Search Results (35)

A low-permeability, high salinity reservoir entered the high-water-cut and high recovery degree stage in the middle and late stages of development, and it is difficult to tap the potential of water flooding. The overall water flooding recovery of the developed low-permeability reservoir is low, and the produced water has high oil content, many granular impurities, and high inorganic salt content. The polymer–surfactant binary system was studied according to the reservoir conditions. The polymer acrylic acid/polyacrylamide/2-acryloylamino-2-methyl-1-propanesulfonic acid was selected by viscosity measurement. The viscosity stability of the polymer and the effect of the flooding system were evaluated, and the salt-tolerant surfactant sulfonated betaine + amides and coco composite system were screened, and the viscosity, interfacial tension, and displacement effect were evaluated. Finally, the polymer–surfactant binary flooding system was formed. The system has good compatibility, the interfacial tension can still be reduced to 10⁻³ mN/m at 40 °C and 23,800 mg/L, and the viscosity of the polymer solution increased by 5.8% upon addition of the surfactant. The composite system can improve the oil displacement efficiency by 21.19%. The results of a parallel core displacement experiment with a 3.91 permeability ratio show that the oil displacement efficiency can be improved by 19.96%. The system has good performance in low-permeability oilfields and can effectively displace crude oil, which is of great significance for the displacement of low-permeability heterogeneous reservoirs. Full article

The accumulation of residual hydrolyzed polyacrylamide (HPAM) gel or molecular-based solutions in reservoirs after polymer flooding poses dual challenges: irreversible formation damage and long-term environmental risk issues. However, existing research mainly focuses on treating polymers in surface-produced water, neglecting both in situ decomposition of residual polymer gel or molecular-based solutions in reservoirs and the degradation of HPAM gels under high temperatures from in situ combustion (ISC). This work investigates the thermochemical behavior of HPAM gel during ISC and its dual-function role in enhanced oil recovery (EOR) and reservoir remediation. It was demonstrated that the residual gel and/or molecular-based solutions undergo efficient degradation, serving as an in situ fuel that significantly reduces the activation energy for crude oil oxidation by up to 58.4% in the low-temperature stage and 75.2% in the high-temperature stage. Factors influencing the gel’s degradation and the combustion process, including its molecular weight, ionic type, and crude oil viscosity, were systematically evaluated. Optimal conditions achieved over 90% gel degradation. Combustion tube experiments validated the dual benefits of this approach: an incremental oil recovery of 68.6% and an average HPAM gel removal efficiency of 64.8%. This work presents a novel strategy for utilizing retained gels in situ to simultaneously enhance oil recovery and mitigate gel-induced formation damage, offering significant insights for the management of mature gel-treated reservoirs. Full article

Heavy-oil reservoirs exhibit a high water–oil mobility ratio. During cyclic steam stimulation or water flooding in the later stages, severe fingering occurs, making it difficult to produce the remaining oil. Chemical flooding methods such as polymer flooding, surfactant–polymer flooding, weak gel flooding, and gel flooding have achieved significant enhanced oil recovery (EOR) effects in the development of high-water-cut oilfields in China. However, the reservoir applicability conditions for each chemical flooding method differ. How to quickly select the appropriate chemical flooding method based on reservoir conditions remains a challenge. This paper uses the basic parameters of a heavy-oil reservoir in Shengli Oilfield as a reference and establishes numerical simulation models for different chemical flooding methods. Then, using the permeability variation coefficient as an indicator to evaluate reservoir heterogeneity, the suitable permeability variation coefficient ranges for different chemical flooding methods are obtained and used as the first-level decision method. Subsequently, based on the differences in temperature and salt tolerance of each chemical flooding method, the applicable ranges for different chemical flooding methods are determined and used as the second-level decision method. Through this two-level decision-making process, the suitable chemical flooding development method for a target reservoir can be rapidly identified, providing support for the efficient development of heavy-oil reservoirs using chemical flooding. The findings are based on a typical heavy-oil reservoir model from Shengli Oilfield; the specific thresholds presented should be calibrated accordingly when applied to reservoirs with different characteristics. Full article

