Residual Resistance Factor Research Articles

Enhancing geothermal efficiency: Experimental evaluation of a high-temperature preformed particle gel for controlling preferential fluid flow

Enhanced Geothermal System (EGS) reservoirs represent a vital frontier in clean energy production. However, short-circulation flow within these reservoirs can significantly affect their immediate efficiency and long-term viability. Injected cold fluids moving through wide fractures or direct channels between injection and production wells reduce thermal production temperatures, disrupting energy output. Preformed Particle Gels (PPGs) have proven effective in controlling preferential fluid flow in oil and gas reservoirs, effectively regulating fluid movement. This work explores the potential of a novel High-Temperature Preformed Particle Gel (HT-PPG), designed for geothermal applications, to plug fractures in a simulated geothermal reservoir. Core flooding experiments in coated and uncoated sandstone models were conducted under varying HT-PPG sizes, swelling ratios, and fracture widths to determine gel plugging efficiency. Variations in the HT-PPG injection pressure, breakthrough pressure, and residual resistance factor (Frr) were evaluated. Water breakthrough pressures can reach 464.10 psi/ft. While the stable injection pressure of HT-PPG decreased with increasing swelling ratio and fracture width, it was higher in uncoated cores. The HT-PPG significantly sealed the fractures, drastically reducing conductivities to millidarcy levels. This work validates HT-PPG a robust solution to mitigate fluid diversion challenges in sandstone EGS reservoirs, enhancing performance and advancing sustainable geothermal energy production.

Preparation of sodium alginate grafted polyelectrolyte by adiabatic polymerization and study on its solution properties

In order to improve the salt resistance and shear resistance of partially hydrolyzed polyacrylamide-based oil displacement agents (they are all anionic polyelectrolytes), this paper proposes the preparation of branched low hydrophobic monomer content sodium alginate grafted hydrophobically modified partially hydrolyzed polyacrylamide P(AM-SA-MO8) using acrylamide (AM), sodium alginate (SA), and non-ionic hydrophobic monomer (MO8) as main raw materials through the method of adiabatic polymerization followed by hydrolysis. The polymerization conditions of P(AM-SA-MO8) were optimized, and the solution properties and oil displacement performance of P(AM-SA-MO8) and P(AM-MO8) (copolymer of AM and MO8) were compared. It was found that the viscosity, resistance to Ca2+/Mg2+, shear resistance, resistance factor (RF), residual resistance factor (RRF), and enhanced oil recovery performance of P(AM-SA-MO8) solution were better than those of P(AM-MO8). Especially in seawater, at 75 ℃, the viscosity of 1500 mg/L P(AM-SA-MO8) solution was 6.5 mpa.s, RF was 6.08, RRF was 2.28, and the enhanced oil recovery was 26.28 % with a injection rate of 4.9 ft/day.

Effect of a SILICA/HPAM Nanohybrid on Heavy Oil Recovery and Treatment: Experimental and Simulation Study.

The addition of nanoparticles has been presented as an alternative approach to counteract the degradation of polymeric solutions for enhanced oil recovery. In this context, a nanohybrid (NH34) of partially hydrolyzed polyacrylamide (MW ∼12 MDa) and nanosilica modified with 2% 3-aminopropyltriethoxysilane (nSiO2-APTES) was synthesized and evaluated. NH34 was characterized by using dynamic light scattering, Fourier-transform infrared spectroscopy, and thermogravimetric analysis. Fluid-fluid tests assessed its viscosifying power, mechanical stability, filterability, and emulsion behavior. Rock-fluid tests were carried out to determine the nanohybrid's adsorption in porous media, the inaccessible pore volume (IPV), and the resistance (RF) and residual resistance factors (RRF). These tests were conducted under the conditions of a Colombian field. NH34 results were compared with four (4) commercial polymers (P34, P88, P51, and PA2). The viscosifying power of NH34 was observed to be similar to that of the four commercial polymers at a lower concentration, but it exhibits more resistance to mechanical and chemical degradation. The evaluation of the emulsion behavior showed that the nanohybrid neither changed the dehydration process nor altered the crude oil viscosity, favoring its extraction at the wellhead. However, the water clarification treatment must be adjusted because the oil and grease contents and turbidity increase with the residual concentration of NH34. Incremental oil recovery factors obtained by numerical simulation (compared to waterflooding) were P51 (5.5%) > P34 (4.9%) > P88 (4.8%) > NH34 (2.6%) > PA2 (0.9%). The polymers P51, P34, and P88 had a better recovery factor than NH34 and PA2 due to their lower values of residual adsorption and IPV. Few studies have been reported on polymer nanohybrids' emulsion and flow behavior. Therefore, further research is needed to enhance our understanding of the fundamental enhanced oil recovery mechanisms associated with polymer nanohybrids.

