Hydrolyzed Polyacrylamide Research Articles

Hydrolyzed Polyacrylamide Screening for EOR in an Indonesia Mature Oil Field

Most of Indonesia’s oil field has been producing the oil for long period of time. For this reason, enhanced oil recovery (EOR) method becomes the most promising method to improve oil production for the country. Chemical flooding, especially polymer flooding is the simplest and the most commonly applied chemical enhanced oil recovery technique, since it can be used after water flooding process. Screening is considered the first step in evaluating and selecting potential polymers for reservoirs. Therefore, this paper aims to select partially Hydrolyzed Polyacrylamide (HPAM) base polymers to find suitable polymer for a targeted mature reservoir in Indonesia. A polymer screening study was carried out on 3 HPAM polymers to identify a potential candidate which can withstand reservoir conditions. These are Kerui, Zekindo, and FP 3630S. Initially, a comprehensive rheological (viscosity, shear rate) study was conducted at various polymer concentrations (500 - 2500 ppm) and brine to investigate the polymers. Then, filtration and screen factor test was conducted at various concentrations (1000 - 2000 ppm). Then, a thermal stability test was conducted at anaerobic condition and 140 °F for 2 months. Finally, for oil recovery used core flooding test. Based on the result of the test, FP 3630S with a concentration of 2000 ppm was chosen for the core flooding test. The test was designed in 3 steps: At first, water injected into the sample, followed by polymer-solvent at 2000 ppm concentrated of 1 PV, the finally injected by water. The results of core flooding showed oil recovery of 28.93 % OOIP. Finally, this study was performed to develop screening criteria and to correlate oil recovery prediction.
 HIGHLIGHTS
 
 One of the efforts to increase old field production is by choosing the right type of polymer to be injected
 Polymer screening was carried out through testing stages, namely rheology, filtration and screen factor, thermal stability, and core flooding
 Selected one type of polymer that meets all the qualifications of the screening tests
 
 GRAPHICAL ABSTRACT

The comparison of interface properties on crude oil-water and rheological behavior of four polymeric nanofluids (nano-SiO2, nano-CaO, GO and CNT) in carbonates for enhanced oil recovery

Nanoparticles (NPs) are currently being used in different areas of petroleum exploration and production, such as drilling, well logging, reservoir management, and enhanced oil recovery (EOR). Nanofluids, prepared from NPs, have been used as a novel flooding for EOR due to the excellent performance in altering interfacial properties and improving rheological behaviors. The properties of nanofluids vary with the structure of nanofluids. Nonetheless, most of the previous studies have focused on a particular type of nanofluid, the interfacial properties of various polymeric nanofluids and their flow behaviors under harsh and challenging reservoir conditions have been rarely reported or compared in literature. In this study, four polymeric nanofluids, prepared by mixing nano-silica (nano-SiO2), nano-CaO, carboxyl functionalized graphene oxide (GO) and amino modified carbon nanotube (CNT) with partially hydrolyzed polyacrylamide (HPAM), were characterized through XRD, FT-IR, UV–Vis and SEM to confirm that the materials were successfully prepared. Then, the colloidal stability, interfacial tension (IFT) reduction, rheological behavior, and wettability on calcite surface of these polymeric nanofluids were also studied in comparison. The experimental results of CNT-NH2/HPAM nanofluid showed that the overlap degree of BS and ΔBS curves was high, oil/brine IFT reduced from 35.84 mN/m to 18.11 mN/m and the contact angle on calcite surface reduced from 139.69° to 47.985°, indicating that the nanofluids were colloidally stability, and both reduce the IFT and alter wettability effectively. Furthermore, the addition of SiO2 and CNT NPs enhanced the network structure significantly, and showed excellent rheological behavior of polymer solution with improved viscoelasticity. Finally, the CNT-NH2/HPAM nanofluid increased the additional oil recovery from 13.8% to 21.6% in core flooding experiments, with the oil displacement mechanism explained in detail. Therefore, the findings of this study can help for better understanding of the effect of NPs on polymeric nanofluids, and set the stage for future investigation into EOR application in carbonate reservoirs.