As an enhanced oil recovery (EOR) technique, alkali/surfactant/polymer (ASP) flooding effectively mitigates production decline in mature oilfields through chemical flooding mechanisms. The breakthrough of ASP chemical agents poses challenges to the green and efficient separation of oilfield produced water. In this paper, sedimentation separation of produced water was simulated using the Eulerian method and the RNG k–ε model. In addition, the filtration process was simulated using a discrete phase model (DPM) and a porous media model. The distribution characteristics of oil/suspended solids obtained through simulation, along with the water quality parameters at each treatment node, were systematically extracted, and the influence of operating conditions on treatment capacity was analyzed. Simulations reveal that elevated treatment loads and produced water polymer concentrations synergistically impair ASP flooding produced water treatment efficiency. Fluctuations of operating conditions generate oil/suspended solids content in output water ranges spanning 13–78 mg/L and 19–92 mg/L, respectively. The interpolation method is adopted to determine the critical water quality parameters of each treatment node, ensuring that the treated produced water meets the treatment standards. The operating limits of the ASP flooding produced water treatment process are established. Full article

In this paper, four kinds of flooding systems, high-molecular-weight polymer (HMP), low-molecular-weight polymer (LMP), hydrophobic association polymer (HAP), and LMP/petroleum sulfonate (PS), are preferred. By comparing the static performance, their good basic characteristics as an oil displacement system are clarified. The application concentration range of the polymer solution is optimized and designed in combination with core injectivity experiments and mobility control theory. The oil displacement system and its injection volume have been optimized via three parallel core flooding experiments. The results show that the increase of the polymer molecular weight and the association will enhance the viscosity-increasing performance, viscosity stability, viscoelasticity, and hydrodynamic characteristic size of the solution. According to whether the injection pressure curve reaches equilibrium and the time required for equilibrium, the matching relationship between the polymer and the reservoir can be divided into plugging, flow difficulty and flow smoothly. Based on the mobility control theory, the minimum mobility of the target core occurs when the water saturation is 30–40%. Therefore, the polymer formulation for the application of combined cores with viscosities of 50 mD, 210 mD, and 350 mD is set at 1500 mg/L for LMP and 800 mg/L for MAP. HAP has the best profile improvement effect, but its lowest EOR is 9.68%, which mainly acts on high-permeability layers; LMP can produce more remaining oil in middle-permeability layers, and its EOR can reach 12.01%; LMP/PS can give full play to the oil displacement performance of the polymer and the oil washing ability of the surfactant, and its highest EOR is 21.32%. Meanwhile, the emulsification effect also makes the profile improvement last longer. According to the EOR efficiency and final oil recovery, the optimal injection volume of LMP/PS can be designed to be 0.6–0.7 PV. Full article

The S oilfield has adopted polymer flooding technology, specifically using partially hydrolyzed polyacrylamide (HPAM), to enhance oil recovery. During the production process, the S oilfield has generated a substantial amount of stable polymer flooding-produced liquid, in which oil droplets are difficult to effectively coalesce, presenting significant challenges in demulsification. This article focuses on the produced fluids from S Oilfield as the research subject, developing a molecular dynamics model for the stability analysis of production liquid, including the molecular dynamics model of an oil–pure water system, an oil–mineralized water system and an oil–polymer–mineralized water system, using the principle of molecular dynamics and combining it with the basic molecular model for analyzing the stability of polymer flooding-production liquid. Through the molecular dynamics simulation of the stability analysis of the extracted liquid, the changing rules of the molecular diffusion coefficient, radial distribution function (RDF), interfacial interaction energy, and interfacial tension under the action of ions as well as polymers in water were investigated. The simulation results demonstrate that the presence of all three inorganic salt ions (Na⁺, Ca²⁺, and Mg²⁺) reduces the interfacial tension between oil and water and stabilizes the interface. Following the addition of polymer, the interfacial tension of the system decreases and the interfacial interaction energy increases significantly, indicating that the stability of the system is significantly enhanced by HPAM. Full article