Insights into the Injectivity and Propagation Behavior of Preformed Particle Gel (PPG) in a Low-Medium-Permeability Reservoir.

Heterogeneous phase combined flooding (HPCF) has been a promising technology used for enhancing oil recovery in heterogeneous mature reservoirs. However, the injectivity and propagation behavior of preformed particle gel (PPG) in low-medium-permeability reservoir porous media is crucial for HPCF treatment in a low-medium-permeability reservoir. Thus, the injectivity and propagation behavior of preformed particle gel in a low-medium-permeability reservoir were systematically studied by conducting a series of sand pack flooding experiments. The matching factor (δ) was defined as the ratio of the average size of PPG particles to the mean size of pore throats and the pressure difference ratio (β) was proposed to characterize the injectivity and propagation ability of PPG. The results show that with the increase in particle size and the decrease in permeability, the resistance factor and residual resistance factor increase. With the increase in the matching factor, the resistance factor and residual resistance factor increase. The higher the resistance factor and residual resistance factor are, the worse the injectivity of particles is. By fitting the relationship curve, PPG injection and propagation standards were established: when the matching coefficient is less than 55 and β is less than 3.4, PPG can be injected; when the matching coefficient is 55-72 and β is 3.4-6.5, PPG injection is difficult; when the matching coefficient is greater than 72 and β is greater than 6.5, PPG cannot be injected Thus, the matching relationship between PPG particle size and reservoir permeability was obtained. This research will provide theoretical support for further EOR research and field application of heterogeneous phase combined flooding.

SUBSTANTIATION OF METHOD FOR LEVELING INJECTIVITY PROFILE UNDER CONDITIONS OF CARBONATE RESERVOIRS OF FIELD NAMED AFTER R. TREBSA

At the moment, the issue of reducing water cut during the development of carbonate fractured reservoirs is relevant. In the work, the object of the study is the carbonate deep reservoirs of the R. Trebs field. According to the field development analysis, there are production wells with sharp unpredictable breakthrough of injected water.In order to increase the coverage of pay zones by waterflooding, it is necessary to use methods aimed at limiting the filtration of injected water into water-flooded intervals.High formation temperature and mineralization of formation water are complicating factors in the selection of the injection profile alignment (runway) technology.Taking into account the criteria specified in the work, potential candidates for testing the technology were selected for the runway.The article analyzed the advantages and disadvantages of the existing runway methods used when exposed to injection wells. The criteria for the applicability of various technologies based on the use of: polymer/gel compositions, emulsion compositions, including reverse emulsions, injection of aqueous salt solutions, silicate, thermotropic and complex reagents are highlighted. Technologies and compositions based on water-soluble polymers that form viscoelastic compositions when crosslinkers of various nature are added are recognized as the most promising for the conditions of the fractured reservoir of the Trebs field.Particular attention is paid to laboratory experiments aimed at studying the physical and chemical properties of crosslinked polymer systems, conducting filtration experiments, determining the applicability of the technology for the geological and physical conditions of the study object.According to the results of physicochemical experiments, such parameters as the time of dissolution of reagents, compatibility with formation water, time and temperature of gelling were determined. Based on the shear test, rheological parameters of the investigated polymer systems are determined. Testing was carried out to determine the conditions under which the crosslinked polymer composition breaks down.Filtration experiments were carried out on linear and volumetric models of the formation using core material from the Trebs field to determine the reagent with the highest colmating abilities calculated from the residual resistance factor.