Dynamic interfacial tensions of sulfobetaine and polymers solutions: Effect of structures

To facilitate the understanding of the intrinsic mechanism responsible for the IFTs of betaine solutions, partly hydrolyzed polyacrylamide (HPAM) and hydrophobically modified polyacrylamide (HMPAM) were employed to investigate their effect on IFTs of different betaine solutions against decane using a spinning drop interfacial tensiometer. Moreover, the effects of oleic acid on the IFTs of betaine-polymer systems were also studied. The results show that the water-soluble polymers (HPAM) form the mixed adsorption film with alkyl sulfobetaine (ASB) molecules and prevent the hydrophilic groups of ASB from lying flat, which produces a minimum IFT with aging time. Besides, the hydrophobic HMPAM forms mixed micelle-like interfacial associations with ASB molecules, which results in a stronger disruption tendency for the interfacial film. The branched xylyl substituted alkyl sulfobetaine (BSB) molecules will form a tight interfacial film, therefore HPAM can’t insert into the interfacial film easily. Meanwhile, steric hindrance makes it difficult to form interfacial aggregates with HMPAM. Thus, the addition of HPAM and HMPAM polymers has little influence on the IFTs in the BSB system. The mixed adsorption of oleic acid and betaine molecules results in a significant decrease in IFTs, especially for BSB. However, in the ASB-polymer system, HPAM forms mixed adsorption film with ASB molecules and hinders the adsorption of oleic acid, accordingly IFTs change little. In contrast, the hydrophobic interaction of HMPAM promotes the adsorption of oleic acid, so the synergistic effect reduces IFTs to some extent. In the BSB-polymer system, the strong synergistic effect between oleic acid and BSB molecules is disrupted by polymers, which results in a significant increase in IFTs. The relevant results are helpful for the design of novel and efficient chemical flooding systems.

Influence study of flue gas on chromium acetate/HPAM gel in flue gas flooding reservoir

Polymer gels are potential plugging agents for gas mobility control in flue gas flooding reservoirs. However, the influence of flue gas on performances of polymer gels have not been clearly clarified so far. In this study, the effect mechanism of flue gas on chromium acetate/partially hydrolyzed polyacrylamide (HPAM) gel system has been elucidated in detail. Dynamic light scattering (DLS) and polymer rheological tests demonstrated that CO2 composed in flue gas altered the HPAM configuration by the decrease of hydrodynamic radius (Rh) and polymer viscosity. Moreover, CO2 delayed the chromium acetate cyclic trimer dissociating into linear trimer and retarded the cross-linking process, which weakened the gelation performance and gel strength. The O2 composed in flue gas led to polymer degradation and seriously impaired the gel long-term stability. Fourier transform infrared spectroscopy (FTIR) analysis revealed that the breakage of Cr-O bond and the disruption of gel network structure were induced by the comprehensive effect of O2 and CO2.

Interfacial tension reduction mechanism by alkaline-surfactant-polymer at oil-water interface from experimental and molecular dynamics approaches

Chemical injection such as alkaline (A), surfactant (S), and polymer (P) in chemical enhanced oil recovery (CEOR) can improve oil recovery by modifying the injected fluid characteristics to enhance interaction with oil in the reservoir. The presence of complex composition in CEOR flooding complicates the study in investigating the mechanism of ASP at the oil–water interface. For this reason, the interfacial tension (IFT) reduction mechanism of ASP solution with the presence of crude oil was investigated via experimentally and molecular dynamics (MD) simulation. The IFT analysis was conducted to determine the optimum ASP composition in reducing the IFT value. The spinning drop video tensiometer (SVT) was used to measure the IFT experimentally. The optimum composition of ASP in reducing the IFT value was 0.3 M S672, 1.0 M Na2CO3, and 0.125 µM hydrolyzed polyacrylamide (HPAM) solution with the IFT value of 0.08 mN/m. The MD simulation successfully predicted the mechanism of ASP in reducing the IFT value. The mechanism in IFT reduction was explained by the surfactant adsorption at the interface, interfacial thickness, and hydrogen bond formation.

