Progress of polymer gels for conformance control in oilfield

Recent advances of intelligent polymer gels as active carriers for medical imaging-guided cancer therapy: A review

Cancer is a major global health challenges and various imaging-guided techniques are gaining prominence for its diagnosis and therapy with the advantages of high sensitivity, spatial resolution, and quantitative capability. The effectiveness of these approaches mainly relies on the establishment of a responsive platform. The intelligent polymer gel composites as the active carriers have drawn considerable attention owing to their outstanding versatility, three-layer network structure, mechanical adjustability and so forth, which may be contribute to loading drug, imaging probe, and targeting biomarkers in medical imaging-guided cancer therapy (IGCT). In this review, significant progress has been highlighted in fabrication of intelligent polymer gel composites with multi-functional molecules for the anticancer drugs delivery systems, multimodal imaging-guided management and developing molecular devices in various tumors. In addition, we also explore the current challenges and future development directions of these composites as carriers with the assistance of IGCT for precise anti-cancer applications in clinical practice.

Controls on microbially-induced carbonate precipitation in geologic porous media

Microbially-induced carbonate precipitation (MICP) provides a natural biomineralization approach to secure the geologic storage of gases (e.g., carbon dioxide, hydrogen and methane). Cracks in embrittled wellbore cement, for example, provide a pathway for atmospheric gas leakage, while permeability heterogeneities in the storage reservoir leads to fingering effects that diminish the storage capacity. The design of MICP processes, however, remains a challenge due to limited understanding of the coupled nonlinear reaction kinetics and multiphase transport involved. Specifically, previous attempts at MICP through porous media have been encumbered by carbonate precipitation localized to the first ∼ cm of the bulk injection surface. In this study, we investigate the reactive transport controls on MICP necessary to enable deep MICP penetration into the formation. We use a micromodel with pore geometry and geochemistry representative of real geologic media to image direct pore- and pore-ensemble-level mineral, fluid, and microbial distributions. An approach to adsorb microbes uniformly across the micromodel, rather than local accumulation near the inlet, is developed that enables deep MICP penetration into the porous medium. A sensitivity analysis was performed to investigate the impact of injection conditions (e.g., rates, concentrations) required to maximize CaCO3 precipitation away from the injection site. With multiple cycles of MICP, a ∼ 78 % reduction in permeability was achieved with ∼8 % carbonate pore volume occupation. Overall, this study establishes the possibility of MICP as an effective and controllable method to enhance the security of gas storage in geologic media.

Preparation and Effect of CO2 Response Gel for Plugging Low-Permeability Reservoirs

In order to solve the problem of gas channeling during CO2 flooding in low-permeability reservoirs, a novel CO2 responsive gel channeling system was prepared by using carrageenan, branched polyethylene imide and ethylenediamine under laboratory conditions. Based on the Box-Behnken response surface design method, the optimal synthesis concentration of the system was 0.5 wt% carrageenan, 2.5 wt% branchized polyethylenimide and 6.5 wt% ethylenediamine. The micromorphology of the system before and after response was characterized by scanning electron microscopy. The rheology and dehydration rate were tested under different conditions. The channeling performance and enhanced oil recovery effect of the gel system were simulated by a core displacement experiment. The experimental results show that the internal structure of the system changes from a disordered, smooth and loosely separated lamellae structure to a more uniform, complete and orderly three-dimensional network structure after exposure to CO2. The viscosity of the system was similar to aqueous solution before contact with CO2 and showed viscoelastic solid properties after contact with CO2. The experiment employing dehydration rates at different temperatures showed that the internal structure of the gel would change at a high temperature, but the gel system had a certain self-healing ability. The results of the displacement experiment show that the plugging rate of the gel system is stable at 85.32% after CO2 contact, and the recovery rate is increased by 17.06%, which provides an important guide for the development of low-permeability reservoirs.