Study on the mobility control ability of a quaternary ammonium salt active polymer for oil flooding

Mobility control ability is an important property of polymer used in oil displacement. This work initially investigates the temperature and salt resistance, steady-state rheology, dynamic viscoelasticity, and long-term stability of a quaternary ammonium salt active polymer (AM/AMPS/DMCA). Subsequently, an examination was conducted to evaluate the static adsorption ability of AM/AMPS/DMCA on the surface of quartz sand, as well as the dynamic retention property within cores. Finally, the mobility control ability and oil displacement capacity of AM/AMPS/DMCA under various injection conditions was investigated in this study. The findings illuminate the superior attributes of AM/AMPS/DMCA, including its remarkable temperature and salt endurance, alongside its long-term stability, presenting a significant advancement over traditional binary polymers like AM/AMPS. Notably, AM/AMPS/DMCA exhibits a predominantly elastic modulus, which enhances its movement and deformation inside porous media. Furthermore, it has been shown that the resistance factor and residual resistance factor achieved by the 2000 mg/L AM/AMPS/DMCA solution in the core of 96.6 mD were 184.50 and 46.95, respectively. The enhanced oil recovery (EOR) value of 0.6 PV of AM/AMPS/DMCA achieved 30.48% in the core of 588.8 mD. This study not only demonstrates the capability of AM/AMPS/DMCA in EOR but also facilitates the understanding of the mobility control mechanism of polymers in porous media, offering valuable empirical guidance for the field application of polymers.

Surfactant-Polymer Composition for Selective Water Shut-Off in Production Wells.

Today, a significant part of production wells' stock has a high water cut percentage of 90% and above. Obviously, for this reason, the need to develop new and improved existing technologies for water shut-off in wells increases every year. Physico-chemical methods of water shut-off are based on the application of special reagents and compositions that plug the pathways of water inflow to the well. Depending on the mechanism and specific features of water barrier formation, isolation methods are divided into selective and non-selective. This article investigates the possibility of using hydrolyzed polyacrylonitrile as a gel-forming and precipitation-forming reagent for water shut-off technologies in production wells. A surfactant-polymer composition for the isolation of water inflow in production wells in objects with high salinity in formation water, possessing physical and chemical selectivity and providing permeability reduction only in water-saturated intervals, is proposed. The developed composition is the invert emulsion, which makes it possible to carry out treatment at a distance from the well and solve the problem of possible premature gel formation directly in the wellbore. The lowest effective concentration of HPAN in an aqueous solution for use as a gel-forming and sedimentation reagent was determined experimentally (5.0 wt% and more). The interaction of the polymer solution with a chromium crosslinker allows obtaining structured gels in the whole volume of the system. The structure of the gels was evaluated using the Sydansk classifier with the assignment of a letter code from A to J. It was experimentally proved that the structure of the obtained gels depends on the temperature and content of the crosslinking agent in the system; the more crosslinking agent in the composition of the system, the stronger the structure of the resulting gel. The optimal ratio of polymer and crosslinking agent to obtain a strong gel was obtained, which amounted to 5:1 by weight of dry polymer powder. For the HPAN concentration of 5 wt% according to the Sydansk classifier, the gel structure had the code "H"-slightly deformable non-flowing gel. The dependence of the volume of gel sediment obtained because of the interaction with mineralized water on the polymer concentration was studied. It was proved that an increase in the concentration of hydrolyzed polyacrylonitrile in the solution, as well as an increase in the concentration of calcium ions in mineralized water, leads to a larger volume of the resulting gel or precipitate and to the strengthening of the gel structure. The results of rheological studies of the developed composition, as well as experiments on thermal stability, are presented. The results of filtration tests on bulk reservoir models demonstrated the selectivity of the developed composition. The obtained value of the residual resistance factor for the oil-saturated low-permeability model was 1.49 units; the value of the residual resistance factor for the water-saturated high-permeability model was 18.04 units. The ratio of the obtained values of the residual resistance factor, equal to 0.08 (much less than 1), can characterize the developed composition as a selective material for water shut-off in producing wells. Existing technologies for water shut-off based on HPAN do not allow for making a treatment at a distance from the well and require the use of technological solutions to prevent premature gel sedimentation in the well. The developed composition makes it possible to solve the problem of premature gelation. In addition, the composition can form a blocking screen in highly permeable water-saturated zones. The development can be useful for deposits with difficult conditions (high mineralization in reservoir waters, boreholes with a horizontal end, elevated temperatures up to 80 °C).

