Hydrolyzed Polyacrylamide Solutions Research Articles

Rheological and structural properties of nanofluids based on hydrolyzed polyacrylamide and aminated carbon nanotubes for enhanced oil recovery

Polymer flooding, a prominent enhanced oil recovery (EOR) technique, involves injecting polymers such as partially hydrolyzed polyacrylamide (HPAM) to increase water viscosity for more effective oil displacement. Overall, HPAM exhibits good shear stability, thermal tolerance, and cost-effectiveness; however, it has limitations such as temperature constraints and salinity susceptibility. Integrating nanomaterials into HPAM-based EOR is a promising and innovative strategy, with aminated carbon nanotubes standing out as a strong candidate due to their remarkable tensile strength, excellent thermal conductivity, exceptional chemical and physical stability, and good dispersibility and versatility. This study employed ethylenediamine-functionalized oxidized multiwalled carbon nanotubes (MWCNTO-EDA) as an additive in HPAM solutions for EOR applications. Extensive analyses, including FTIR, Raman, TGA, zeta potential, elemental analysis, and cryo-TEM, confirmed the chemical composition and morphology of HPAM and the nanomaterials. Cryo-TEM images under various ionic conditions revealed that the presence of salts caused polymer chain contraction into spherical structures, explaining the reduced viscosity in high-salinity nanofluids. Rheological tests at 70 °C demonstrated that MWCNTO-EDA significantly increased the nanofluid viscosity over reference HPAM fluids. Notably, nanofluids containing 0.5 % MWCNTO-EDA exhibited an average 55 % viscosity increase at an ionic strength of 0.6, which is vital for applications in EOR where heightened viscosity is crucial. Aging tests, performed over 180 days at 70 °C, displayed substantial viscosity improvements in nanofluids containing 1.0 % MWCNTO-EDA, achieving up to a 150 % increase over reference samples. MWCNTO-EDA emerges as a valuable additive for creating innovative nanofluids, addressing critical limitations and preserving HPAM conformation, making it suitable for EOR in challenging environmental conditions.

Syntheses and properties of associative acrylamide copolymers containing short hydrophobic chains used in a friction reducer for slick-water fracturing

Two allyldimethylalkyl quaternary ammonium salt (AQAS) monomers, N,N-dimethylallylphenylpropylammonium bromide (AQAS1) and N,N-dimethylallylnonylammonium bromide (AQAS2), were synthesized and used to prepare modified polyacrylamide materials. Two new drag reducers were synthesized from acrylamide (AM), sodium acrylate (NaAA) and a cationic modified monomer (AQAS1 or AQAS2) via aqueous solution polymerization, and the copolymers were named P(AM/NaAA/AQAS1) and P(AM/NaAA/AQAS2), respectively. The structures of the drag reduction agents were confirmed by IR and 1H NMR spectroscopies. The molecular weight (Mw) of P(AM/NaAA/AQAS1) was 1.79 × 106 g/mol. When the copolymer concentration was 1000 mg/L and the flow rate was 45 L/min, in fresh water the highest drag reduction rate was 75.8%, in 10,000 mg/L NaCl solution the drag reduction rate decreased to 72.9%. The molecular weight of P(AM/NaAA/AQAS2) was 3.17 × 106 g/mol. When the copolymer concentration was 500 mg/L and the flow rate was 45 L/min, the drag reduction rate reached 75.2%, and in 10,000 mg/L NaCl solution the drag reduction rate was 73.3%, decreased by approximately 1.9%. The drag reduction rate for partially hydrolyzed polyacrylamide (HPAM) was also investigated, and the results showed that the drag reduction rates for 500 and 1000 mg/L HPAM solutions were merely 43.2% and 49.0% in brine, respectively. Compared with HPAM, both of the above copolymers presented better drag reduction capacities.