Preparation and Performance Evaluation of Self-Cementing Nanoscale Polymeric Microspheres with Salt and Temperature Tolerance

Polymer microspheres with temperature and salt resistance were synthesized using the anti-suspension polymerization method, incorporating the functional monomers AMPS, AM, and AA. To enhance their self-gelling properties, the microspheres were designed with a core-shell structure. The shell is composed of a polymeric surfactant, fatty alcohol polyoxyethylene ether methacrylate (AEOMA), which serves as a thermosensitive crosslinking agent, enabling self-crosslinking upon shell decomposition, addressing compatibility with reservoir pore throat dimensions. Comprehensive characterizations including infrared spectroscopy, scanning electron microscopy, optical microscopy, and laser particle size analysis were conducted. The microspheres exhibited successful synthesis, a nanoscale size, and regular spherical morphology. They demonstrated excellent temperature and salt resistance, making them suitable for high-temperature, high-salinity reservoir profile control. With a stable three-dimensional network structure, the microspheres displayed good expansion behavior due to hydrophilic groups along the polymer chains, resulting in favorable water affinity. Even after aging, the microspheres maintained their gelling state with a distinct and stable microscopic network skeleton. They exhibited superior plugging performance in low-permeability reservoirs, while effectively improving water absorption profiles in reservoirs with permeability contrasts of 10 to 80, thereby enhancing oil recovery.

Study on a Strong Polymer Gel by the Addition of Micron Graphite Oxide Powder and Its Plugging of Fracture

It is difficult to plug the fracture water channeling of a fractured low-permeability reservoir during water flooding by using the conventional acrylamide polymer gel due to its weak mechanical properties. For this problem, micron graphite powder is added to enhance the comprehensive properties of the acrylamide polymer gel, which can improve the plugging effect of fracture water channeling. The chemical principle of this process is that the hydroxyl and carboxyl groups of the layered micron graphite powder can undergo physicochemical interactions with the amide groups of the polyacrylamide molecule chain. As a rigid structure, the graphite powder can support the flexible skeleton of the original polyacrylamide molecule chain. Through the synergy of the rigid and flexible structures, the viscoelasticity, thermal stability, tensile performance, and plugging ability of the new-type gel can be significantly enhanced. Compared with a single acrylamide gel, after adding 3000 mg/L of micrometer-sized graphite powder, the elastic modulus, the viscous modulus, the phase transition temperature, the breakthrough pressure gradient, the elongation at break, and the tensile stress of the acrylamide gel are all greatly improved. After adding the graphite powder to the polyacrylamide gel, the fracture water channeling can be effectively plugged. The characteristics of the networked water flow channel are obvious during the injected water break through the gel in the fracture. The breakthrough pressure of water flooding is high. The experimental results are an attempt to develop a new gel material for the water plugging of a fractured low-permeability reservoir.

Analysis of the Distribution Pattern of Remaining Oil and Development Potential after Weak Gel Flooding in the Offshore LD Oilfield

The LD oilfield is one of the representative offshore oilfields. After weak gel flooding, the recovery rate is significantly improved. However, the oilfield is then in a medium- to high-water content stage, presenting a complex distribution of the remaining oil. The measures for further enhanced oil recovery (EOR) are uncertain. As a result, it is necessary to clarify the distribution pattern and development potential of the remaining oil during the high-water content period after weak gel flooding. In this study, an online nuclear magnetic resonance (NMR) oil displacement experiment and microscopic oil displacement experiment were conducted, and the mechanisms of weak gel flooding and the distribution pattern of the remaining oil were clarified in the LD oilfield. Additionally, high-multiple water flooding and numerical simulation experiments were conducted to analyze the development potential after weak gel flooding. The results show that the effect of weak gel flooding was more significant in the core of 1500 mD, with an increase in oil recovery of 9% compared to 500 mD. At a permeability of 500 mD, the degree of crude oil mobilization in micropores and small pores caused by weak gel flooding was improved by 29.64% and 23.48%, respectively, compared with water flooding. At 1500 mD, the degree of crude oil mobilization in small pores caused by weak gel flooding was increased by 37.79% compared to water flooding. After weak gel flooding, the remaining oil was primarily distributed in medium and large pores. Microscopically, the remaining oil was dominated by cluster residual oil, accounting for 16.49%, followed by columnar, membranous, and blind-end residual oil. High multiple water flooding experiments demonstrated that weak gel flooding could significantly reduce development time. The ultimate oil recovery efficiency of 500 mD and 1500 mD reached 71.85% and 80.69%, respectively. Numerical simulation results show that the ultimate oil recovery efficiency increased from 62.04% to 71.3% after weak gel flooding. This indicated that the LD oilfield still had certain development potential after weak gel flooding. The subsequent direction for enhanced oil recovery focuses mainly on mobilizing oil in medium pores or clustered remaining oil. This will play a crucial role in further exploring methods for utilizing the remaining oil and increasing the recovery rate.