Dynamic covalent hydrogel fabricated in porous media through dynamic acylhydrazone bond from reactive precursors for deep profile control

In this work, we proposed a novel hydrogel system for in-depth conformance control through the dynamic covalent bond. Diffluent ketone-bearing and acyl hydrazide-bearing reactive precursors with low molecular weight are injected into the formation simultaneously, then gels in situ through dynamic hydrazone bonds to divert the post-injected fluid to un-swept oil zones. Ketone-bearing and acyl hydrazide-bearing reactive precursors with different reactive group ratios were synthesized by simple radical polymerization and hydrazinolysis. Rheological measurement results proved the two reactive precursors formed dynamic covalent hydrogel (DCG) through dynamic hydrazone bonds in deionized water and mineralized water. The viscoelasticity, flow behavior, and profile control behavior in the porous media of the DCG were evaluated. When the flow behavior and profile control experiments were conducted with a 9 m core, the injection pressure of DCG-20 % of which the molar ratio of the reactive group was 20 % was low (0–0.22 MPa) throughout the injection process, and the resistance factor was 4.40. After fully gelation, the post-water injection pressure significantly increased (0.22–7.54 MPa). The residual resistance factor was 150.80, and the plugging efficiency was 99.34 %. This work proved that the DCG consisting of ketone-bearing and acyl hydrazide-bearing reactive precursors not only had a strong injection capacity but also had a good profile control effect in porous media which meant the DCG fully met the need for deep profile control.

A WATER SHUTOFF OPERATION EFFICIENCY PREDICTION IN VIEW STRENGTH OF THE SEALING COMPOSITION

The increase in the volume of produced water is one of the most important problems of modern oil production. Improvement of well stimulation technologies and methods leads to the more intensive development of a reservoir and an increase in the probability of wells premature flooding, which leads to the necessity of water shutoff operations. One of the ways to increase the water shutoff efficiency is to improve methods for predicting the technological effect and optimizing the operation parameters. In this paper, the author considered
 the theoretical aspects of the most important issues of water shutoff design – justification of the required volume of the sealing agent and forecasting the technological effectiveness of the operation (starting well operation indicators after operation).
 A numerical model is proposed and an analytical solution to the problem of predicting the effectiveness of water shutoff operation is obtained, taking into account the dependence of the residual resistance factor on the pressure gradient.