Adsorption and Desorption Behavior of Partially Hydrolyzed Polyacrylamide on Longmaxi Shale

Large-scale volumetric fracturing is generally used during shale gas development. The return rate of fracturing fluid is low, and a large amount of slickwater is retained in the reservoir. The adsorption and desorption of partially hydrolyzed polyacrylamide (HPAM), an additive commonly used in slickwater, on the surface of shale was studied using Longmaxi shale from the Sichuan Basin. The experimental results showed that the mass ratio of the HPAM solution to shale reached saturation adsorption at 20:1 when the concentration of HPAM solution was 1000 mg/L and 25:1 when the concentration of HPAM solution was 500 mg/L. The mass ratio of the HPAM solution to shale was fixed at 25:1, and the adsorption equilibrium was reached at a HPAM concentration of 1000 mg/L when the aqueous solution temperature was 30 °C and 800 mg/L when the aqueous solution temperature was 60 °C. The Langmuir adsorption model yielded a better fit than the Freundlich adsorption model. The adsorption equilibrium time at 30 °C was at 60 min for a HPAM concentration of 500 mg/L, while for a concentration of 1000 mg/L, it was at 90 min. The adsorption equilibrium time at 60 °C was 40 min for a HPAM concentration of 500 mg/L, whereas it was 60 min for a HPAM concentration at 1000 mg/L. The pseudo-second order (PSO) kinetics model yielded better fits than the pseudo-first order (PFO) kinetics model. The adsorption of HPAM on shale was strong, and the adsorbed HPAM resembled cobwebs adhering to the shale surface. HPAM on the surface of shale after adsorption was able to resist the desorption capacity of water. However, when the amount of adsorbed HPAM on shale increased significantly, the amount of residual HPAM on the surface of the shale decreased rapidly during desorption in deionized water. The desorption of HPAM on the shale surface followed a modified desorption model. The higher the concentration of HPAM adsorbed on the shale surface was, the easier it was to desorb and the easier it was to be removed from the shale.

Statistical and rheological evaluation of the effect of salts in partially hydrolyzed polyacrylamide solutions

AbstractPartially hydrolyzed polyacrylamide (PHPA) is the most common anionic copolymer used in Enhanced oil recovery (EOR), but the use of this polymer presents some limitations in the presence of divalent cations. The objective of this work was to evaluate the thermal stability of PHPA in brines containing Na+, Mg2+, and Ca2+ cations (isolated or combined). In this study, the PHPA used at a concentration of 2500 mgL−1 has a MW of 20 × 106 Da. The stability of the polymeric solutions was monitored through rheological analyses for 180 days at 70°C, in the absence of oxygen, using a central composite rotational design. In the absence of dissolved oxygen and cations, the PHPA solution was basically the same as that observed over a period of 30 days. It was observed that Ca+2 ion had the greatest influence on reducing the viscosity of PHPA in all cases. Polymeric solutions with Total dissolved solids (TDS) greater than 1000 mg L−1 showed complete degradation of the polymer in 180 days. The statistical data corroborate the rheological results, showing that only the main effect of Na+ was not statistically significant and that the concentrations of Mg2+ and Ca2+ presented statistically significant effects in their linear components and quadratic components.

Synthesis and performance evaluation of a novel zwitterionic quaternary copolymer for enhanced oil‐recovery application

AbstractA novel quaternary copolymer of AA/AM/AOS/C16‐DMAAC was synthesized with acrylic acid (AA), acrylamide (AM), sodium α‐alkenyl‐sulfonate (AOS), and dimethyl‐hexadecyl‐allyl‐ammonium chloride (C16‐DMAAC), using ammonium persulfate and sodium bisulfate (NH4)2S2O8‐NaHSO3) as initiators. The structure of AA/AM/AOS/C16‐DMAAC was characterized using Fourier transform infrared spectroscopy and nuclear magnetic resonance hydrogen spectroscopy. It can be found that the thickening capacity, shearing resistance, temperature‐resistance, salt‐resistance, and emulsification properties of AA/AM/AOS/C16‐DMAAC were superior to those of most widely and cost‐effective partially hydrolyzed polyacrylamide (HPAM) solution at the same concentration. Specifically, the viscosity retention rate of AA/AM/AOS/C16‐DMAAC (3000 mg/L) solution was 86%, which was better than that of HPAM solution (52%) after 30 s of mechanical shearing at 28000 r/min. In addition, the enhanced oil recovery of AA/AM/AOS/C16‐DMAAC solution was 16% at 65 °C, which was about 1.5 times higher than that of HPAM solution (11%). Significantly, successful synthesis of zwitterionic quaternary copolymer emphasizes the importance of a systematic approach to designing appropriate copolymers for enhanced oil recovery.Highlights A novel zwitterionic quaternary copolymer of AA/AM/AOS/C16‐DMAAC was successfully synthesized. The performance on thickening capacity, shearing resistance, temperature‐resistance, salt‐resistance, and emulsification properties of AA/AM/AOS/C16‐DMAAC was superior to that of the most widely used partially hydrolyzed polyacrylamide (HPAM). The enhanced oil recovery of AA/AM/AOS/C16‐DMAAC (16%) was about 1.5 times higher than that of HPAM (11%).