Our target USH reservoir in the D oilfield is characterized by “inverse rhythm” deposition with the noticeable features of “high porosity and low permeability”. The reservoir has been developed with waterflooding using horizontal wells. Due to the strong heterogeneity of the reservoir, water channeling is severe, and the water cut has reached 79%. Considering the high temperature and high salinity reservoir conditions, polymer microspheres (PMs) were selected to realize conformance control. In this study, characterization of the polymer microsphere suspension was achieved via morphology, size distribution, and viscosity measurement. Furthermore, a multi-scale visualization study of the reservoir development process, including waterflooding, polymer microsphere flooding, and subsequent waterflooding, was conducted using macro-scale coreflooding and calcite-etched micromodels. It was revealed that the polymer microspheres could swell in the high salinity brine (170,000 ppm) by 2.7 times if aged for 7 days, accompanied by a viscosity increase. This feature is beneficial for the injection at the wellbore while swelled to work as a profile control agent in the deep formation. The macro-scale coreflood with a 30 cm × 30 cm × 4.5 cm layer model with 108 electrodes installed enabled the oil distribution visualization from different perpendicular cross sections. In this way, the in situ conformance control ability of the polymer microsphere was revealed both qualitatively and quantitatively. Furthermore, building on the calcite-etched visible micro-model, the pore-scale variation of the residual oil when subjected to waterflooding, polymer microsphere waterflooding, and subsequent waterflooding was collected, which revealed the oil displacement efficiency increase by polymer microspheres directly. The pilot test in the field also proves the feasibility of conformance control by the polymer microspheres, i.e., more than 40,000 bbls of oil increase was observed in the produces, accompanied by an obvious water reduction. Full article

High technical and financial risks are involved in exploring and exploiting new fields; hence, greater focus has placed on the development of environmentally friendly, cost-effective, and enhanced oil recovery (EOR) options for existing fields. For reservoirs producing high-density crudes and those with high interfacial tensions, water flooding is usually less effective due to density differences—hence the advent of polymer and surfactant flooding. For cost-effective and eco-friendly EOR solutions, a biopolymer and a surfactant synthesized from Jatropha seeds are used in this study to determine their effectiveness in increasing the oil recovery during core flooding analysis. The experiment involved an initial water flooding that served as the base cases of three weight percentages of polymers and polymeric surfactant solutions. The results for the polymer flooding of 1 wt%, 1.5 wt%, and 2 wt% showed an incremental oil recovery in comparison to water flooding of 16.8%, 17%, and 26%, while the polymeric surfactant mixtures of 5 wt% of surfactant and 1 wt%, 1.5 wt%, and 2 wt% of a polymer recorded 16.5%, 22.3%, and 28.8%, and 10 wt% of surfactant and 1 wt%, 1.5 wt%, and 2 wt% of a polymer recorded incremental oil recoveries of 20%, 32.9%, and 38.8%, respectively. Full article