Advances of polymer microspheres and its applications for enhanced oil recovery

After long-term water injection, mature reservoirs are encountered with the adverse consequences of the treatment, including erosion, rock formation destruction and drastic decline in oil recovery rate for the past years. Today, the inexpensive and highly efficient polymer microspheres can be considered as a solution to the current issue with excess water production. Studies on practical utilization of polymer microspheres to plug high-permeability zones in heterogeneous reservoirs gained immense popularity in oil production lately. This review aims to give classification to polymer microspheres, including fluorescent polymer microspheres, low elastic polymer microspheres, viscoelastic polymer microspheres and nano-composite polymer microspheres and discuss the specific structural and behavioral traits of each polymer microsphere. Differences in preparation methods, comparisons of performance evaluation and oil recovery rate assessment were also studied. The current complications with functional application of polymer microspheres and its further improvements were considered. This review will provide assistance to the researchers with further advancements of the polymer microspheres, by effectively increasing the oil recovery levels in heterogeneous reservoirs, which will also meet the economical and ecological requirements of the oilfields.

Atomic Force Microscopy of Hydrolysed Polyacrylamide Adsorption onto Calcium Carbonate

In this work, the interaction of hydrolysed polyacrylamide (HPAM) of two molecular weights (F3330, 11-13 MDa; F3530, 15-17 MDa) with calcium carbonate (CaCO3) was studied via atomic force microscopy (AFM). In the absence of polymers at 1.7 mM and 1 M NaCl, good agreement with DLVO theory was observed. At 1.7 mM NaCl, repulsive interaction during approach at approximately 20 nm and attractive adhesion of approximately 400 pN during retraction was measured, whilst, at 1 M NaCl, no repulsion during approach was found. Still, a significantly larger adhesion of approximately 1400 pN during retraction was observed. In the presence of polymers, results indicated that F3330 displayed higher average adhesion (450-625 pN) and interaction energy (43-145 aJ) with CaCO3 than F3530's average adhesion (85-88 pN) and interaction energy (8.4-11 aJ). On the other hand, F3530 exerted a longer steric repulsion distance (70-100 nm) than F3330 (30-70 nm). This was likely due to the lower molecular weight. F3330 adopted a flatter configuration on the calcite surface, creating more anchor points with the surface in the form of train segments. The adhesion and interaction energy of both HPAM with CaCO3 can be decreased by increasing the salt concentration. At 3% NaCl, the average adhesion and interaction energy of F3330 was 72-120 pN and 5.6-17 aJ, respectively, while the average adhesion and interaction energy of F3530 was 11.4-48 pN and 0.3-2.98 aJ, respectively. The reduction of adhesion and interaction energy was likely due to the screening of the COO- charged group of HPAM by salt cations, leading to a reduction of electrostatic attraction between the negatively charged HPAM and the positively charged CaCO3.