The effect of NaCl and HPAM solution concentration on HPAM gel structure degradation by ultrasonic waves

AbstractThe present study evaluated the impact of ultrasonic waves on the degradation of partially hydrolyzed polyacrylamide (HPAM) gel structures, focusing on the effects of sonication time, NaCl concentration, and HPAM solution concentration. Results showed that both sonication time and salinity levels play a crucial role in the degradation of HPAM gel, with an increase in sonication time leading to a decrease in the remaining gel and the presence of NaCl in the solution decreasing the residual time required for degradation. The results also revealed that higher levels of salinity expedite the degradation of the gel. In addition, the study discovered that a rise in polymer solution concentration usually results in a reduction in gel degradation. The research suggests there might be an ideal combination of polymer solution and NaCl concentration for achieving the greatest decrease in the degradation rate. For 2‐min sonication, as the salinity of the HPAM solution, with a concentration of up to 5000 ppm, increases, the accumulated energy remains relatively constant. However, when the polymer solution concentration is increased, the accumulated energy becomes more sensitive to changes in salinity. The results of this study provide valuable insight into the interplay between polymer solution concentration, salt concentration, and the energy required for gel degradation, which can be applied in various fields including the oil and gas industry, petroleum processing, and environmental remediation.

Non-Newtonian Flow of Hydrolyzed Polyacrylamide Solution

Structural rheological model is used to describe the rheological behavior of hydrolyzed polyacrylamide aqueous solutions. The change in viscosity during stationary flow is explained by structure change of the polymer solution associated with contacts between macromolecules. Flow curves are well approximated by the generalized flow equation, except for the region of high shear rates, where the phenomenon of shear thickening is observed. The behavior of the rheological equation coefficients with a change in the polymer concentration is consistent with the conclusions of the structural rheological model.

Degradation of polyacrylamide (PAM) in aqueous solution by electron beam technology: Efficiency, viscosity reduction and correlation with microstructure of polymer molecules

In this paper, we present a systematic evaluation about degradation of partially hydrolyzed polyacrylamide (HPAM) in aqueous solution by ionizing radiation to find relationship between HPAM decomposition, viscosity reduction and microstructure of polymer molecules. The viscosity of the two HPAM solution declined rapidly from 5.2 to 3.0 mPa s to 1.4–1.2 mPa s with the adsorbed dose of 0.1 kGy, and then reached the level of pure water at 0.5 kGy. The molecular weight declined remarkably from 1.6 × 107 Da to 1.4 × 105 Da (HPAM1) and from 1.2 × 107 Da to 1.1 × 106 Da (HPAM2) at 0.1 kGy. The HPAM solution changed from pseudoplastic fluid behavior to Newtonian fluid after irradiation. Following ionizing radiation, the presence of anion Na+, Ca2+, Mg2+, anions HCO3- and SO42-(1000–5000 mg/L) and surfactant sodium dodecyl sulfate (SDS) (50–100 mg/L) respectively has slight effect on the rate and extent of viscosity reduction, while CO32- and surfactant petroleum sulfonate exhibit a great negative effect on reducing HPAM viscosity. Ionizing radiation is able to destroy the molecular structure and spatial structure of HPAM. Both the C-C backbones and pendant are attacked. It is proposed that the degradation products include ammonium, aliphatic hydrocarbon, small molecular acids and compounds with double-bond. With the absorbed dose of 0.1 kGy, the micelles-like aggregates are broken into small particles by direct microscope observation, while the stretched and coiled molecular strands shrink and curl to form an irregular network from AFM and SEM observation. The chains break into fragment scattered randomly as increasing dose to 1.0 kGy. Both the diameter size and dispersity of HPAM molecules decreased remarkably after irradiation.·OH is the major active species responsible for HPAM degradation and viscosity reduction. This study contributes to a multiscale understanding the mechanism of ionizing radiation-induced degradation of HPAM in aqueous solution.