The application of polymer flooding is currently under investigation to control water cut and recover residual oil from a giant sandstone reservoir in Kazakhstan, where the water cut in most producers exceeds 90%, leaving substantial untouched oil in the porous media. The primary objective of this research is to explore the feasibility of a novel approach that combines the mechanisms of mobility control by polymer injection and the thermal effects, such as oil viscosity reduction, by utilizing hot water to prepare the polymer solution. This innovative hybrid method’s impact on parameters like oil recovery, resistance factor, and mobility was measured and analyzed. The research involved an oil displacement study conducted by injecting a hot polymer at a temperature of 85 °C, which is higher than the reservoir temperature. Incremental recovery achieved through hot polymer injection was then compared to the recovery by conventional polymer flooding and the conventional surfactant–polymer-enhanced oil recovery techniques. The governing mechanisms behind recovery, including reductions in oil viscosity, alterations in polymer rheology, and effective mobility control, were systematically studied to comprehend the influence of this proposed approach on sweep efficiency. Given the substantial volume of residual oil within the studied reservoir, the primary objective is to improve the sweep efficiency as much as possible. Conventional polymer flooding demonstrated a moderate incremental oil recovery rate of approximately 48%. However, with the implementation of the new hybrid method, the recovery rate increased to more than 52%, reflecting a 4% improvement. Despite the polymer’s lower viscosity during hot polymer flooding, which was observed by the lower pressure drop in contrast to the conventional polymer flooding scenario, the recovery factor was higher. This discrepancy indicates that while polymer viscosity decreases, the activation of other oil displacement mechanisms contributes to higher oil production. Applying hybrid enhanced oil recovery mechanisms presents an opportunity to reduce project costs. For instance, achieving comparable results with lower chemical concentrations is of practical significance. The potential impact of this work on enhancing the profitability of chemically enhanced oil recovery within the sandstone reservoir under study is critical. Full article

The application results of profile control and water plugging technology are highly related to the gelation time and strength of phenolic resin hydrogel. In this work, a hydrogel solution was prepared by fully mixing the prepared polymer solution with a crosslinker. The static gelation process of PFR hydrogel in ampoule bottles and porous media was analyzed by changes in the viscosity and residual resistance coefficient. Then, the dynamic gelation of the PFR hydrogel in porous media was tested using a circulating flow device, and the changes in viscosity and injection pressure were analyzed during the dynamic gelation process. Finally, the effects of the polymer concentration and crosslinker concentration on dynamic gelation were analyzed. The initial gelation time and final gelation time in porous media were 1–1.5 times and 1.5–2 times those in ampoule bottles under static conditions, respectively. The initial dynamic gelation time in porous media was 2–2.5 times and 1.5–2 times the initial static gelation times in ampoule bottles and porous media, respectively. The final dynamic gelation time was four times and two times the initial static gelation times in ampoule bottles and porous media, respectively. The production after dynamic gelation in porous media comprised hydrogel aggregates and water fluid, leading to a high injection pressure and low viscosity of the produced liquid. As the concentration of polymer and crosslinker increased, the dynamic gelation time was shortened and the gel strength was increased. In the dynamic gelation process in porous media, the phenol resin hydrogel could migrate deeply, but it was limited by the concentrations of the polymer and crosslinker. The results of subsequent water flooding showed that the polymer hydrogel had a good plugging ability after dynamic gelation. The deep reservoir could only be blocked off in the subsequent water flooding process when the migration of hydrogel happened in the dynamic gelation process. Full article

In view of the high salinity characteristics of reinjection oilfield wastewater in the Gasi Block of Qinghai Oilfield, with the polymer produced by Shandong Baomo as the research target, we systematically investigated the variations in the impact of six ions, Na⁺, K⁺, Ca²⁺, Mg²⁺, Fe²⁺, and Fe³⁺, in the produced water from polymer flooding on the viscosity and stability of the polymer solution. Additionally, we provided the primary research methods for complexation in reinjected wastewater. Experimental results indicate that the main factors leading to a decrease in polymer viscosity are high-valence cations, with the descending order of their influence being Fe²⁺ > Fe³⁺ > Mg²⁺ > Ca²⁺ > Na⁺ > K⁺. High-valent cations also effect the viscosity stability of polymer solutions, and their order from greatest to least impact is: Fe²⁺ > Ca²⁺(Mg²⁺) > Fe³⁺ > Na⁺(K⁺). This article is focused on investigating the influencing factors and extent of the impact of oilfield wastewater on the viscosity of polymer solutions. It illustrates the response mechanism of cations to the viscosity of polymer solutions in reinjection wastewater polymerization. Through this research, the goal is to provide reference control indicators and limits for the water quality of injected polymers at oilfield sites. This ensures the stability and controllability of polymers in field applications and offers theoretical guidance for polymer flooding technology. Full article