Rheology of Gels and Yielding Liquids

In this review, today's state of the art in the rheology of gels and transition through the yield stress of yielding liquids is discussed. Gels are understood as soft viscoelastic multicomponent solids that are in the incomplete phase separation state, which, under the action of external mechanical forces, do not transit into a fluid state but rupture like any solid material. Gels can "melt" (again, like any solids) due to a change in temperature or variation in the environment. In contrast to this type of rheology, yielding liquids (sometimes not rigorously referred to as "gels", especially in relation to colloids) can exist in a solid-like (gel-like) state and become fluid above some defined stress and time conditions (yield stress). At low stresses, their behavior is quite similar to that of permanent solid gels, including the frequency-independent storage modulus. The gel-to-sol transition considered in colloid chemistry is treated as a case of yielding. However, in many cases, the yield stress cannot be assumed to be a physical parameter since the solid-to-liquid transition happens in time and is associated with thixotropic effects. In this review, special attention is paid to various time effects. It is also stressed that plasticity is not equivalent to flow since (irreversible) plastic deformations are determined by stress but do not continue over time. We also discuss some typical errors, difficulties, and wrong interpretations of experimental data in studies of yielding liquids.

Water-Induced Cellulose Nanofibers/Poly(vinyl alcohol) Hydrogels Regulated by Hydrogen Bonding for In Situ Water Shutoff

Hydrogels have been widely applied to the water shutoff in oilfields due to their excellent three-dimensional network and thermal and physicochemical stability, and it is still a huge challenge to develop new hydrogels with simple preparation, low cost, and high mechanical performance that can meet the requirements of practical applications. Herein, we devised a simple and universal manufacturing method for regulating the hydrogen bonds between poly(vinyl alcohol) (PVA) and cellulose nanofibers (CNF) via the water-diffusion action, thus fabricating a physically tough PVA-CNF hydrogel for the in situ water shutoff. This method allowed the polymer chains to strengthen the molecular interactions between polymers upon replacing with water (a poor solvent) to regulate the cross-linking structure, characterizing by the nano-crystallinity domains and fibrillar segments, which also accounted for the thermal stability, extraordinary elasticity, high stretchability, and toughness of PVA-CNF hydrogel. Further, the obtained PVA-CNF hydrogel exhibited superb plugging performance, that is, the breakthrough pressure gradient could reach 71.56 MPa·m-1, surpassing all currently reported gelling water shutoff agents. This water-induced in situ hydrogelation made it well suited as a water shutoff agent in oilfields and may provide a promising strategy to fabricate mechanically robust smart materials for the water shutoff projects with low cost, simple processing, and high efficiency.

Synthesis and Performance Evaluation of Alginate-Coated Temperature-Sensitive Polymer Gel Microspheres

With the long-term water-flooding development of the reservoir, the non-homogeneity of the formation is increasing and the reservoir environment is deteriorating; the microspheres used for deep plugging have shown disadvantages, such as poor temperature and salt resistance and faster expansion. In this study, a polymeric microsphere was synthesized that is resistant to high temperature and high salt and can achieve slow expansion and slow release for deep migration. P(AA-AM-SA)@TiO₂ polymer gel/inorganic nanoparticle microspheres were prepared by reversed-phase microemulsion polymerization using acrylamide (AM) and acrylic acid (AA) as monomers, 3-methacryloxypropyltrimethoxysilane (KH-570)-modified TiO₂ as the inorganic core, and sodium alginate (SA) as a temperature-sensitive coating material. Through single-factor analysis of the polymerization process, the optimal synthesis conditions were determined as follows: the oil(Cyclohexane)-water volume ratio was 8:5, the emulsifier mass ratio (Span-80:Tween-80) was 3:1 (10 wt% of the total system amount), the stirring speed was 400 r/min, the reaction temperature was 60 °C, and the initiator (ammonium persulfate and sodium bisulfite) dosage was 0.6 wt%. The size of the dried polymer gel/inorganic nanoparticle microspheres prepared by the optimized synthesis conditions was 10~40 μm with uniform particle size. The observation of P(AA-AM-SA)@TiO₂ microspheres reveals that the Ca elements are uniformly distributed on the microspheres, and FT-IR indicates that the synthesized product is the target product. TGA shows that the polymer gel/inorganic nanoparticle microspheres have better thermal stability after the addition of TiO₂, with a larger mass loss at 390 °C, which can adapt to the medium-high permeability reservoir environment. The thermal and aqueous salinity resistance of the P(AA-AM-SA)@TiO₂ microspheres was tested, and the cracking temperature of P(AA-AM-SA)@TiO₂ microsphere temperature-sensitive material was 90 °C. It still has favorable water absorption and swelling performance under the sodium salt concentration of 2.5 × 10⁴ mg/L and can tolerate calcium salt up to 2.0 × 10⁴ mg/L. Plugging Performance Test results show that the microspheres have good injectability between the permeability of 1.23 and 2.35 μm² and good plugging effect near the permeability of 2.20 μm². At high temperature and high salinity, P(AA-AM-SA)@TiO₂ microspheres have a remarkable effect on profile control and water shutoff, the plugging rate reaches 95.3%, and the oil recovery rate is increased by 12.89% compared with water flooding, achieving the effect of slow swelling and slow release.