Implications of chemical agents and nanofluids coupled with carbon dioxide to improve oil recovery factor

In this study, we experimentally investigated the effects of chemically enhanced oil recovery methods containing hydrolyzed polyacrylamide (HPAM), surfactant–hydrolyzed polyacrylamide (SHPAM), surfactant nanofluids (SNF), that is, coupled with carbon dioxide (CO2) and water chase injection to measure enhanced oil recovery methods in a sandstone reservoir. To proceed with the experiments, we performed four flooding tests at the simulated reservoir temperature of 70 °C. The sand packs were saturated with oil to establish the irreducible water saturation (Swr). Then, the fluid flow in sand packs remained undistributed for about 5 days to obtain the 1.5 pore volume (PV). We observed that the pressure drop had small fluctuations when there was waterflooding (until 1.5 PV), and after injecting the chemical agents, the pressure drop had a sharp rise. It is indicated that the chemical solution has implemented higher pressure drops (significant energy efficiency) to displace the oil instead of water. The maximum oil recovery factor was about 53% and 59% when HPAM and SHPAM solution displaced oil after waterflooding, respectively; however, it is observed that water chase flooding recovered about 8% and 14% of remaining oil in place while CO2 has increased only 3% and 5%, respectively. SNF solution can provide more oil recovery factors. It is about 72% (SNF with 0.5 wt%) and 67% (SNF with 1 wt%). We observed that water chase flooding recovered about 20% of oil in place while CO2 increased by only 8%. It was concluded that the SNF solution with 0.5 wt% tends to adhere to the water–CO2 and causes to improve oil recovery factor after SNF injection. Therefore, SNF is the optimum enhanced oil recovery method among other chemical agents. On the other hand, with the decrease in CO2 flow rate and increase in silica nanoparticles slug size, pressure drop has started to decrease in higher pore volume injections, indicating that larger volumes of CO2 can be stored in sand packs. However, by increasing the CO2 flow rate and decreasing silica nanoparticles slug size, CO2 can escape easily from the sand pack.

Effect of Amine-Functionalized Nanoparticles (SiO2/Amine) on HPAM Stability under Chemical Degradation Environments: An Experimental and Molecular Simulation Study

This work aimed to develop SiO2 nanoparticles functionalized with amine (SiO2/amine) to inhibit the chemical degradation of partially hydrolyzed polyacrylamide (HPAM) in the presence of different ionic species through static experiments and molecular simulations. The effect of the SiO2/amine on the rheological behavior of HPAM solution was evaluated in the presence of monovalent, divalent, and trivalent cations. To understand the relationships between polymers, ions, and nanostructures, interaction energies and the radii of gyration under all saline scenarios were calculated by molecular dynamics (MD). The SiO2/amine was spherical with a size <100 nm. There is a correlation between the ion’s valence and the chemical degradation of HPAM: in the presence of polyvalent cations, the viscosity losses of the HPAM solutions reached up to 94%, incorporating SiO2/amine at 100 mg L–1 mitigated the viscosity losses by up to 16%. The molecular simulations showed that the self-folding of the HPAM chains increased in brine containing trivalent cations leading to the viscosity loss of the solutions. The presence of SiO2/amine increased the radius of gyration of the polymer up to 17%, improving the viscosity of the HPAM solutions. This study opens a broader landscape regarding nanotechnology to improve polymer flooding applied to the oil industry.

Rheological Performance of High-Temperature-Resistant, Salt-Resistant Fracturing Fluid Gel Based on Organic-Zirconium-Crosslinked HPAM

