Polymer Flooding Research Articles

Developing methodology and experimental procedure эfor experimental microfluidic study of chemical enhanced oil recovery

The concern of this research was to review the different methodology on microfluidic experiments conducted to study chemical enhanced oil recovery methods on micromodel chips. In general, there are several ways to study EOR methods such core flooding and microfluidics. The disadvantage of first method is that the flow processes inside the core sample cannot be imagined. Hence, the second method helps us to fully visualize how fluid flow behaviour occurs though the porous medium of the rocks. The various chemical EOR processes such as surfactant flooding, polymer flooding and ASP flooding were studied on microfluidic chips. These chemicals were injected into micromodels to drive out crude oil. It helps to understand the interactions between crude oil and chemicals, the advancement of front developed between displacing and displaced fluids and the viscous fingering effect. Visual studies enabled us to understand the effectiveness of polymer, surfactant and alkaline separately and as combined. The different experimental methodologies to study the EOR methods are reviewed. Mainly experiments divided into two main groups: methods of geological characterisations influence to fluid transport while others study oil displacement at different condition, such high temperature, high pressure, low or high salinity, highly viscous oil. We reviewed methodologies applied to study an oil displacement by polymer, surfactant-polymer (SP) and alkaline surfactant polymer (ASP) solutions, their interactions and transport in porous media. Based on reviewed article the experimental procedure was developed. Analyses of published materials have helped to design and direct the methodology of research.

Study on Compatibility between Complex Mode Micropore Structure and Polymer Solution of Different Formulation for Conglomerate Reservoir

In this paper, the conglomerate reservoir is selected as the object to investigate the micropore structure and the compatibility of polymer solutions. Firstly, the characteristics of complex mode pore structure are analyzed based on casting thin sections, scanning electron microscope, and capillary pressure curve. Then the conglomerate reservoir is divided into five types by use of the K-means clustering algorithm, and the differences in micropore structure among the different reservoir types are also clarified. Secondly, the dynamic light scattering technology is used to directly determine the hydrodynamic diameter of different polymer formulations. As the polymer molecular weight increases, the average hydrodynamic diameter becomes larger, and with the same polymer molecular weight, the average hydrodynamic diameter becomes gradually larger as the solution concentration increases. Based on the above research results, the matching relationship between five reservoir types and polymer solutions is determined through laboratory experiments. The experimental results show that when the polymer molecular weight is determined, the volume of pore volume that can be effectively swept by polymer hydration molecules gradually decreases as the concentration of the solution increases. When the polymer molecular weight and its concentration are both determined, the pore volume of effective displacement of polymer-hydrated molecules also gradually reduces with becoming worse reservoir pore structure. The scope of application of different polymer formulations becomes progressively smaller as the microscopic pore structure of type I to type V reservoirs becomes deteriorated. The compatibility between the micropore structure of different conglomerate reservoir types and polymer solution is determined to provide the geological basis for the reasonable formulation of the polymer flooding scheme.

Low Salinity Water–Polymer Flooding in Carbonate Oil Reservoirs: A Critical Review

AbstractLow salinity water–polymer flooding (LSWPF) is an emerging hybrid enhanced oil recovery (EOR) method that uses the synergetic effects of low salinity water (LSW) and polymers to enhance both the microscopic and macroscopic sweep efficiencies. Polymer flooding is an EOR method that aims to increase water viscosity and improve the mobility ratio of the injected fluid to the reservoir. It enhances mobility control and reduces water relative permeability, reaching a more favorable condition for sweep efficiency. LSW is an EOR method that aims to change wettability by exploiting crude oil and reservoir rock interactions. It allows for improving oil recovery when the injected water has a very low salinity compared to seawater or formation water. The literature reports LSWPF studies applied to sandstone reservoirs. However, LSWPF applications in carbonate reservoirs still lack. This review critically analyzes LSWPF as an alternative to Polymer flooding using seawater in carbonate reservoirs.