High stretchable and self-healing nanocellulose-poly(acrylic acid) composite hydrogels for sustainable CO2 shutoff

The injection of CO₂ into oil reservoirs to enhance oil recovery (EOR) has become a widely accepted and effective technical method, which, however, remains subject to the gas channeling caused by the reservoir fractures. Herein, this work developed a novel plugging gel combining excellent mechanical properties, fatigue resistance, elastic and self-healing properties for the CO₂ shutoff purpose. This gel consisting of grafted nanocellulose and polymer network was synthesized via a free-radical polymerization, and reinforced by using Fe³⁺ to cross-link the two networks. The as-prepared PAA-TOCNF-Fe³⁺ gel has a stress of 1.03 MPa and a high strain of 1491 %, and self-heals to its original 98 % in stress and 96 % in strain after rupture, respectively. The introduce of TOCNF/Fe³⁺ improves the excellent energy dissipation and self-healing via the synergy effect of dynamical coordination bonds and hydrogen bonds. Further, the PAA-TOCNF-Fe³⁺ gel is both flexible and high-strength in plugging the multi-round CO₂ injection, during which the CO₂ breakthrough pressure is above 9.9 MPa/m, the plugging efficiency exceeds 96 %, and the self-healing rate is larger than 90 %. Given that above, this gel shows a great potential to plug the high-pressure CO₂ flow, which could offer a new method for CO₂-EOR and carbon storage.

Preparation Method and Performance Evaluation of a Gel Based on AM/AMPS Copolymer

Polymer gels have been widely used in high water cut oilfields for profile control and water plugging. It is urgent to develop a gel suitable for the Tahe Oilfield (Temperature: 130 °C, salinity: 2.2 × 10⁵ mg/L) in China. A stable gel was prepared by using an acrylamide (AM)/2-acrylamide-2-methyl propanesulfonic acid (AMPS) copolymer crosslinked with urotropin (HMTA), hydroquinone (HQ), thiourea and Nano-SiO₂. This paper covers a step-by-step process for designing gels based on experience with preparing gels. A wide range of combinations between polymers and crosslinking agents with and without stabilizers were investigated, and the results indicated that there is an optimal value of AMPS content of AM/AMPS copolymers in the preparation of gels. Increasing the mass fraction of copolymer and using stabilizer enhanced the performance of gel, but an excessive amount of crosslinking agent was not conducive to the stability of gel. The work optimized the formula of plugging agent suitable for the high temperature and high salt (HTHS) condition in the Tahe Oilfield. The gelling solution had a long gelation time of 20 h. The gel had high strength (Sydansk's gel-strength code of "G") with storage modulus of 12.9 Pa and could be stable for half a year at 130 °C and 2.2 × 10⁵ mg/L of salinity. The plate model that could be heated and pressurized was used to simulate the oil flooding and profile modification under the condition of the Tahe Oilfield for the first time. The experiment results showed that the oil recovery could be increased by 13.22% by subsequent water flooding under heterogeneous formation condition. Therefore, it was fully confirmed that the plugging performance of AM/AMPS phenolic gel prepared in the work was excellent. The information provided in the study could be used as a reference for the design and evaluation of polymer gels in other HTHS reservoirs.