Development of low-cost, high-temperature-resistant and salt-resistant fracturing fluids is a hot and difficult issue in reservoir fluids modification. In this study, an organic zirconium crosslinker that was synthesized and crosslinked with partially hydrolyzed polyacrylamide (HPAM) was employed as a cost-effective polymer thickener to synthesize a high-temperature-resistant and salt-resistant fracturing fluid. The rheological properties of HPAM in tap water solutions and 2 × 104 mg/L salt solutions were analyzed. The results demonstrated that addition of salt reduced viscosity and viscoelasticity of HPAM solutions. Molecular dynamics (MD) simulation results indicated that, due to electrostatic interaction, the carboxylate ions of HPAM formed an ionic bridge with metal cations, curling the conformation, decreasing the radius of rotation and thus decreasing viscosity. However, optimizing fracturing fluids formulation can mitigate the detrimental effects of salt on HPAM. The rheological characteristics of the HPAM fracturing fluid crosslinking process were analyzed and a crosslinking rheological kinetic equation was established under small-amplitude oscillatory shear (SAOS) test. The results of a large-amplitude oscillation shear (LAOS) test indicate that the heating effect on crosslinking is stronger than the shear effect on crosslinking. High-temperature-resistant and shear-resistant experiments demonstrated good performance of fracturing fluids of tap water and salt solution at 200 °C and 180 °C.

Synthetic polyampholytes based on acrylamide derivatives – new polymer for enhanced oil recovery

Background: Due to its high efficiency, polymer flooding has been widely used in the fields of Kazakhstan. However, under conditions of high water salinity, high concentrations of polymers are needed to ensure the design viscosity of the solutions, therefore, polymers are needed that, at concentrations not exceeding 0.10.2%, will increase the viscosity of water up to 2050 cP when the formation water salinity is above 200 g/ l.&#x0D; Aim: The purpose of this work is to study the salt- and heat-resistant properties of a linear polyampholyte based on acrylamide, an anionic monomer sodium salt of 2-acrylamido-2-methyl-1-propanesulfonic acid - and a cationic monomer (3-acrylamidopropyl) trimethylammonium chloride and substantiate its applicability in oil production.&#x0D; Materials and methods: We used water with a salinity of 200300 g/l, as well as oils with viscosities of 60, 138, and 420 cP. To simulate a porous medium, bulk sand models and aerated concrete with high porosity were chosen. Hydrolyzed polyacrylamide with a molecular weight of 17 million Da and a ternary polyampholyte with a molecular weight of 2.9 million Da were used as polymers. To compare the effectiveness of these polymers under conditions of high salinity, experiments were carried out to measure the dynamic viscosity and oil displacement efficiency.&#x0D; Results: It is shown that the injection of a 0.25% solution of triple polyampholyte dissolved in water with a salinity of 200 g/l into sand models increases the oil displacement efficiency by 2328% compared to the injection of formation water. Under identical conditions, the injection of a hydrolyzed polyacrylamide solution resulted in an increase in the oil displacement efficiency by only 18%.&#x0D; Conclusion: Triple polyampholyte based on acrylamide derivatives has superior oil displacement properties compared to hydrolyzed polyacrylamide in high salinity reservoirs. The results of laboratory experiments can draw the attention of oil and gas industry specialists and subsoil users to new developments by the staff of the Institute of Polymer Materials and Technologies in terms of scaling up synthetic polyampholytes and conducting pilot tests.

Probing the Effect and Mechanism of Flue Gas on the Performance of Resorcinol/Hexamethylenetetramine-Based Polymer Gel in Flue Gas Flooding Reservoir.

Polymer gel plugging is an effective method for gas mobility control in flue gas flooding reservoirs. However, the effect and mechanism of flue gas on the performance of polymer gels have rarely been reported. In this study, a polymer gel was prepared by cross-linking hydrolyzed polyacrylamide (HPAM) and resorcinol/ hexamethylenetetramine (HMTA) to illuminate the influencing mechanism of flue gas composition on gel. The gel rheological testing results showed that flue gas promoted gelation performance, whereas it seriously threatened gel long-term stability, especially at high pressure conditions. The influence of CO2 on the polymer gel had the characteristic of multiplicity. The hydrodynamic radius (Rh) and the initial viscosity of HPAM solution decreased in the presence of CO2. Nonetheless, the dissolved CO2 expedited the decomposition rate of HMTA into formaldehyde, which promoted the cross-linking process of the HPAM, leading to a shorter gelation time. Oxidation-reduction potential (ORP) tests and Fourier transform infrared spectroscopy (FTIR) analysis indicated that O2 played a leading role in the oxidative degradation of HPAM compared to CO2 and threatened the gel long-term stability at elevated gas pressures. To address the adverse effects caused by flue gas, it is highly desirable to develop polymer gels by adding oxygen scavengers or strengthening additives.

