8 million barrels per day to reach almost 101 million barrels per day in the year 2019. Several other reports mention that the global crude oil output increased by 2.1 million barrels per day, or 2.3 percent, which is more than three times the global consumption. Additionally, the recent dramatic drop in oil prices compelled oil corporations to reconsider their production plans and cut costs in light of the dynamic oil price environment. While new oil sources are still being discovered and developed, enhanced oil recovery (EOR) methods are being used more frequently. In this review paper, the features of polymers utilized for EOR, including synthetic and natural polymers (biopolymers) are discussed. Also, the numerous EOR applications such as polymer flooding, polymer foam flooding, alkali–polymer flooding, surfactant–polymer flooding, alkali–surfactant polymer flooding, and polymeric nanofluid flooding are generalized and evaluated. With new advancements in the applications of polymeric nanofluid, it is capable of taking over the oil industry efficiently in polymer flooding for EOR. Additionally, due to their general macromolecular structure and viscoelastic characteristics, polymers are important in EOR.

Synthesis and characterization of cellulose-based graft copolymers crosslinked by gamma-irradiation for enhanced oil recovery applications

Cellulose-based polymers have garnered significant attention as potential candidates for use in enhanced oil recovery (EOR). The challenge in the design of EOR polymers is the need for materials with a high low critical solution temperature (LCST) and the ability to withstand harsh environmental conditions. In this study, cellulose-methylcellulose graft copolymers were prepared with different cellulose to methylcellulose weight ratios. The copolymerization was carried out using gamma radiation doses of 5, 15, and 25 kGy, respectively. The LCST of the copolymers were evaluated using differential scanning calorimetry analysis. The effect of salt addition on the LCST of the materials was studied using different phosphate-buffered saline (PBS) concentrations. The results showed that the cellulose monomer concentration increase from 0.1 to 0.5% in 2% methylcellulose dispersed in water reduced the LCST from 59 to 54°C. The hydrophobic nature of cellulose moieties induced the aggregation of the copolymers into core-shell micelles. Besides, higher gamma radiation doses lowered the LCST of the copolymers. The increase in the salt concentration in the PBS medium tended to decrease the LCST due to disrupted hydration structure of the polymer chains. This work revealed that cellulose-methylcellulose copolymers could be used in chemical EOR due to their high phase transition temperatures, preventing pore clogging and enhancing oil production in the producing wells.

Injectivity and Potential Wettability Alteration of Low-Salinity Polymer in Carbonates: Role of Salinity, Polymer Molecular Weight and Concentration, and Mineral Dissolution

Summary Coupling polymer with low-salinity water (LSW) to promote enhanced oil recovery (EOR) in carbonate reservoirs has attracted significant interest in the petroleum industry. However, low-salinity polymer (LSP) application to improve oil extraction from such rocks remains a challenge because of the complex synergism between these two EOR agents. Thus, this paper highlights the main factors that govern the LSP displacement process in carbonate reservoirs in terms of wettability alteration and mobility control. A series of experiments including contact angle, spontaneous imbibition, injectivity, adsorption, and oil displacement tests were performed. The impact of mineral dissolution on the polymer/brine and polymer/rock surface interactions and its possible connection to the efficiency of the LSP in carbonates was also investigated using ζ potential analysis following an elaborative procedure. All experiments were executed at elevated temperature (75°C) using two polymers (SAV10) of different molecular weights (MWs) prepared at varying concentrations and salinities. Contact angle measurements showed that increasing the polymer concentration and MW and, at the same time, decreasing the solution salinity could effectively rend homogeneous oil-wet calcite surfaces strongly water-wet. Conversely, spontaneous imbibition tests using heterogonous oil-wet Indiana limestone cores showed that the polymer viscosity and its molecular size hinder the performance of the polymer to modify the wettability of the core samples at high concentration and MW because they could limit its penetration into the porous medium. On the other hand, the results obtained from polymer injectivities showed that LSP had better propagation with lower filtration effects in comparison with high-salinity polymer (HSP). However, polymer adsorption and inaccessible pore volume (IPV) increased with the decrease of salinity. Calcite mineral dissolution triggered by LSP, which is associated with an increase in pH and [Ca2+], considerably influenced the polymer viscosity. In addition, ζ potential measurements showed that the LSP altered the rock surface charge from positive toward negative and at the same time, the Ca2+ released due to mineral dissolution could modify the polymer molecule charge toward positive. This confirms that mineral dissolution impressively results in better wettability alteration performance; however, it could lead to undesirable high polymer adsorption at low salinity. These findings provide new insight into the influence of mineral dissolution on polymer performance in carbonates. Finally, forced oil displacement tests revealed that both HSP and LSP extracted approximatively the same amount of oil. The HSP could enhance the oil recovery through mobility control. By contrast, wettability alteration could take part in the improvement of oil recovery at LSP, as proved by spontaneous imbibition tests, along with mobility control. Despite possessing high wettability alteration potential, LSP could not yield very high recovery because of its low accessibility into the porous medium. Shearing of the LSP was found effective in improving oil recovery through enhancing the polymer accessibility. This will lead us to simply say that polymer accessibility into carbonates is crucial for the success of the wettability alteration and mobility control processes, which is remarkably important not only for this specific study but also for other various polymer EOR applications.