Exploration of Super-Gravity Rapid Dissolution Method of Polymer for Offshore Oil Repellent

The long dissolution time and large dispensed volumes of oil repellent polymers in offshore oil fields lead to a great increase in the volume and number of dissolution and maturation tanks in the polymer formulation system. However, there is limited space and load-bearing capacity at the offshore platform and only a small space is available for the dispensing system. To further optimize the polymer dispensing system and reduce its floor space, the super-gravity technology may be considered as a way to speed up the dissolution of the polymer. The mechanism of super-gravity rapid dissolution was investigated by establishing mathematical models and with indoor experiments. The effects of filler pore size and super-gravity factor on polymer dissolution time and solution viscosity were investigated using the super-gravity rapid dissolution device, then combined with established graded forced stretching devices for field magnification experiments. The results indicated that the super-gravity method can substantially shorten the polymer dissolution time. The basic dissolution time of the polymer AP-P4 was shortened by 35 min compared with the conventional formulation method after use of the super-gravity rapid dissolution device. The optimal process conditions for the preparation of polymer solution by the super-gravity rapid dissolution device were selected as the optimal super-gravity factor range of 1031~1298.

Thermo-/pH-Dual-Sensitive PEG/PAMAM Nanogel: Reaction Dynamics and Plugging Application of CO2 Channeling

Smart hydrogels, owing to their exceptional viscoelastic and deformable capacity in response to environmental stimulation involving temperature and pH, have been successfully applied in oilfields for purposes such as water and/or gas shutoff treatments. However, the CO₂ breakthrough problem in low permeability reservoirs has not been well solved. In this work, a rheological method-based Avrami dynamics model and Dickinson dynamics model were employed to investigate the dynamic gelation process of thermo-/pH-dual-sensitive PEG/PAMAM nanogels to further our understanding of the microstructure of their gelation and pertinence plugging application. Plugging experiments were performed by alternating injections of CO₂ and hydrogel solution in a slug type on three fractured low permeability cores with a backpressure of 13 MPa. The nanogels presented a secondary growth pattern from three to one dimension from micrometer to nanometer size with a morphological transformation from a sphere to an irregular ellipsoid or disk shape. The phase transition temperature was 50 °C, and the phase transition pH was 10. If both or either were below these values, the hydrogel swelled; otherwise, it shrank. Plugging results show that the plugging efficiency was higher than 99%. The maximum breakthrough pressure was 19.93 MPa, and the corresponding residual pressure remained 17.64 MPa for a 10 mD core, exhibiting great plugging performance and high residual resistance after being broken through by CO₂.

Polymer Gels Used in Oil-Gas Drilling and Production Engineering

Polymer gels are widely used in oil-gas drilling and production engineering for the purposes of conformance control, water shutoff, fracturing, lost circulation control, etc. Here, the progress in research on three kinds of polymer gels, including the in situ crosslinked polymer gel, the pre-crosslinked polymer gel and the physically crosslinked polymer gel, are systematically reviewed in terms of the gel compositions, crosslinking principles and properties. Moreover, the advantages and disadvantages of the three kinds of polymer gels are also comparatively discussed. The types, characteristics and action mechanisms of the polymer gels used in oil-gas drilling and production engineering are systematically analyzed. Depending on the crosslinking mechanism, in situ crosslinked polymer gels can be divided into free-radical-based monomer crosslinked gels, ionic-bond-based metal cross-linked gels and covalent-bond-based organic crosslinked gels. Surface crosslinked polymer gels are divided into two types based on their size and gel particle preparation method, including pre-crosslinked gel particles and polymer gel microspheres. Physically crosslinked polymer gels are mainly divided into hydrogen-bonded gels, hydrophobic association gels and electrostatic interaction gels depending on the application conditions of the oil-gas drilling and production engineering processes. In the field of oil-gas drilling engineering, the polymer gels are mainly used as drilling fluids, plugging agents and lost circulation materials, and polymer gels are an important material that are utilized for profile control, water shutoff, chemical flooding and fracturing. Finally, the research potential of polymer gels in oil-gas drilling and production engineering is proposed. The temperature resistance, salinity resistance, gelation strength and environmental friendliness of polymer gels should be further improved in order to meet the future technical requirements of oil-gas drilling and production.