Polymer Retention “Tailing” Phenomenon Associated with the Milne Point Polymer Flood

Summary Associated with the Milne Point polymer flood (on Alaska’s North Slope), this paper explores the unusual shape of hydrolyzed polyacrylamides (HPAM) breakout/propagation during dynamic polymer retention measurements in Milne Point core material. In contrast to conventional expectations, polymer retention does not delay the initial polymer arrival at the end of a Milne Point core. However, after effluent polymer concentrations rapidly rise to at least 50% of the injected value, the concentration gradually “tails” up over many pore volumes (PVs) before it finally achieves the injected value. To understand the origin and significance of this behavior, a wide range of core experiments were performed, including substantial variations in polymer concentration and molecular weight, core length, preservation state, sand grain size, and mineral composition. Illite was identified as primarily responsible for the tailing phenomenon. This phenomenon has important consequences that must be considered when projecting the performance of the field project. This work suggests that mineralogy analysis (especially for illite and kaolinite) may reveal whether tailing should be accounted for during simulations of polymer propagation/retention in a given field application.

Pore-Scale Flow Fields of the Viscosity-Lost Partially Hydrolyzed Polyacrylamide Solution Caused by Sulfide Ion

The rheology of a partially hydrolyzed polyacrylamide (HPAM) solution plays an important role in its oil recovery during polymer flooding. However, multiple factors in brine, such as sulfide ions, cause a dramatic loss in the viscosity and oil recovery. To better understand the sulfide-induced viscosity loss and the consequent flow mechanisms in pore networks, the morphology of polymer solutions with and without sulfide ion was observed by scanning electron microscopy; and the variations of the pore scale flow fields were demonstrated by a microscopic visualization seepage experiment combined with Micro-PIV (Microscale Particle Image Velocimetry). The results showed that, with the presence of sulfide ion, the microstructure of the polymer changed from a uniform three-dimensional network structure to loose and uneven floccules, which resulted in viscosity loss (over 70% with 5-mg/L sulfide ion). Moreover, higher concentrations of sulfide ions (5 mg/L and 10 mg/L) resulted in earlier shear thinning characteristics than those with lower sulfide concentrations. Due to viscosity loss, the average flow velocity in the main stream of the microscopic seepage experiment increased more significantly than that without sulfide. However, the viscosity loss alone cannot independently explain the severe viscous fingering during the subsequent post-water flooding, which was about five times greater than that of the primary water flooding in terms of the velocity ratio between the mainstream and margin. A further pore-scale flow field analysis exhibited an eccentric and a bimodal velocity distribution in the throat along the radial and axial directions, respectively. The former distribution indicated that the adsorbed polymer on the pore wall was broken through by hydraulic shear due to the collapsed structure caused by sulfide ion. The latter suggested that another sulfide-induced impact was an earlier-occurring non-Newtonian characteristic with a low shear rate. Therefore, instead of viscosity loss, elastic loss is the dominant mechanism affecting the characteristics of the aggregate flow field under the action of sulfide. Microscopic flooding combined with Micro-PIV is a feasible and essential method to reveal pore scale flow mechanisms.

Impact of polymer on electro-kinetic properties of crude oil, brine and rock interfaces

In recent years, there has been a growing interest in the petroleum industry to improve the ultimate oil recovery method by using low-salinity polymer flooding (LSPF) with the synergistic effect by combining polymer and low-salinity water injection. Although numerous research studies have focused on the technical and economic benefits of low salinity polymer (LSP), to the best of our knowledge, crude oil/brine/rock (COBR) interactions in LSP did not receive enough attention due to the complexity of the interactions between brine, polymer, crude oil, and the rock surface. Therefore, this study aimed to investigate the impact of polymer on COBR interactions with different brine chemistry and improve the understanding of active mechanisms of LSPF. Partially hydrolyzed polyacrylamide (HPAM) polymer, Boise rock, a crude oil sample from an Omani oil field, and several brine solutions were used in the study. Zeta potential and pH measurements were performed to examine the role of polymer on electrical properties of brine/rock and oil/brine interfaces. In addition, rheological properties of the polymer were investigated at different salinity and brine compositions. Changes in Boise rock surface charge through zeta potential measurements were investigated in the absence and presence of polymer. pH and rheology measurements for equilibrated brines with and without polymer and zeta potential of crude oil/equilibrated brine were performed. The results revealed that the addition of polymer to the brine not only increased the viscosity, but also affected the electrical charge at crude oil/brine/rock (COBR) interfaces and triggered pH increase of the brine. The impact of polymer on COBR interactions is mainly controlled by the water chemistry. In the absence of ions, polymer molecules did not affect the charge of COBR interfaces, while in the presence of ions, at different compositions and concentrations, the charge of COBR interfaces changed to become more negative. Thus, the presence of polymer in brine increases the electrostatic repulsion between crude oil/brine and brine/rock interfaces, increases electrical double layer (EDL) thickness, and makes the water film more stable. A direct relationship between the viscosity and zeta potential of the polymer solutions was observed at different brine chemistry. Moreover, the presence of polymer at different brine chemistry resulted in an increase in pH of the aqueous phase. This could in turn reduce the adsorption of polar organic acids from crude oil. Therefore, in addition to the reduction of the water-oil mobility ratio, polymer molecules could contribute to an increase in the repulsion forces between COBR interfaces and an increase in the pH of the aqueous solution.