Evaluation of the Performances of Foam System as an Agent of Enhancing Oil Recovery

Foam has been used in petroleum engineering to enhance oil recovery for many years. It is a very complicated dispersion system, and the performances are affected by many factors. In order to understand the influence rules and mechanisms of such factors, the performances and mechanisms of foam systems are investigated by static and core flooding experiments with Sodium Dodecyl Sulfate. It is found that a polymer may reduce the foaming ability, but significantly enhance the foam stability in both oil-free and oil-bearing environments, while the optimal concentration is around 1500 mg/L in this case. NaCl may reduce the stability, but the capability of enhancing the foaming ability and oil tolerance gradually increases and stabilizes when the concentration reaches to 7000 mg/L. Oil can reduce the foam stability, and the stability decreases as the oil saturation increases to 0.15. Moreover, the foam stability is worse in light oil conditions than in heavy oil conditions. In the sand-pack tests, the resistance factors of foam are much higher than that of a polymer solution. The maximum resistance factor of the foam tested reaches about 230. The residual resistance factor of polymer-enhanced foam (PEF) is generally larger than that of pure foam and salt enhanced foam (SEF) in an oil-free environment. The maximum value of resistance factor of PEF and SEF is only about 60, and that of pure foam is less than 40 in an oil-bearing environment. In the parallel sand-pack tests, both ultimate oil recovery and incremental oil recovery are the best when using PEF, with SEF the second, and pure foam the worst.

Modyfikacja właściwości filtracyjnych ośrodków porowatych z wykorzystaniem micelarnej cieczy zabiegowej Multizol

The need for the modification of filtration properties of rock media (most frequently porous rocks) appears frequently, e.g., in hydrocarbon exploitation. Exploitation of crude oil and natural gas is frequently accompanied by an excessive and uncontrolled inflow of reservoir water to the production well, which often results in a significant reduction of hydrocarbon production in the late period of reservoir exploitation. The control of water inflow, through modification treatments of rock filtration properties of the near wellbore zone, is the solution to this problem. The use of dedicated treatment fluids is the basis of such success, which, after the injection and change of original physicochemical properties, create local insulation barriers, enabling the control of the flow of fluids in the geological formation. This paper presents the results of the laboratory assessment of the technological effectiveness of Multizol micellar treatment fluid, which is used for selective blocking of the reservoir water inflow to gas wells. Tests performed, at a preliminary stage, comprised the development of a procedure, the obtaining of samples of the treatment fluid, and the performance of flow tests in test glass tubes, which allow for a swift determination of the technological range of the fluid's capability to form gel and emulsion. Flood tests were the main element of testing, related to the measurement of pressure drops of fluids flowing through the sample under the simulated reservoir conditions. The tests were carried out using two types of media, porous rocks (Szydłowiec sandstone) and sand packs. The determination of the modification degree of filtration properties, both in individual zones and in the entire sample/model, was based on the value of the FRR (Residual Resistance Factor) coefficient, being the measure of their permeability reduction. Two types of tests were performed to assess the effect of Multizol treatment fluid on the initial filtration properties of gas and water-bearing zones.

Amphoteric nano‐ and microgels with acrylamide backbone for potential application in oil recovery

AbstractAmphoteric nano‐ and microgels based on acrylamide (AAm), 3‐acrylamidopropyltrimethylammonium chloride (APTAC) and 2‐acrylamido‐2‐propanesulfonate sodium salt (AMPS) were prepared via inverse emulsion polymerization in the presence of crosslinking agent—N,N′‐methylenebisacrylamide (MBAA). Several polyampholyte nano‐ and microgel samples AAm‐APTAC‐AMPS with compositions (70:15:15, 80:10:10, and 90:5:5 mol%) were obtained and they were abbreviated as AAm70‐APTAC15‐AMPS15, AAm80‐APTAC10‐AMPS10 AAm90‐APTAC5‐AMPS5 (where the lower indexes indicate the molar concentration of monomers). The nano‐ and microgels were characterized by Fourier‐transform infrared spectroscopy, dynamic light scattering (DLS), transmission electron microscope (TEM), thermogravimetric analysis and interfacial tension measurements. The most attention was paid to the AAm80‐APTAC10‐AMPS10 microgel because its linear analog showed the best swelling capacity and the viscosifying effect for potential application in oil recovery. The influence of monomer concentration, surfactants, volume ratio of the water/organic phases, and the hydrophilic–lyophilic balance (HLB) on the average hydrodynamic size of the AAm80‐APTAC10‐AMPS10 nano‐ and microgels was studied. The size distribution of nano‐ and microgels derived from DLS data and TEM images was compared as a function of monomer concentration at constant surfactant concentration (6 wt%), HLB = 5.5 and mixture of water:oil = 60:40 vol%. Swelling of microgel particles in saline water due to the antipolyelectrolyte effect was observed. The applicability of amphoteric microgels AAm80‐APTAC10‐AMPS10 for oil recovery was tested on cores simulating the conditions of a model oil reservoir. The obtained results indicated that after the injection of around three pore volumes of the 2500 ppm microgel suspension into the sandstone core the permeability to brine decreased from 1.5 to 0.78 mD. For the first half of core sample the residual resistance factor was higher than the resistance factor, whereas for the second part of core sample these parameters were almost equal. Additional experiments with longer cores are needed to evaluate in‐depth propagation of microgels and permeability reduction in porous media.