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

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

Treatment of polyacrylamide-containing wastewater by ionizing radiation: Efficient reduction of viscosity and degradation of polyacrylamide

Polyacrylamide is one of the most widely used polymer to enhance oil recovery in oilfield, leading to generation of partially hydrolyzed polyacrylamide (HPAM)-containing wastewater, with large amount, high viscosity and emulsification, making the oil droplets and particles in the wastewater stable and difficult to remove. In present work, ionizing radiation was applied to decompose HPAM, thus to reduce the viscosity of HPAM-containing wastewater. During radiation, the viscosity of HPAM solution declined rapidly and the reduction extend was affected slightly by the initial HPAM concentration and pH. The viscosity decreased from 5.2 to 12 mPa s to 1.1–1.6 mPa s at the absorbed dose of 1.0 kGy, while the absolute value of zeta potential also declined rapidly from 116 mV to 79 mV. The removal efficiency of HPAM was 62–78% at 10 kGy at the initial concentrations of 250–1000 mg/L. The molecular weight of HPAM declined from 12,000 kDa–320 kDa at 5 kGy. Gamma radiation might destroy hydrogen bonds of intermolecular and intramolecular HPAM molecules preferentially, leading to the destruction of the curling network structure, thus the reduction of viscosity. The attacks on C–N bond, C–C skeleton, amide and carboxyl groups were also occurred, resulting in the formation of intermediate products, such as aliphatic hydrocarbon, ammonium, ketone, etc. In summary, ionizing radiation is a promising alternative to treat HPAM-containing oilfield wastewater.

Injectability of Partially Hydrolyzed Polyacrylamide Solutions Improved by Anionic-Nonionic Surfactant in Medium and Low Permeability Reservoirs

Injectability of the polymer solution is a very important factor that determines the effectiveness of polymer flooding for enhanced oil recovery. Here, the medium and low permeability oil reservoir was taken as a research object, and effects of relative molecular weight, concentration and core permeability on the flow and injection performance of a partially hydrolyzed polyacrylamide (HPAM) solution with and without anionic-nonionic surfactant (ANS) were studied by indoor outcrop core physical model experiments. It was found that the influence of HPAM concentration on the flow performance was related to the core permeability. When the core permeability was lower than 59 mD, the resistance factor and residual resistance factor of HPAM increased with increasing the concentration. High molecular weight and low core permeability were not conducive to the injectability of HPAM solutions. The addition of ANS was beneficial in enhancing the injectability of HPAM solution by reducing the critical value of injectability of HPAM solution, which was elucidated by the Hall curve derivative method. In the presence of ANS, the flow pressure gradient and the residual resistance factor of the HPAM solution decreased. It is believed that the injectability of HPAM solution improved by ANS in the medium and low permeability reservoirs can be attributed to decrease in fluid viscosity and competitive adsorption on the surface of porous media. The study provides a new idea and theoretical basis for improving the injectability of an HPAM solution and the application of polymer flooding and a polymer/surfactant binary flooding system in medium and low permeability reservoirs.

Tug-of-war between hydrogen bond and hydrophobic interaction of bisfunctionalized graphene oxide/hydrolyzed polyacrylamide allows thickening and salt-resistance in enhanced oil recovery

Polymer flooding is the most commonly used method to enhance oil recovery. Due to the harsh stratum environment, it is particularly important to prepare polymer systems with high viscosity and salt resistance. Here, we present a tug-of-war strategy that can easily control polymer system viscosity and salt resistance. By introducing hydroxyl and phenyl groups to the surface of GO, we successfully synthesized a series of Diethanolamine-Diphenylpropylamine Graphene Oxide (DDGO) with different ratio of hydroxyl and phenyl, as confirmed by TGA, ATR-FTIR and XPS analysis. 1H NMR demonstrated the three DDGOs have different phenyl/hydroxyl ratio. TEM images showed DDGO maintained 2D nanostructure upon modification. We mixed partially hydrolyzed polyacrylamide (HPAM) with DDGO to form a hybrid system. The surface hydroxyl groups of DDGOs are bridged with HPAM through hydrogen bonds to improve network structures, whereas phenyl groups are conducive to self-association by π-π interaction. The properties of the hybrid systems are regulated by the tug of war of functional groups on the surface of nanoparticles. The results from oil displacement experiments showed that the enhanced oil recovery ratio jumped to 21.5% for HPAM/DDGO system, while it was only 7.7% for HPAM solution, which provides an alternative thought of EOR.