Waste plastic derived reduced graphene oxide as a potential additive for the surfactant polymer flooding: A sustainable solution

The twenty-first century's major problems are the demand for sustainable green energy and the eco-friendly upcycling of plastic waste. The solutions to these problems should have an alluring cost-effective industrial synergy. Tackling these issues address the clean energy generation concerns and the long-term preservation of the economy and environment from plastic waste. This study focuses on upcycling waste plastics into reduced graphene oxide (RGO) and their application in enhanced oil recovery. Raman and TEM analysis confirmed the successful synthesis of RGOs. In addition, FTIR helps study the presence of functional groups and TGA for thermal stability analysis. The RGO improves the oil recovery by altering wettability, reducing surface tension / interfacial tension, and minimizing surfactant loss. The surface / interfacial property and wetting attributes of the RGO-based prepared solution were examined by surface tension and contact angle measurement. The surface tension and contact angle reduction using RGO were ∼25% and ∼20% without surfactant. Whereas with surfactant (anionic, cationic, and nonionic) and RGO, the reduction in surface tension was ∼55%, ∼57%, and ∼57%, respectively. Also, the reduction in contact angle with surfactant was ∼83%, ∼46%, and ∼80% for anionic, cationic, and nonionic surfactant with RGO particles. The chemical slug's viscosity was then examined at elevated temperatures. The viscosity results follow the power law model to comprehend fluid flow behavior. Finally, the chemical slug consisting of a surfactant mixture, RGO particles, and an industrial-grade polymer was used in the sand pack flooding studies recovering ∼71% of the original oil in place.

A Systematical Review of the Largest Polymer Flood Project in the World: From Laboratory to Pilots and Field Application

Summary This paper presents a systematical review of the largest polymer flood project in the world, applied to multilayered, heterogeneous sandstone reservoirs in the giant Daqing Oilfield in China. First, reservoir and fluid characteristics are highlighted to understand the heterogeneity of the reservoir. Next, the project history is summarized, including laboratory studies, pilot tests, commercial tests, and fieldwide applications. Third, typical polymer flood performance and reservoir management measures are presented. Finally, key understandings and lessons learned from more than 50 years of experience are summarized. The La-Sa-Xing Field in the Daqing Field Complex contains three types of reservoir sands: Type I sand with high permeability, Type II sand with medium permeability, and Type III sand with low permeability. Polymer flood was studied in the laboratory in the mid 1960s, followed by small-scale pilots beginning in 1972 and industrial-scale pilots starting in 1993, all of which successfully reduced water cut and enhanced oil recovery. Fieldwide application commenced in 1996, targeting the Type I sand. With Type II sand being brought onstream in 2003, the project achieved a peak production of 253,000 BOPD in 2013. Polymer flood reduced water cut by 24.8%. Reservoir management measures, such as zonal injection, profile modification, hydraulic fracturing in low-permeability sand, and injection optimization, proved to be effective. Based on the water-cut performance, production can be divided into four stages: (1) water-cut decline, (2) low water cut, (3) rebound, and (4) water chase. Fit-for-purpose improved-oil-recovery measures were implemented for each stage to improve production performance. Key understandings and lessons learned include the following: (1) Polymer flood improves both sweeping and displacing efficiencies; (2) high interlayer permeability contrast leads to low incremental recovery; (3) variable well spacing should be adopted for different reservoir types; (4) adoption of large molecular weight (MW) and large slug size greatly enhances recovery; and (5) salt-resistant polymer is beneficial for produced water reinjection in Type II sand; (6) zonal injection increased swept reservoir zones by 9.8% and swept pay thickness by 10.3%; (7) profile modifications helped improve vertical conformance in injection wells and led to enhanced sweeping efficiency and extended low water-cut stage; and (8) optimization-recommended well spacing for Type I, Type II, and Type III sands is 10–15.5, 5.6–7.6, and 2.5–3.6 acres, respectively. In comparison with generally 6–8% incremental recovery by polymer flood in the industry, this project achieved an impressive incremental recovery of 12%, enhancing the oil recovery factor from 40% by primary recovery and waterflood to 52% stock tank oil initially in place (STOIIP). The progressive approach from laboratory experiments through pilots and finally to field application is a best practice for applying polymer flood fieldwide for a giant field such as the La-Sa-Xing Field.