Syneresis Behavior of Polymer Gels Aged in Different Brines from Gelants.

Gel syneresis is a common problem in gel treatment for oil recovery applications. In this study, a stable gel was prepared in a soft brine by using a water-soluble phenolic resin as a crosslinker, nanoparticles as a stabilizer, and partially hydrolyzed polyacrylamide (HPAM) or copolymers with different contents of 2-acrylamido-2-methylpropane sulfonic acid (AMPS) groups as polymers. The syneresis behavior of the gels formed in a soft brine was evaluated upon aging in hard brines. The results show that when the salinity of the hard brine is lower than 30,000 mg/L, the gel expands, and its strength decreases; when the salinity of the hard brine is higher than 50,000 mg/L, the gel exhibits syneresis, and its strength increases. The effects of various influencing factors on the gel syneresis behavior were also evaluated. It was found that optimizing the polymer structure and adding nanoparticles can effectively overcome gel syneresis and enhance gel stability. Based on the research described in this paper, some proposals for designing salt-resistant polymer gels are presented.

Hydrolyzed Polyacrylamide Screening for EOR in an Indonesia Mature Oil Field

Most of Indonesia’s oil field has been producing the oil for long period of time. For this reason, enhanced oil recovery (EOR) method becomes the most promising method to improve oil production for the country. Chemical flooding, especially polymer flooding is the simplest and the most commonly applied chemical enhanced oil recovery technique, since it can be used after water flooding process. Screening is considered the first step in evaluating and selecting potential polymers for reservoirs. Therefore, this research aims to select partially Hydrolyzed Polyacrylamide (HPAM) base polymers to find suitable polymer for a targeted mature reservoir in Indonesia. A polymer screening study was carried out on 3 HPAM polymers to identify a potential candidate which can withstand reservoir conditions. These are Kerui, Zekindo, and FP 3630S. Initially, a comprehensive rheological (viscosity, shear rate) study was conducted at various polymer concentrations (500 - 2500 ppm) and brine to investigate the polymers. Then, filtration and screen factor test was conducted at various concentrations (1000 - 2000 ppm). Then, a thermal stability test was conducted at anaerobic condition and 140 °F for 2 months. Finally, for oil recovery used core flooding test. Based on the result of the test, FP 3630S with a concentration of 2000 ppm was chosen for the core flooding test. The test was designed in 3 steps: At first, water injected into the sample, followed by polymer-solvent at 2000 ppm concentrated of 1 PV, the finally injected by water. The results of core flooding showed oil recovery of 28.93 % OOIP. Finally, this study was performed to develop screening criteria and to correlate oil recovery prediction.
 HIGHLIGHTS · One of the efforts to increase old field production is by choosing the right type of polymer to be injected · Polymer screening was carried out through testing stages, namely rheology, filtration and screen factor, thermal stability, and core flooding · Selected one type of polymer that meets all the qualifications of the screening testsGRAPHICAL ABSTRACT

2-D porous flow field reveals different EOR mechanisms between the biopolymer and chemical polymer