Investigation of the drag reduction of hydrolyzed polyacrylamide–xanthan gum composite solution in turbulent flow

AbstractIn this paper, the rheological properties, drag reduction properties, and flow field characteristics of hydrolyzed polyacrylamide (HPAM) solution, xanthan gum (XG) solution, and HPAM–XG composite solution were analyzed to explore the synergistic effect of flexible and rigid polymer. The experimental results show that the viscoelasticity and shear thinning of the composite solution are significantly enhanced compared with single‐component solution, which indicates that the rigid XG has an effect on the viscoelasticity of the flexible HPAM solution. Compared with the single‐component solution, the drag reduction rate of HPAM–XG composite solution is higher, and the mean flow field of HPAM–XG composite solution changes less after being sheared for 300 minutes, which means that not only the drag reduction effect of composite solution is better, but also the shear resistance. Compared with single‐component solution, the mean velocity distribution of the composite solution moves upwards most obviously in the logarithmic layer, the peak of velocity fluctuation in the main flow direction of composite solution is higher, the suppression degree of normal velocity fluctuation is deepened, and the corresponding vorticity intensity is also reduced. These changes in the flow field characteristics explain the reason for the drag reduction gain of the composite solution.

The impact of viscoelastic nanofluids on the oil droplet remobilization in porous media: An experimental approach

Abstract Polymer nanohybrids have displayed great potential in remobilizing oil droplets through porous media. This research aims at providing some insights into how the hydrolyzed polyacrylamide (HPAM) polymer and Al2O3 nanoparticles’ (NPs) hybrid can push crude oil toward the producers. An understanding of what the hybrid viscosity is when flowing through porous rocks was acquired by the rheological tests. Using the Du Noüy ring method, the interfacial tension (IFT) between the polymer nanohybrid and crude oil was studied. Contact angle experiments were employed to assess the ability of hybrid in reversing surface wettability. The results show that the hybrid can yield a 12% higher shear viscosity than the HPAM solution and the viscosity improvement dramatically depends on NPs’ concentration and temperature. With more than a 23% drop in the contact angle value, the results of contact angle experiments reveal the capability of the Al2O3 NPs in altering surface wettability. The measured IFT between hybrid and crude oil at different temperatures demonstrates that the adsorption of NPs on the oil–aqueous phase interface can significantly improve the capillary number. This article not only presents the underlying mechanisms of oil recovery during hybrid flooding but also provides a new reference for formulating a novel hybrid agent.

Synergistic effect of Polymer-Augmented low salinity flooding for oil recovery efficiency in Illite-Sand porous media

Low salinity water (LSW) flooding is a novel and emerging technique for oil recovery and has received significant attention recently by petroleum industries as an efficient, economical, and environmentally friendly method compared to other secondary and tertiary oil recovery methods. Although LSW flooding has been proven to be a promising technique, its conjunction with the traditional polymer flooding process (called low salinity polymer, LSP flooding) to control flood front mobility of LSW could be a game-changer. A very few studies have investigated the effectiveness of LSP flooding in terms of oil recovery efficiency. But the effect of clay minerals such as illite present in the hydrocarbon reservoir has remained to be investigated. Herein, this work reports the injection of the partially hydrolyzed polyacrylamide (HPAM) polymer augmented LSW flooding into an oil-saturated sandpack consisting of sand (98%) and illite (2%). HPAM characterization and effect of polymer concentration (1000–5000 ppm), salinity (0–60000 ppm), and temperature (26℃ − 70℃) on the rheological behaviour of the HPAM solution has been investigated. The possible mechanisms have also been discussed to understand the interaction between illite and LSP slug in the sandpack. The sandpack flooding experiments reveal that the LSP flooding recovered more additional oil (42.7%) than high salinity polymer (HSP) flooding (35.4%), with an ultimate oil recovery of 67.7% and 60.4 %, respectively. However, in the absence of polymer, oil recovery was limited to only 25% of the original oil in place (OOIP). The findings of this study can help to understand the synergistic effect of LSW and variety of polymeric solutions on oil recovery in the presence of different clay minerals.