Oil recoveries from medium and heavy oil reservoirs under natural recovery production are small because of the high viscosity of the oil. Normal water flooding procedures are usually ineffective, as the injected water bypasses much of the oil because of its high mobility. Thermal flooding processes are desirable but have many disadvantages from costs, effects on the environment, and loss of lighter hydrocarbons. Chemical flooding options, such as bio-polymer flooding options, are attractive, as they are environmentally friendly and relatively cheap to deploy and help to increase the viscosity of the injecting fluid, thereby reducing its mobility and increasing its oil recovery. The downside to polymer flooding includes reservoir temperature, salinity, molecular weight, and composition. Six weight percentages of two polymers (xanthan gum, XG, and gum arabic, GA) are dissolved in water, and their viscosity is measured in the laboratory. These viscosities are incorporated with correlations in the Eclipse software to create models with different polymer concentrations of (0.1% wt., 0.2% wt., 0.3% wt., 0.4% wt., 0.5% wt., and 1% wt.). A base case of natural recovery and water injection was simulated to produce an oil recovery of 5.9% and 30.8%, respectively, while at 0.1% wt. and 1% wt., respectively, oil recoveries of 38.8% and 45.7% (for GA) and 48.1% and 49.8% (for XG) are estimated. At 5% and 10% saline conditions, a drop in oil recovery of (4.6% and 5.3%) is estimated during GA flooding and (1.2% and 1.7%) for XG flooding at 1% wt., respectively. XG exhibits higher oil recoveries compared to GA at the same % wt., while oil recoveries during GA floodings are more negatively affected by higher saline concentrations. Full article

Chemical flooding, such as alkaline-surfactant (AS) or nanoparticles-surfactant (NS) flooding, is an enhanced oil recovery (EOR) technique that has been increasingly utilized to enhance the oil production rate and recovery factor while reducing chemical adsorption. The AS/NS flooding process involves the injection of a mixture of surfactant and alkali/nanoparticles solutions into an oil reservoir to reduce the interfacial tension between the oil and water phases by surfactant and lower surfactant adsorption by alkali or nanoparticles (NPs) to improve the residual oil recovery. In this study, the AS/NS flooding is evaluated for a Kazakhstani oilfield by systematically screening the chemical constituents involved. Field A in Kazakhstan, one of the oldest fields in the country, has been waterflooded for decades and has not produced even 50% of the original oil in place (OOIP). Currently, the water cut of the field is more than 90%, with a high residual oil saturation. Therefore, besides polymer flooding to control mobility, chemical EOR is proposed as a tertiary recovery method to mobilize residual oil. This study aimed to screen chemicals, including surfactant, alkali, and NPs, to design an effective AS/NS flooding program for the target field. The study focused on conducting laboratory experiments to identify the most effective surfactant and further optimize its performance by screening suitable alkaline and NPs based on their compatibility, stability, and adsorption behavior under reservoir conditions. The performance of the screened chemicals in the porous media was analyzed by a set of coreflood experiments. The findings of the study indicated that alkali agents, particularly sodium carbonate, positively affected surfactant performance by reducing its adsorption by 9–21%. The most effective surfactant combination was found, which gave Winsor type III microemulsion and the lowest interfacial tension (IFT) of 0.2 mN/m. The coreflood tests were conducted with the screened surfactant, alkali, and NPs. Both AS and NS tests demonstrated high residual oil recovery and microemulsion production. However, NS flooding performed better as the incremental oil recovery by NS flooding was 5% higher than standalone surfactant flooding and 9% higher than AS flooding. The results of this screening study helped in designing an efficient chemical formulation to improve the remaining oil recovery from Field A. The findings of this study can be used to design EOR projects for oil fields similar to Field A. Full article