Profile control and plugging ability of extracellular polymeric substances (EPS) produced by E. cloacae strain ZL-02 under Ba2+ in reservoir

Microbial Enhanced Oil Recovery (MEOR) is a pivotal technology for enhancing tertiary oil recovery. The production of partly extracellular polymeric substances (EPS) by Enterobacter cloacae exhibits excellent control over mobility and holds promise for applications in heterogeneous reservoir exploration. To investigate the impact of Ba2+ on microbial EPS production, a series of tests were conducted, including EPS production tests, polysaccharide and protein content analyses, Inductively Coupled Plasma Optical Emission Spectrometer (ICP-OES) measurements, X-ray diffraction (XRD), laser particle size measurements, and transcriptome analysis.The results demonstrated the stimulating effect of Ba2+ on EPS membrane production. Ba2+ stimulation led to increased secretion of proteins (5.82 g/L) and polysaccharides (9.0 g/L). Moreover, the binding of proteins with Ba2+ resulted in an enlargement of the particle size of the EPS membrane and an increase in grain size, reaching a maximum crystallinity of 77.77 %. Transcriptome analysis revealed the up-regulation of 790 genes and down-regulation of 728 genes in response to Ba2+ addition. Enrichment analysis of the up-regulated genes highlighted the significant enrichment of gene ontology number GO: 00160120, which directly influenced microbial EPS membrane production. Furthermore, microscopic displacement and core flooding experiments were conducted to evaluate the plugging ability of microbial-produced EPS membranes. Remarkably, under the influence of Ba2+, microorganisms exhibited significantly enhanced sealing capacity on glass slides etched with rock cores. The results from simulated flow experiments demonstrated a maximum sealing rate of 81.5 % on rock cores, with an RF (Resistance Factor) value of 2.5 and an RRF (Residual Resistance Factor) value of 5.45.This study innovatively explores oil-producing microbial genes, combining simulation experiments and rock core slicing to reveal the microscale mechanism of Ba2+ stimulating microbial EPS secretion for reservoir plugging. It provides theoretical support for the application of MEOR technology in improving oil recovery rates.

Influence of polymer solution concentration and media permeability on the residual resistance factor

Purpose. Determination of the required concentration of polymer solution, providing the maximum well insulation effect, depending on the filtration characteristics of the medium. Methodology. The research was conducted by experimental method using the methodology of planning the experiment. The theory of rational planning was used by varying two variables on five levels. Media permeability and polymer solution concentration were used as variables. Methods of mathematical statistics were used in processing the results. Findings. Experimental studies made it possible to build a model expressing the dependence of the residual resistance factor on the permeability of the medium and the concentration of the polymer solution. By further statistical processing the connection between permeability and necessary concentration of polymer solution was obtained. Originality. The experimental studies have substantiated the possibility of evaluating the influence of medium permeability and concentration of polymer solution on the residual resistance factor and determined its dependence on the concentration of polymer solution and medium permeability. The main point of polymer solutions application is justification and choice of the reagent concentration. The concentration should be selected in such a way that it provides the maximum value of the residual resistance factor and the viscosity of the solution necessary to level out permeability heterogeneity of the environment to some extent. To achieve this, a relationship has been obtained that allows determining the concentration of the polymer solution at a given permeability of the environment that provides the maximum residual resistance factor. Practical value. The conducted experimental studies allow developing the ideas about the regularities of water manifestations. The results of the research allow selecting purposefully both the formulations of composite systems and the technology of their application to improve the efficiency of oil production and to limit water inflows in specific geological and physical conditions.