Biopolymers are potential flooding agents that can tolerate high temperatures and salinity. The screening of biopolymers has always followed the same rules based on viscosity and elasticity testing as chemical polymers, and the parameters are comparable. However, the current pilot field study of biopolymer flooding did not achieve the expected effect as chemical polymers. Therefore, it was necessary to examine the difference between the two polymer types in the flooding process and examine the EOR mechanisms to explain the suboptimal performance of biopolymers. Traditional microscopic flooding experiments were carried out in the present study, but the results showed no significant difference in recovery of the two polymer types (only 2% original oil-in-place (OOIP) difference) or in sweep and the microscopic displacement efficiency, indicating that a traditional experiment is not sufficient to explain the performance difference between the two polymer types. Therefore, to distinguish the two types of recovery processes, micro-PIV experiments were carried out to further quantitatively investigate the flow field characteristics of the two polymers. The results showed that the flow velocity after xanthan gum (XG) injection significantly decreased 88.6% of water injection but only 26.9% after partially hydrolysed polyacrylamide (HPAM), indicating severe pore clogging by XG. Therefore, there are differences in EOR mechanisms: HPAM improves the mobility ratio, while XG clogs pores and changes the flow direction. To understand the reasons for the distinct flow fields, further quantitative analysis was conducted. First, in the margin region with a relatively lower velocity, the effective flow diameter was reduced to 48.04% and 62.69% of the pore width after XG and HPAM injection, respectively, indicating that the adsorption of XG was stronger than that of HPAM, although both could be adsorbed. Second, both velocities after polymer injection remained in a similar low range in wide channels, while the velocity after HPAM increased up to six times higher than XG in narrow channels, indicating that the shear resistance of XG is greater than that of HPAM and is the key mechanism for its higher pore adsorption and pore clogging ability. Therefore, the strong clogging of biopolymers results in poor migration ability in reservoirs, which is the major reason why biopolymers cannot reach deep oil-rich regions and show suboptimal recovery. Therefore, understanding how the agents migrate in reservoirs is the key to improving utilization efficiency, and the combination of micro-PIV and pore scale flow experiments is essential for understanding the flow fields and characteristics. • The flow field of polymers were quantitatively studied by micro-PIV experiments. • The EOR mechanism by biopolymer lies in the deposition and clogging pores. • The strong clogging results in poor migration ability and suboptimal recovery. • Understanding how agents migrate in reservoirs is essential for oil recovery.

Turbulent drag reduction of viscoelastic wormlike micellar gels

Long-chained, viscoelastic surfactant solutions (VES) have been widely employed in the oil and gas industry, particularly in hydraulic fracturing and gravel-packing operations, where turbulence is commonly reached due to high pumping rates. With this motivation, we experimentally investigate the turbulent duct flow of an under-studied class of wormlike micellar solutions that forms a gel at room temperature. The fluid is characterized via rotational rheometry, and the turbulent velocity and Reynolds stress profiles are measured via Laser Doppler Anemometry (LDA). Three surfactant concentrations are investigated at increasing Reynolds numbers. The turbulent flow fields of water, and semi-dilute solutions of partially hydrolysed polyacrylamide (HPAM) and xanthan gum (XG) are used as comparisons. Our study reveals that the gel-like structure of the wormlike micellar gel is mostly broken down during turbulent flow, especially in the near-wall region where the results indicate the presence of a water layer. Turbulent flow at low concentrations of surfactant show a Newtonian-like flow field throughout most of the duct, where the energy spectra shows a − 5 / 3 power law scale with wavenumber, whereas higher concentrations lead to drag reduction and lower power spectral densities at large wavenumbers. A comparison of the flow of polymeric fluids and the wormlike micellar solutions at maximum drag reduction (MDR) shows comparable drag-reduction effects, with a large decrease in Reynolds shear stresses, and increased turbulence anisotropy in the buffer layer due to the large streamwise fluctuations and near-zero wall-normal fluctuations. At the centreline of the duct, the power spectral densities of polymers and VES are significantly reduced at all wavenumbers probed. Additionally, the MDR regime was bounded by Virk’s asymptote for both polymers and the micellar gel, which implies a similar mechanism of drag reduction at MDR. • Turbulent flows of wormlike micellar gels (VES) are experimentally studied. • Turbulent flows of VES and polymeric liquids are quantified via LDA measurements. • Steady flow curves of VES are not representative of its rheology in turbulent flow. • At MDR, the VES and polymer solutions show decreased energy spectra. • Our results show similar drag reduction mechanisms between VES and polymers at MDR.