A holistic approach to determine the enhanced oil recovery potential of hydroxyethylcellulose, tragacanth gum and carboxymethylcellulose

Several polymers have been investigated for their potential as an enhanced oil recovery process. In general, polymer dispersion in an injection fluid increases its sweep efficiency and mobility ratio leading to an increase in oil recovery rate. Though, harsh reservoir heterogeneous environment, lowers performance of different polymers under high formation salinity and temperature. Therefore, to achieve a profitable operational decision to recover crude oil, the oil and gas industry relies heavily on predicting various enhanced oil recovery (EOR) fluid performance in advance. Decisions on such recovery strategies should be taken at the lab scale before practical field job planning. In this study, we propose a holistic approach for analyzing and assessing tragacanth gum (TGU), hydroxyethylcellulose (HEC), and carboxymethyl cellulose (CMC) potential as an EOR fluid in three stages of screening methods, depending on the criteria that are well-established in the literature. We perform a comprehensive study based on the polymer rheological characteristics as first stage examination, wettability alteration features as second stage examination, and evaluation of additional oil recovery potential using oil reservoir simulating bioreactors (ORSBs) in the final stage. We integrate all the practical screening principles involving the reservoir characteristics through this innovative approach. The first stage screening showed better rheological characteristics of HEC and TGU, and the existence of wettability alteration capacities in these polymers was observed during the second stage screening. The final stage demonstrated that both these polymers (HEC – 7.38% and TGU – 6.71% of Residual Oil in Place) had higher additional oil recovery potential than polyacrylamide polymer (5.83%), a widely used commercial EOR polymer.

E&P Notes (June 2021)

E&P Notes (June 2021)

TiO2 nanoparticle-induced Xanthan Gum Polymer for EOR: Assessing the underlying mechanisms in oil-wet carbonates

This work systematically investigates the potential of Anatase TiO 2 nanoparticles-induced Xanthan-gum polymer as a Nano-polymer suspension for enhanced oil recovery (EOR) in carbonates. For this purpose, initially, viscosity of Xanthan gum polymer with and without the nanoparticles (NPs) was examined at different conditions. The stability of the suspensions was determined qualitatively and quantitatively. The capability of the Nano-polymer suspensions for wettability alteration was explored using contact angle measurement aided by a mathematical approach. Interfacial tension measurement was performed. Finally, oil displacement experiments were conducted to examine EOR efficiency of the Nano-polymer suspension. We found that while increasing temperature and adding salt to polymeric solutions caused a reduction in shear viscosity, the addition of NPs to the solutions could relatively recover the viscosity. The presence of polymers in the nanofluids improved dispersion stability of NPs. Also, the Nano-polymer suspensions could extend the ability of the NPs for wettability alteration and faster equilibrium states obtained than the polymer-free nanofluids. The mathematical model derived based on the equation of kinetic adsorption could describe the wettability alteration process well and successfully captured contact angle profiles. Results of the oil displacement tests revealed that whereas TiO 2 nanofluid and polymer solution showed additional oil recovery values of 12 and 19% of OOIP, respectively, 25% additional oil was produced using Anatase TiO 2 -induced Xanthan gum polymer flooding. • EOR potential of Anatase TiO 2 Nanoparticles-induced Xanthan Gum Polymer was investigated systematically. • TiO 2 nanoparticles relatively compensated the viscosity reduction of the polymer for thermal breakage and salt effect. • Xanthan gum polymer was helpful for nanofluids to remain stable for a long time range. • The performance of nanoparticles for rock wettability alteration was fortified by Xanthan gum polymer. • An extra oil recovery of 25% of OOIP was recovered using the Nano-polymer suspension.

New insights into guar gum as environmentally friendly polymer for enhanced oil recovery in high-salinity and high-temperature sandstone reservoirs

Chemical enhanced oil recovery (EOR) processes are usually used as additives for hydrocarbon production due to its simplicity and relatively reasonable additional production costs. Polymer flooding uses polymer solutions to increase oil recovery by decreasing the water/oil mobility ratio by increasing the viscosity of the displacing water. The commonly used synthetic water-soluble polymer in EOR application is partially hydrolyzed polyacrylamide (HPAM). However, synthetic polymers in general are not attractive because of high cost, environmental concerns, limitation in high temperature, and high-salinity environment. Guar gum is an environmentally friendly natural water-soluble polymer available in large quantities in many countries and widely used in various applications in the oil and gas industry especially in drilling fluids and hydraulic fracturing operations; however, very limited studies investigated on guar as a polymer for EOR and no any study investigated on its uses in high-temperature and high -salinity reservoirs. The objective of this study is to confirm the use of guar gum as a natural polymer for EOR applications in sandstone reservoirs and investigate its applicability for high-temperature and high-salinity reservoirs. The study experimentally investigated rheological characteristics of a natural polymer obtained from guar gum with consideration of high temperature (up to 210 °F) and high salinity (up to 20% NaCl) and tested the guar solution as EOR polymer. The results of this study show that the guar solution can be used as an environmentally friendly polymer to enhance oil recovery. Based on the results, it can be concluded that guar gum shows shear-thinning behavior and strongly susceptible to microbial degradation but also shows a very good properties stability in high temperature and salinity, where in low shear rate case, about 100 cp viscosity can be achieved at 210 °F for polymer prepared in deionized water. Guar polymer shows good viscosity in the presence of 20% NaCl where the viscosity is acceptable for temperature less than 190 °F. Also, the flooding experiment shows that the recovery factor can be increased by 16%.