Investigation of the plugging capacity and enhanced oil recovery of flexible particle three-phase foam

In the later stage of water flooding in reservoirs, the oil production decreases. The stability of three-phase foam system is strong, enhancing oil displacement effects of ultrahigh water cut reservoirs. In this paper, the flow state of the foam system was studied by using a microscopic visualization model. Second, sandpack flooding experiments were performed to analyze the optimal plugging conditions of three-phase foam through resistance factors. Finally, single and parallel sandpack flooding experiments were carried out to analyze plugging effect and production conditions under different injection systems and permeability ratios. The research shows that three-phase foam is more stable and capable of plugging. The stable residual resistance factor after injection of the three-phase foam system is 172.75. When the foam and particles are injected simultaneously, the gas–liquid ratio is 1:1, the formation permeability is 5526.5 mD, and the plugging effect of three-phase foam is the best. The oil recovery increases by 24.9% after the injection of three-phase foam system. The three-phase foam system combines Jamin effect of foam and dynamic plugging characteristics of flexible particles. The highest oil recovery factor of 80.87% is achieved at a permeability ratio of 9.99. Three-phase foam flooding has broad application prospects.

Sensitivity Study of The Effect Polymer Flooding Parameters to Improve Oil Recovery Using X-Gradient Boosting Algorithm

Implementation of waterflooding sometimes cannot increase oil recovery effectively and requires additional methods to increase oil recovery. Polymer flooding is a common chemical EOR method that has been implemented in the last few decades and provides good effectiveness in increasing oil recovery and can reduce the amount of injection fluid injected into the reservoir. Seeing the success of polymer flooding in increasing oil recovery, it is necessary to know the parameters that influence the success of polymer flooding so that it can be evaluated and taken into consideration in creating a new scheme to increase oil recovery with polymer flooding. The parameters tested in this study include Injection Rate, Injection Time, Injection Pressure, Adsorption, Inaccessible Pore Volume, Residual Resistance Factor. This research uses the X-Gardient Boosting Algorithm to look at the most influential parameters in polymer flooding. The parameters that most influence the performance of polymer flooding on the value of oil recovery with the importance level of each parameter in this study are injection time of 0.452632, injection rate of 0.430075, injection pressure of 0.064662, Adsorption of 0.025564, RRF of 0.021053, IPV of 0.006014 and produce accurate predictive modeling using x-gradient boosting where with 3 variations of the comparison ratio of training and testing data obtained at a ratio of 0.7 : 0.3 obtained an R2 train of 0.9886 and an R2 test of 0.9645, a ratio of 0.8 : 0.2 obtained an R2 train of 0.9891 and an R2 test of 0.9579, and a ratio of 0.9: 0.1 obtained R2 train of 0.9890 and R2 test of 0.9660.

Optimization of Polymer Flooding Using Genetic Algorithm

One of the methods to achieve optimal conditions in increasing oil recovery through injecting polymers is by optimizing the parameters that influence the success of injecting polymers to provide information and be considered when determining new schemes for implementation in the future. Optimization to obtain the optimum value of the recovery factor and the best value of the parameters PV, injection rate, injection time, injection pressure, adsorption, residual resistance factor (RRF), and inaccessible pore volume (IPV) using a genetic algorithm with three training ratios and testing 70: 30, 80: 20 and 90: 10 using 1000 datasets. The best value obtained for each parameter is at a ratio of 90: 10, which is the best model with the lowest reference error value with RSME of 0.241104 and MAPE value of 19.1964 classified as good prediction with the value of each adsorption parameter 0.1737 (g/l), injection rate 703 (bpd), injection pressure 1816, IPV 0.2524, RRF 4.8319 and finally the optimum value for recovery factor is 53.9557.