Evaluation of ATBS Polymers for Mangala Polymer Flood

Summary Mangala field has been under polymer flood since 2015. The polymer flood has been more successful in accelerating recovery compared to waterflood. As the flood matured, field performance indicated that part of the injected polymer was degrading in the reservoir. Laboratory studies and polymer samples collected from the reservoir suggest that the most likely reason for the degradation is increased hydrolysis due to thermal aging. This degradation compels higher dosing of polymer to make up for the lost viscosity and increases operating costs. Polymer precipitation in the reservoir may also lead to loss of reservoir permeability. Literature surveys and preliminary laboratory studies showed that polymers with acrylamide-tertiary-butyl-sulfonic acid monomer units (referred to as ATBS polymers) could be a suitable option for Mangala. To evaluate the hypothesis, the team did a series of laboratory and coreflood studies. The studies include accelerated thermal ageing, rheology, dynamic adsorption, injectivity, waterflood with fresh and degraded samples, and compatibility studies with topside chemicals. Two hydrolyzed polyacrylamide (HPAM) polymers with different degrees of hydrolysis (DOH) and two ATBS polymers were evaluated. The selected ATBS polymer was then tested for compatibility with surface topside chemicals. The studies show that the classic 20 to 25% DOH HPAM suffers viscosity degradation and possible precipitation in Mangala reservoir conditions. ATBS polymers and a lower DOH HPAM provide superior results to the incumbent HPAM with an acrylamide (AM) (86)-ATBS (14) copolymer providing the best results. ATBS polymers were especially resistant to cloudpoint lowering and provide some superiority in shear degradation. The ATBS monomer was resistant to hydrolysis during the period of testing. Contrary to the published literature, ATBS polymers showed higher adsorption and their propagation through cores required a higher pressure drop. ATBS polymer seemed to plug a low-permeability section of the core stack. All polymers reach their peak viscosity at 30 to 40% hydrolysis and decline sharply after 40%, but viscosity and cloudpoints measured during accelerated aging are possibly conservative. A large-scale pilot of ATBS injection in Mangala is under way to validate the laboratory test results. ATBS polymer can be a suitable polymer for some layers of Mangala with a high residence time and permeability. The choice is driven by the economics of the incremental cost of ATBS for the benefits it offers. In some sands with shorter interwell spacing, a lower DOH HPAM may be a more cost-effective solution. The study results in this paper provide insights to operators to understand the reservoir performance of existing polymer floods and plan for future polymer floods.

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.

Silica Nanoparticles in Xanthan Gum Solutions: Oil Recovery Efficiency in Core Flooding Tests.

Polymer flooding is one of the enhanced oil recovery (EOR) methods that increase the macroscopic efficiency of the flooding process and enhanced crude oil recovery. In this study, the effect of silica nanoparticles (NP-SiO2) in xanthan gum (XG) solutions was investigated through the analysis of efficiency in core flooding tests. First, the viscosity profiles of two polymer solutions, XG biopolymer and synthetic hydrolyzed polyacrylamide (HPAM) polymer, were characterized individually through rheological measurements, with and without salt (NaCl). Both polymer solutions were found suitable for oil recovery at limited temperatures and salinities. Then, nanofluids composed of XG and dispersed NP-SiO2 were studied through rheological tests. The addition of nanoparticles was shown to produce a slight effect on the viscosity of the fluids, which was more remarkable over time. Interfacial tension tests were measured in water-mineral oil systems, without finding an effect on the interfacial properties with the addition of polymer or nanoparticles in the aqueous phase. Finally, three core flooding experiments were conducted using sandstone core plugs and mineral oil. The polymers solutions (XG and HPAM) with 3% NaCl recovered 6.6% and 7.5% of the residual oil from the core, respectively. In contrast, the nanofluid formulation recovered about 13% of the residual oil, which was almost double that of the original XG solution. The nanofluid was therefore more effective at boosting oil recovery in the sandstone core.

Molecular Insights into Cyclodextrin-Adamantane-Modified Copolymer Host-Guest Interactions.

Supramolecular polymer flooding has great potential in solving the problems of difficult injection and low recovery in low-permeability polymer reservoirs. However, the self-assembly mechanism of supramolecular polymers is not yet to be fully understood at the molecular level. In this work, molecular dynamics simulations were used to explore the formation of cyclodextrin and adamantane-modified supramolecular polymer hydrogels; the self-assembly mechanism was summarized; and the effect of concentration on the oil displacement index was evaluated. The assembly mechanism of supramolecular polymers can be attributed to the "node-rebar-cement" mode of action. At the same time, Na+ can form intermolecular and intramolecular salt bridges with supramolecular polymers, and together with the "node-rebar-cement" mode of action, the supramolecular polymers can form a more compact 3D network structure. When the polymer concentration was increased, especially up to its critical association concentration (CAC), the association increased significantly. Besides, the construction of a 3D network was promoted, which results in a higher viscosity. This work investigated the assembly process of supramolecular polymers from the molecular scale and explained its mechanism of action, which makes up for the deficiencies of other research methods and provides a theoretical basis for screening out functional units that can be used for the supramolecular polymer assembly.