Mechanistic modeling of hybrid low salinity polymer flooding: Role of geochemistry

Low salinity polymer (LSP) based enhanced oil recovery (EOR) technique is getting more attention due to its potential of improving both displacement and sweep efficiencies. Modeling LSP flooding is challenging due to the complicated physical processes and the sensitivity of polymers to brine salinity. In this study, a coupled numerical model has been implemented to allow investigating the polymer-brine-rock geochemical interactions associated with LSP flooding along with the flow dynamics. MATLAB Reservoir Simulation Toolbox (MRST) was coupled with the geochemical software IPhreeqc, which is the interface module of Phreeqc (i.e., pH-Redox-Equilibrium in C programming language). The effects of polymer were captured by considering Todd–Longstaff mixing model, inaccessible pore volume, permeability reduction, polymer adsorption as well as salinity and shear rate effects on polymer viscosity. Regarding geochemistry, the presence of polymer in the aqueous phase was considered by adding a new solution specie and related chemical reactions to Phreeqc database files. Thus, allowing for modeling the geochemical interactions related to the presence of polymer. Coupling the two simulators was successfully performed, verified, and validated through several case studies. The coupled MRST–IPhreeqc simulator allows for modeling a wide variety of geochemical reactions including aqueous, mineral precipitation/dissolution, and ion exchange reactions. Capturing these reactions allows for real time tracking of the aqueous phase salinity and its effect on polymer rheological properties. The coupled simulator was verified against Phreeqc for a realistic reactive transport scenario. Furthermore, the coupled simulator was validated through history matching a single-phase LSP coreflood from the literature. This paper provides an insight into the geochemical interactions between partially hydrolyzed polyacrylamide (HPAM) and aqueous solution chemistry (salinity and hardness), and their related effect on polymer viscosity. This work is also considered as a base for future two-phase polymer solution and oil interactions, and their related effect on oil recovery.

Mechanical Degradation of Biopolymers for Enhanced Oil Recovery Applications

Summary Polymer degradation is detrimental to enhanced oil recovery (EOR) because it ultimately leads to solution viscosity loss. Molecular breakage during flow owing to high stresses, known as mechanical degradation, can occur in numerous stages during field polymer injection. One of the reasons biopolymers are promising for EOR is their enhanced mechanical stability compared to their polyacrylamide counterparts. This study presents a comparative investigation of the mechanical degradation of biopolymers with potential applications in EOR. The mechanical degradation was evaluated by flowing the solutions through a short-length capillary (internal diameter of 0.127 mm and length of 10 mm) and then testing their viscosity loss through a rheometer. Nine flow velocities were tested between 0.13 and 66 m/s (shear rates between 8.29 × 103 and 1.66 × 107 s−1) in addition to the undegraded baseline. Four biopolymers were evaluated [xanthan gum (XG), scleroglucan (SCLG), schizophyllan (SCP), and guar gum (GG)] and compared to two polyacrylamides [hydrolyzed polyacrylamide (HPAM) and HPAM-AMPS (2-acrylamido-2-methylpropane sulfonic acid)] that serve as benchmarks for EOR processes. All the polymers were evaluated in three different concentrations (100, 500, and 2,000 ppm) in synthetic seawater (3.01% total dissolved solids). The degradation was evaluated through the Ostwald-de Waele indices. The consistency index (K) indicates loss of overall viscosity, and the behavior index (n) accounts for the loss of pseudoplasticity. Overall, the mechanical degradation correlated positively with shear rate and negatively with polymer concentration. When increasing the polymer concentration, the dominant mechanisms at play were macromolecule extension inhibition, caused by interactions with surrounding molecules, and hydrodynamic volume reduction. The biopolymers displayed superior resistance to mechanical degradation than the synthetic ones, with XG being the most resistant polymer. In this work, the main factors for the mechanical degradation resistance of different polymers were rigidity of the polymer structure in solution and the molar mass of the polymer chains.