Optimization of Gel Flooding during the High Water Cut Stage in a Conglomerate Reservoir of the Xinjiang A Oilfield.

Influenced by water injection, a dominant flow channel is easily formed in the high water cut stage of a conglomerate reservoir, resulting in the inefficient or ineffective circulation of the injected water. With gel flooding as one of the effective development methods to solve the above problems, its parameter optimization determines its final development effect, which still faces great challenges. A new optimization method for gel flooding is proposed in this paper. Firstly, the gel flooding parameters were obtained through physical experiments; then, an experimental model of gel flooding was established according to the target reservoir, and parameter sensitivity analysis was carried out. Next, a history matching of the gel flooding experiment was carried out. Finally, history matching of the target reservoir was also carried out, and a gel flooding scheme was designed and optimized to determine the best parameters. The experimental results showed that the gelation time was 4 h and the gel viscosity was 6332 mPa·s; the breakthrough pressure, resistance factor (RF), and residual resistance factor (RRF) all decreased with the increase in permeability. The gel had a good profile control ability and improved oil recovery by 16.40%. The numerical simulation results illustrated that the porosity of the high permeability layer (HPL) had the greatest impact on the cumulative oil production (COP) of the HPL, and the maximum polymer adsorption value of the HPL had the largest influence on the COP of the low permeability layer (LPL) and the water cut of both layers. Benefiting from parameter sensitivity analysis, history matching of the gel flooding experiment and a conglomerate reservoir in the Xinjiang A Oilfield with less time consumed and good quality was obtained. The optimization results of gel flooding during the high water cut stage in a conglomerate reservoir of the Xinjiang A Oilfield were as follows: the gel injection volume, injection rate, and polymer concentration were 2000 m3, 50 m3/d, and 2500 mg/L, respectively. It was predicted that the water cut would decrease by 6.90% and the oil recovery would increase by 2.44% in two years. This paper not only provides a more scientific and efficient optimization method for gel flooding in conglomerate reservoirs but also has important significance for improving the oil recovery of conglomerate reservoirs.

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.

The evaluation of dodecyl hydroxy sulfobetaine as a high-temperature and high-salinity resistant foaming agent in sandstone reservoirs

For the high temperature (130 °C), high pressure (30 MPa), and high salinity (2.5 × 105 mg/L) of formation water conditions in the target block of the Tarim Basin Oilfield in northwest China, dodecyl hydroxy sulfobetaine surfactant was evaluated for its foaming performance, thermal stability, adsorption performance. The evaluation results showed that the surfactant exhibited good foaming ability and thermal stability than the general carboxy betaine under the above harsh conditions. The static adsorption of the surfactant on the surface of quartz sand particles was less than 1 mg/g with a concentration of less than 0.4%, which met the requirement for foaming agent adsorption. Moreover, the results of core displacement experiments indicated that, when simultaneously injecting 0.4% foaming agent and gas at a volume ratio of 3:7 into the cores of 38 mD, 161.4 mD, and 478.7 mD, foam with low mobility of less than 2 mD/cP could be generated; in the 57.3 mD Berea core, the resistance factor of foam generated by 8 cycles of injecting gas-liquid alternately with gas-liquid volume ratio ranging from 0.2:0.1 to 0.4:0.1 was nearly 20, and the residual resistance factor was greater than 5 after 5 PV of continuous gas injection. The results of the study can guide the selection of foaming agents for gas mobility control in high-temperature and high-salinity sandstone reservoirs.