The purpose of this study is to clarify the difference in oil production rules of conglomerate reservoirs with different pore structures during surfactant–polymer (SP) binary flooding and to ensure the efficient development of conglomerate reservoirs. In this paper, the full-diameter natural cores from the conglomerate reservoir of the Triassic Kexia Formation in the seventh middle block of the Karamay Oilfield (Xinjiang, China) are selected as the research objects. Two schemes of single constant viscosity (SCV) and echelon viscosity reducing (EVR) are designed to displace oil from three main oil-bearing lithologies, namely fine conglomerate, glutenite, and sandstone. Through comprehensive analysis of parameters, such as oil recovery rate, water content, and injection pressure difference, the influence of lithology on the enhanced oil recovery (EOR) of the EVR scheme is determined, which in turn reveals the differences in the step-wise oil production rules of the three lithologies. The experimental results show that for the three lithological reservoirs, the oil displacement effect of the EVR scheme is better than that of the SCV scheme, and the differences in recovery rates between the two schemes are 9.91% for the fine conglomerate, 6.77% for glutenite, and 6.69% for sandstone. By reducing the molecular weight and viscosity of the SP binary system, the SCV scheme achieves the reconstruction of the pressure field and the redistribution of seepage paths of chemical micelles with different sizes, thus, achieving the step-wise production of crude oil in different scale pore throats and enhancing the overall recovery of the reservoir. The sedimentary environment and diagenesis of the three types of lithologies differ greatly, resulting in diverse microscopic pore structures and differential seepage paths and displace rules of SP binary solutions, ultimately leading to large differences in the enhanced oil recoveries of different lithologies. The fine conglomerate reservoir has the strongest anisotropy, the worst pore throat connectivity, and the lowest water flooding recovery rate. Since the fine conglomerate reservoir has the strongest anisotropy, the worst pore throats connectivity, and the lowest water flooding recovery, the EVR scheme shows a good “water control and oil enhancement” development feature and the best step-wise oil production effect. The oil recovery rate of the two schemes for fine conglomerate shows a difference of 10.14%, followed by 6.36% for glutenite and 5.10% for sandstone. In addition, the EOR of fine conglomerate maintains a high upward trend throughout the chemical flooding, indicating that the swept volume of small pore throats gradually expands and the producing degree of the remaining oil in it gradually increases. Therefore, the fine conglomerate is the most suitable lithology for the SCV scheme among the three lithologies of the conglomerate reservoirs. Full article

High water cut of produced fluid is one of the most common problems in reservoir development. At present, injecting plugging agents and other profile control and water plugging technologies are the most widely used solutions. With the development of deep oil and gas resources, high-temperature and high-salinity (HTHS) reservoirs are becoming increasingly common. Conventional polymers are prone to hydrolysis and thermal degradation under HTHS conditions, making polymer flooding or polymer-based gels less effective. Phenol–aldehyde crosslinking agent gels can be applied to different reservoirs with a wide range of salinity, but there exist the disadvantage of high cost of gelants. The cost of water-soluble phenolic resin gels is low. Based on the research of former scientists, copolymers consisting of acrylamide (AM) and 2-Acrylamido-2-Methylpropanesulfonic acid (AMPS) and modified water-soluble phenolic resin were used to prepare gels in the paper. The experimental results show that the gelant with 1.0 wt% AM-AMPS copolymer (AMPS content is 47%), 1.0 wt% modified water-soluble phenolic resin and 0.4 wt% thiourea has gelation time of 7.5 h, storage modulus of 18 Pa and no syneresis after aging for 90 days at 105 °C in simulated Tahe water of 22 × 10⁴ mg/L salinity. By comprehensively comparing the effectiveness of the gels prepared by a kind of phenolic aldehyde composite crosslinking agent and modified water-soluble phenolic resin, it is found that the gel constructed by the modified water-soluble phenolic resin not only reduces costs, but also has shorter gelation time and higher gel strength. The oil displacement experiment with a visual glass plate model proves that the forming gel has good plugging ability and thus improves the sweep efficiency. The research expands the application range of water-soluble phenolic resin gels, which has an important implication for profile control and water plugging in the HTHS reservoirs. Full article