Synthesis and gelation properties of HPMC-g-poly(AM/AA/APEG2400) quaternary copolymer

To improve the stability of the polymers applied to profile control in high-temperature and high-salinity reservoirs, a water-soluble graft-copolymer HPMC-g-poly(AM/AA/APEG2400) was synthesized from hydroxypropylmethylcellulose (HPMC), acrylamide (AM), acrylic acid (AA), and allyl polyoxyethylene ether (APEG2400) via free-radical copolymerization using potassium persulfate (KPS) as the initiator. The molecular weight (Mw) of HPMC-g-poly(AM/AA/APEG2400) was controlled by the addition of the chain-transfer agent, sodium formate (SF), to the polymerization medium and was measured by capillary viscometry. Fourier transform infrared spectroscopy (FTIR), X-ray diffractometry (XRD), proton nuclear magnetic resonance (1H NMR), and scanning electron microscopy (SEM) were performed to characterize the graft-copolymer. The rheological properties of the graft-copolymer were investigated at different salinities and temperatures. The graft-copolymer solution showed better salt resistance, temperature tolerance, and long-term thermal stability than partially hydrolyzed polyacrylamide (HPAM). In addition, hydrogels were prepared using the graft-copolymer with varying Mw (346 × 104–1319 × 104), a crosslinker (hexamethylenetetramine–resorcinol, (HMTA–RC)), and additives (citric acid, (CA), and ammonium phosphate monobasic, (MAP)), and the hydrogels exhibited adequate strength and tunable gelation time. The hydrogels prepared using the graft-copolymer with high Mw possessed excellent long-term stabilities with negligible syneresis at 45 °C after 130 d, for the same conditions, the syneresis of conventional hydrogels prepared by HPAM reached approximately 90%.

Electrochemical degradation of hydrolyzed polyacrylamide by a novel La-In co-doped PbO2 electrode: Electrode characterization, influencing factors and degradation pathway

• A novel La-In-PbO 2 co-doped electrode was prepared through electrodeposition. • The electrode presents compact pyramidal structure with large surface area. • The modification enhances the oxygen evolution potential and the stability of the electrode. • Hydrolyzed polyacrylamide can be degraded effectively. The anode materials play a key role in the electrochemical oxidation process. In this work, a new type of Ti/Sn-SbO x /α-PbO 2 /La-In-β-PbO 2 electrode has been prepared through electrodeposition and applied to the degradation of high concentration aqueous solution of hydrolyzed polyacrylamide (HPAM). Scanning electron microscopy (SEM), X-ray diffraction (XRD), and Energy-dispersive spectroscopy (EDS) were employed to characterize the surface morphological and structural properties of the electrodes, which indicated that the La-In-PbO 2 electrode had smaller grain size, denser surface and larger active surface area compared with undoped and single-doped PbO 2 electrode. Cyclic voltammetry (CV), linear sweep voltammetry (LSV) and electrochemical impedance spectroscopy (EIS) were also utilized to investigate the electrochemical performance of electrodes. The results showed that the La-In-PbO 2 electrode exhibited higher oxidation peak current, oxygen evolution potential (2.22 V) and lower charge transfer resistance. The La-In-PbO 2 electrodes were used as anode to degrade HPAM solution under different conditions. The results revealed that the viscosity reduction rate of HPAM reached to 97.63 % after 60 min under the condition of electrolyte concentration, initial concentration of HPAM, initial pH and current density were 0.05 M, 3 g·L −1 , 7 and 20 mA·cm −2 , respectively. The kinetic behavior of HPAM degradation was analyzed by the viscosity reduction experiment. The intermediates in the electrochemical oxidation process were identified by GC–MS and the possible degradation mechanism of HPAM was explored by UV–visible absorption spectra and the Fourier Transform Infrared (FT-IR) spectra.

Investigation of alkali and salt resistant copolymer of acrylic acid and N‐vinyl‐2‐pyrrolidinone for medium viscosity oil recovery