Performance assessment of a novel bio-based polymer for enhanced oil recovery in high salinity sandstone reservoirs

Polymer flooding is arguably the oldest chemical oil recovery method. The use of natural polymers in enhanced oil recovery process has gained wide acceptance due to their excellent viscosity, high resistance to challenging reservoir conditions ranging from increased salinities, temperatures and divalent cations. In recent times, research into the efficiency of green natural polymers is gaining attention as an eco-friendly, readily available and cost-effective option. In this study, the displacement efficiency of Abelmoschus esculentus as a natural polymer in recovering heavy crude from sandstone reservoirs was examined and a simulation model was built to replicate the laboratory model. Abelmoschus esculentus was cleaned, sun-dried, and grinded into powder form and enclosed in an airtight bag. The various phases were analyzed to ascertain the fluid-fluid compatibility and consistency. Polymer rheological studies was conducted at varied temperatures. Core flooding at optimum polymer concentration was considered in an oil-wet sandstone core under reservoir conditions. Results showed that the solubility of the fluids is a function of temperature. Furthermore, polymer viscosity showed a direct relationship to the polymer concentration and temperature. Polymer flooding resulted in additional recovery of 16.26 % oil initially in place (OIIP), thus affirming the efficiency of this natural polymer in recovering heavy oil. However, a viscosity enhancer is required for improved performance. The simulation model was built, and the recovery factors of both models was successfully matched.

Enhanced Oil Recovery

Abstract: Enhanced oil recovery procedures, which are part of improved oil recovery, are used to recover the leftover oil include Steam injection, Polymer flooding, Gas injection and Water injection. Only a small percentage of the total hydrocarbons in the reservoir can be recovered using standard oil recovery technologies. Even if normal recovery procedures are implemented, almost 2 trillion barrels of conventional oil and 5 trillion barrels of heavy oil will remain in reservoirs around the world. Many factors, both economic and technological, influence the strategy chosen and the projected recovery. The study evaluates the EOR approaches that are currently in use in the field. The current EOR technologies are put into context, with the technical reasons for their failure highlighted. Recovering additional oil is difficult and expensive, and it has only been done successfully in a few cases under strict conditions. Despite this, EOR will continue to play a significant role in oil production due to rising energy demand and constrained supply. It is estimated that a significant amount of research is required to develop new technologies for recovering almost two-thirds of the oil that remains unrecoverable in the reservoir. New methods of enhanced oil recovery improves the efficiency of existing processes and reduce demand for new reserves in the longer term. This paper represents the new technologies evolved in the petroleum industry for Enhanced oil recovery.

Experimental investigation on the degradation of polymer-containing oily sludge in sub-/supercritical water

ABSTRACT Polymer-containing oily sludge (PCOS) has caused tremendous hazards with the broad application of polymer flooding technology. Traditional methods cannot meet the treatment demand due to the high-water content of PCOS. In this work, the degradation of PCOS in sub-/supercritical water is studied to explore an appropriate treatment method. The influence of residence time (15–90 min), temperature (340–700°C), catalysts (sulfates, carbonates, and alkalis), and co-solvents (methanol-water and ethanol-water) on the distribution of end products is studied in details. Results show that PCOS is hardly gasified under the subcritical conditions and the increase in residence time and temperature has positive effects on the phase conversion. The conversion rate reaches 81.77% at 60 min, 340°C, compared to 67.09% at 15 min. Supercritical water shows a great solubility for PCOS, and no solid residues are detected at supercritical conditions (400–700°C, 23 MPa). Organic matter in liquid phase is classified into nine types, and the increase in temperature greatly changes its composition. The relative proportion of ketones reaches more than 50% of the organic matter in liquid at 400°C. Ketones are proven to be the main source of CO2 and disappear at above 500°C. Moreover, the migration of elements (carbon and nitrogen) is comprehensively studied.