Injection of Gelling Systems to a Layered Reservoir for Conformance Improvement

The paper describes the introduction and estimation of performance criteria for the gelling agent injection technology based on a general approach to modeling physical and chemical enhanced oil recovery (EOR) methods. The current mathematical models do not include performance criteria for the process of gelling agent injection and do not allow for assessing the level of success of a treatment job in production wells. The paper introduces such criteria for the first time. To simulate the effect on injection wells, the mass conservation laws and the generalized flow law are used, and closing relations for the gelling rate are taken into account. A conformance control coefficient is introduced which characterizes the positive effect of well treatments and injectivity drop which characterizes the negative effect. The performance criteria allow for identifying the wells where the treatment jobs were the most successful. The model verification, based on the comparison of post-treatment injectivity estimated in the developed model, with Rosneft’s field data showed a satisfactory match. The developed correlations can be used as the basis for a surrogate model that allows for avoiding building sector geological and flow simulation models of the treated zone.

Dilational Rheological Properties of Surfactants at the Crude Oil-Water Interface: The Effect of Branch-Preformed Particle Gels and Polymers

The interfacial properties of a heterogeneous composite flooding system containing a surfactant fatty alcohol polyoxyethylene carboxylate (C₁₂EO₃C), branched-preformed particle gel (B-PPG), and polymer partly hydrolyzed polyacrylamide (HPAM) at the crude oil-water interface were investigated by a dilational rheology method. The results demonstrated that the C₁₂EO₃C molecules can form an elastic interfacial film with certain strength at the crude oil-water interface. The addition of HPAM to the C₁₂EO₃C solution has a detrimental effect on the interfacial film formed by C₁₂EO₃C molecules, leading to a decrease in the dilational modulus and an increase in the phase angle. Moreover, the addition of B-PPG to the C₁₂EO₃C solution also disrupts the stability and strength of the interfacial film of C₁₂EO₃C. In particular, linear HPAM with a lower steric hindrance is more likely to insert into the interfacial film of C₁₂EO₃C; thus, HPAM possesses a stronger destruction ability for the interfacial film of C₁₂EO₃C than B-PPG. When HPAM is compounded with B-PPG, a superimposed effect exists to cause more severe disruption for the interfacial film. The heterogeneous composite flooding system not only enhances oil recovery by increasing the viscosity of the bulk phase but also weakens the interfacial film to facilitate the post-treatment of the recovered crude oil. Thus, the heterogeneous composite flooding system exhibits promising prospects in practical application.

Experimental Investigation of Steam Conformance Evolution in Vertical-CSS and Optimization of Profile Improvement Agents

Production performance of heavy oil deposits in Xinjiang oilfield developed by vertical-well cyclic steam stimulation (CSS) is increasingly challenged by reservoir heterogeneity, which is comprised of original sedimental heterogeneity and steam-induced heterogeneity. In order to understand the impacts of sedimental heterogeneity and high-speed steam injection to steam conformance, and strategies to maximize steam swept volume, a series of experiments were designed and implemented. Three-tube coreflooding experiments were performed to study the steam displacement dynamics under heterogeneous conditions, and a high-temperature plugging agent was developed. The coreflooding experiments indicate that the injection conformance deteriorates once the steam breakthrough occurs in a high-permeability tube, leaving the oil in the medium and low permeability tubes being surpassed. The optimized plugging agent could resist high temperatures over 260 °C and its compressive strength was 13.14 MPa, which is higher than maximal steam injection pressure. The plugging rate of high permeability core was greater than 99.5% at 220–280 °C with a breakthrough pressure gradient over 25 MPa/m. The field test validated its profile improvement feasibility with cyclic oil, 217.6% of the previous cycle. The plugging agent optimized in this study has significant potential for similar heterogeneous reservoirs.