Study on Micro-Displacement Mechanism and Reservoir Compatibility of Soft Dispersed Microgel.

Polymer flooding is a key technology for improving reservoir heterogeneity around the world, and it has made great progress. However, the traditional polymer has many shortcomings in the theory and application, which causes the efficiency of polymer flooding to gradually decrease and secondary reservoir damage after a long period of polymer flooding. In this work, a novel polymer particle (soft dispersed microgel, SMG) is used as the research object to further investigate the displacement mechanism and reservoir compatibility of SMG. The visualization experiments of the micro-model prove that SMG has excellent flexibility and can be highly deformable to realize deep migration through the pore throat smaller than SMG itself. The visualization displacement experiments of the plane model further show that SMG has a plugging effect, which makes the displacing fluid flow into the middle and low permeability layers, improving the recovery of these layers. The compatibility tests show that the optimal permeability of the reservoir for SMG-μm is 250-2000 mD, and the corresponding matching coefficient range is 0.65-1.40. For SMG-mm-, its corresponding optimal permeabilities of reservoir and matching coefficient are 500-2500 mD and 1.17-2.07, respectively. The comprehensive analysis demonstrates that the SMG has excellent ability of the water-flooding swept control and compatibility with reservoirs, having the potential to solve the problem of traditional polymer flooding.

Multi-objective global and local Surrogate-Assisted optimization on polymer flooding

Oil production and polymer injection are two performance indicators of polymer flooding and are usually conflicting objectives. In order to obtain optimal trade-off solutions, this paper proposes a multi-objective global and local surrogate-assisted particle swarm optimization (MO-GLSPSO) method, which consists of alternative steps: global population prescreen and local population search.The global steps use generalized regression neural network (GRNN) to prescreen a better population, and the local steps use radial basis function (RBF) as proxy to search for the next generation. The global steps aim to reduce the chance of generations being trapped in local minima, and the local steps obtain the optimal solutions with a fast convergence rate. The rates (liquid production rate and water injection rate) and polymer injection concentration of wells are tuned to obtain a Pareto-front that maximizes cumulative oil production and minimizes cumulative polymer injection.The MO-GLSPSO method is tested using both synthetic and Brugge benchmark cases. The iterations generally improve the oil production or reduce polymer injection and are stabilized at a Pareto-front of the two objectives. Improved sweep efficiency and polymer utility are also observed in the optimal results. The proposed method is also compared with other two methods, multi-objective genetic algorithm (MOGA) and multi-objective particle swarm optimization (MOPSO), to examine the pros and cons. The results indicate that MO-GLSPSO has a better pareto-front than others.

Research on Adaptability Evaluation Method of Polymer by Nuclear Magnetic Resonance Technology.

In order to study the matching relationship between polymer(HPAM) molecular weight and reservoir permeability, in this paper, the injection performance of polymers with different molecular weights in rock cores with different permeability is studied. Using nuclear magnetic resonance technology combined with conventional core displacement equipment, the change law of the displacement process was analyzed from three aspects of nuclear magnetic resonance T2 spectrum, core layering, and imaging. Finally, the fluidity of the polymer solution in the core was analyzed by injection pressure control features. The experimental results show that the polymer solution with a molecular weight of 25 million has the best retention effect in the core flooding experiment and can stay in the dominant channel of the core for a long time to control the water flooding mobility. In rocks with a permeability of 500, 1000, and 2000 mD, subsequent water flooding can expand the swept volume by about 25% compared with polymer flooding. This method can effectively establish the adaptability matching relationship between the polymer molecular weight and the reservoir permeability.

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.

Transient pressure analysis of polymer flooding fractured wells with oil-water two-phase flow