Types and Performances of Polymer Gels for Oil-Gas Drilling and Production: A Review

Polymer gels with suitable viscoelasticity and deformability have been widely used for formation plugging and lost circulation control, profile control, and water shutoff. This article systematically reviews the research progress on the preparation principle, temperature resistance, salt resistance, and mechanical properties of the ground and in situ crosslinked polymer gels for oil-gas drilling and production engineering. Then, it comparatively analyzes the applicable conditions of the two types of polymer gel. To expand the application range of polymer gels in response to the harsh formation environments (e.g., high temperature and high salinity), we reviewed strategies for increasing the high temperature resistance, high salt resistance, and rheological/mechanical strengths of polymer gels. This article provides theoretical and technical references for developing and optimizing polymer gels suitable for oil-gas drilling and production.

Comprehensive Review of Polymer and Polymer Gel Treatments for Natural Gas-Related Conformance Control

Conformance problems often exist in natural gas-related activities, resulting in excessive water production from natural gas production wells and/or excessive natural gas production from oil production wells. Several mechanical and chemical solutions were reported in the literature to mitigate the conformance problems. Among the chemical solutions, two classes of materials, namely polymer gels and water-soluble polymers, have been mostly reported. These systems have been mainly reviewed in several studies for their applications as water shutoff treatments for oil production wells. Natural gas production wells exhibit different characteristics and have different properties which could impact the performance of the chemical solutions. However, there has not been any work done on reviewing the applications of these systems for the challenging natural gas-related shutoff treatments. This study provides a comprehensive review of the laboratory evaluation and field applications of these systems used for water control in natural gas production wells and gas shutoff in oil production wells, respectively. The first part of the paper reviews the in-situ polymer gel systems, where both organically and inorganically crosslinked systems are discussed. The second part presents the water-soluble polymers with a focus on their disproportionate permeability reduction feature for controlling water in gas production wells. The review paper provides insights into the reservoir conditions, treatment design and intervention, and the success rate of the systems applied. Furthermore, the outcomes of the paper will provide knowledge regarding the limitations of the existing technologies, current challenges, and potential paths forwards.

Review of Microgels for Enhanced Oil Recovery: Properties and Cases of Application

In todays' world, there is an increasing number of mature oil fields every year, a phenomenon that is leading to the development of more elegant enhanced oil recovery (EOR) technologies that are potentially effective for reservoir profile modification. The technology of conformance control using crosslinked microgels is one the newest trends that is gaining momentum every year. This is due to the simplicity of the treatment process and its management, as well as the guaranteed effect in the case of the correct well candidate selection. We identified the following varieties of microgels: microspheres, thermo- and pH-responsible microgels, thin fracture of preformed particle gels, colloidal dispersed gels. In this publication, we try to combine the available chemical aspects of microgel production with the practical features of their application at oil production facilities. The purpose of this publication is to gather available information about microgels (synthesis method, monomers) and to explore world experience in microgel application for enhanced oil recovery. This article will be of great benefit to specialists engaged in polymer technologies at the initial stage of microgel development.

Polyoxometalate-Containing Supramolecular Gels

Supramolecular gels are important soft materials with various applications, which are fabricated through hydrogen bonding, π-π stacking, electrostatic or host-guest interactions. Introducing functional groups, especially inorganic components, is an efficient strategy to obtain gels with robust architecture and high performance. Polyoxometalates (POMs), as a class of negatively-charged clusters, have defined structures and multiple interaction sites, resulting in their potential as building blocks for constructing POM-containing supramolecular gels. The introduction of POMs into gels not only provides strong driving forces for the formation of gels due to the characteristics of charged cluster and oxygen-rich surface, but also brings new properties sourcing from unique electronic structures of POMs. Though many POM-containing gels have been reported, a comprehensive review is still absent. Herein, the concept of POM-containing gels is discussed, following with the design strategies and driving forces. To better understand the results in the literature, detailed examples, which are classified into several categories based on the types of organic components, are presented to illustrate the gelation process and gel structures. Moreover, applications of POM-containing gels in energy chemistry, sustainable chemistry and other aspects are also reviewed, as well as the future developments of this field. This article is protected by copyright. All rights reserved.