The oil-water two-phase flow pressure-transient analysis model for polymer flooding fractured well is established by considering the comprehensive effects of polymer shear thinning, shear thickening, convection, diffusion, adsorption retention, inaccessible pore volume and effective permeability reduction. The finite volume difference and Newton iteration methods are applied to solve the model, and the effects of fracture conductivity coefficient, injected polymer mass concentration, initial polymer mass concentration and water saturation on the well-test type curves of polymer flooding fractured wells are discussed. The results show that with the increase of fracture conductivity coefficient, the pressure conduction becomes faster and the pressure drop becomes smaller, so the pressure curve of transitional flow goes downward, the duration of bilinear flow becomes shorter, and the linear flow appears earlier and lasts longer. As the injected polymer mass concentration increases, the effective water phase viscosity increases, and the pressure loss increases, so the pressure and pressure derivative curves go upward, and the bilinear flow segment becomes shorter. As the initial polymer mass concentration increases, the effective water phase viscosity increases, so the pressure curve after the wellbore storage segment moves upward as a whole. As the water saturation increases, the relative permeability of water increases, the relative permeability of oil decreases, the total oil-water two-phase mobility becomes larger, and the pressure loss is reduced, so the pressure curve after the wellbore storage segment moves downward as a whole. The reliability and practicability of this new model are verified by the comparison of the results from simplified model and commercial well test software, and the actual well test data.

Insight into polymer concentration, temperature, CO2 content, and Cl− content on corrosion of N80 steel tubing in polymer flooding

AbstractThe corrosion of N80 steel in polymer flooding is studied, and the safe service life of N80 steel tubing is calculated. The results show that the temperature is the main factor affecting the corrosion of tubing during the process of polymer flooding, and the safe service life of N80 carbon steel tubing at 75°C is only 11.1 years. The polymer is connected by molecular chains to form a network structure and then adsorbed on the surface of the steel. As the polymer concentration increases, the space between polymer molecules becomes smaller; the exposed surface area decreases; and the corrosion rate of N80 steel decreases. Both temperature and Cl− ions destroy the adsorption capacity of the polymer on the carbon steel substrate. The negatively charged chloride ion repels the negatively charged polymer, leading to the resolution of the polymer and reduction of the corrosion inhibition of the polymer. High temperature destroys the polymer's intramolecular and intermolecular aggregation, and also wrecks the long molecular chain polymer structure, significantly inhibiting the corrosion inhibition effect of the polymer.

Numerical simulation of in-depth profile control for dispersed particle gel in heterogeneous reservoirs

Introduction: As a new agent of enhancing oil recovery, the dispersed particle gel (DPG) has been gradually used for in-depth profile control in mature oilfields. Many researchers investigated the preparation, profile control mechanism and application of DPG based on a series of laboratory experiments. However, few numerical studies have been carried out on profile control mechanism of DPG.Methods: This paper proposes a novel mathematical model to proceed numerical simulation of profile control for DPG, considering DPG particles adsorption and weak shear thinning effects. The numerical codes are verified by the UTCHEM simulator.Results and discussion: The effects of the DPG viscosity, the DPG concentration, the water saturation of high permeable regions and the permeability ratio between high and low permeable regions on decreasing the water-cut of producing well are studied. Simultaneously, this paper also investigates the influence of different mobility ratios between high and low permeable regions on water shutoff of DPG. The numerical simulation results show that the effects of DPG profile control become better as the DPG solution viscosity, the suspension concentration and the permeability ratio increase. But the increased water saturation of high permeable regions is not helpful to improve oil recovery. Water plugging effect of DPG becomes worse with increasing mobility ratio between different regions. According to comparison results between DPG profile control and polymer flooding, it is found that DPG profile control is more suitable for heterogeneous reservoirs. These findings are of benefit to guide the efficient field application of DPG profile control in heterogeneous reservoirs.

The Effect of Shear on the Properties of an Associated Polymer Solution for Oil Displacement.

Polymer flooding is one of the techniques used to enhance oil recovery from depleted hydrocarbon reservoirs. Although this technology is popular for this application, the shearing effect in the injection process causes poor performance, which is an obstacle to meeting the needs of the formation. An experimental evaluation of the rheological properties, viscoelasticity, hydrodynamic size, static adsorption, and seepage characteristics of the associated polymer solution before and after shearing was conducted to determine the influence of shearing on the polymer solution. The results show that the effect of shear on the polymer was irreversible, and the properties of the polymer solution damaged by shear were attenuated. After the critical associating concentration, the associated polymer can recover its solution properties through hydrophobic association, which can improve the shear resistance of the polymer solution and make its own rheological law and reduce the viscoelastic change. Although the hydrodynamic size, viscoelasticity, and adsorption capacity of the polymer solution after shear failure decreased, strong flow resistance during porous media seepage and mobility control was achieved. Improving the shear resistance of the polymer solution by increasing the intermolecular force is proposed to develop new polymer systems for subsequent oil displacement.