AbstractHeavy oil reservoirs, unsuited for thermal applications, are being exploited using chemical enhanced oil recovery (CEOR) techniques. The most widely used polymer in CEOR applications is hydrolyzed polyacrylamide (HPAM). However, it hydrolyzes very rapidly under alkaline conditions, making it susceptible for alkaline polymer flooding, the main variant of chemical EOR techniques. To overcome this shortfall of conventional HPAM, a copolymer P(AA‐co‐VP) of acrylic acid (AA) and N‐vinyl‐2‐pyrrolidinone (NVP) was synthesized, that can offer stability and positive synergism against alkali. In the research presented herein, rheological properties of HPAM and P(AA‐co‐VP) were compared in terms of viscosity and elasticity for typical alkali‐polymer (AP) flood operations. The core flooding experiments were conducted using the heavy oil samples collected from a reservoir in Alberta. The shear rheological and dynamic viscoelastic properties of P(AA‐co‐VP) copolymer improved in presence of strong alkali while the conventional HPAM showed much higher viscosity loss, becoming less effective for AP heavy oil recovery operations. In the presence of alkali, 45.9% and 47.3% incremental recovery factor are shown by HPAM and the newly synthesized P(AA‐co‐VP) copolymer. Although the incremental recovery factor shown by newly synthesized polymer is slightly higher, it resulted in a three times lower residual resistance factor than HPAM. Lower residual resistance factor is important for ensuring good transport properties during polymer flooding. AP flooding conducted using P(AA‐co‐VP) copolymer could effectively overcome the drawbacks of conventional HPAM polymer, thereby improving the heavy oil recovery and transport in porous media.

Adsorption of Hydrolysed Polyacrylamide onto Calcium Carbonate.

Carbonate rock strengthening using chemical techniques is a strategy to prevent excessive fines migration during oil and gas production. We provide herein a study of the adsorption of three types of hydrolysed polyacrylamide (HPAM) of different molecular weight (F3330S, 11–13 MDa; F3530 S, 15–17 MDa; F3630S, 18–20 MDa) onto calcium carbonate (CaCO3) particles via spectrophotometry using a Shimadzu UV-2600 spectrometer. The results are compared to different adsorption isotherms and kinetic models. The Langmuir isotherm shows the highest correlation coefficient (R2 > 0.97) with equilibrium parameters (RL) ranging between 0 and 1 for all three HPAMs, suggesting a favorable monolayer adsorption of HPAM onto CaCO3. The adsorption follows pseudo-second order kinetics, indicating that the interaction of HPAM with CaCO3 is largely dependent on the adsorbate concentration. An adsorption plot reveals that the amount of HPAM adsorbed onto CaCO3 at equilibrium increases with higher polymer molecular weight; the equilibrium adsorbed values for F3330S, F3530S and F3630S are approximately 0.24 mg/m2, 0.31 mg/m2, and 0.43 mg/m2, respectively. Zeta potential analysis shows that CaCO3 has a zeta potential of +12.32 mV, which transitions into negative values upon introducing HPAM. The point of zero charge (PZC) is observed at HPAM dosage between 10 to 30 ppm, in which the pH here lies between 9–10.

A critical analysis on the effects of xanthan gum properties and its derivatives in enhanced oil recovery

Polymer flooding or mobility control techniques that focus on maintaining favorable mobility ratios can be used to improve volumetric sweep efficiency. The development of specialized polymer solutions optimizes the mobility ratio between the injected polymer solution and the oil or water bank being displaced in advance of the polymer. Because of its solid structure, lack of effect of salt on viscosity (unlike partially hydrolyzed polyacrylamide (HPAM), which has a salinity influence on viscosity), and lack of effect of high temperatures, xanthan gum, also known as polysaccharide biopolymer, is the most frequently utilized. This research investigates many properties of xanthan gum, as well as its effectiveness with other polymers and the modifications made to improve its performance.

Treatment technique for wastewater from bauxite flotation and an application for its reuse

During bauxite flotation, flotation indexes decrease with increasing water circulation time, resulting in the discharge of bauxite flotation wastewater as well as a waste of resources and great environmental safety risks. To determine how to return the wastewater back to the flotation process, this study aimed to identify the main components affecting the flotation indexes of flotation wastewater, and coagulation, biological and combined biological-coagulation methods were used to remove the components that affected the production index of wastewater. The results revealed that the accumulation of hydrolyzed polyacrylamide (HPAM) in circulating water reduced the flotation indexes. The combined biological-coagulation method was efficient and consisted of two steps: two-stage biological pretreatment to reduce the stability of HPAM in wastewater followed by coagulation treatment to remove HPAM. At an initial pH of 8, the biological coagulation treatment system stabilized after 4 days of continuous operation, and the treated water was subjected to a flotation test and attained good indexes: the proportion of alumina recovered increased from 62.80% to 68.52%, and the mass ratio of Al2O3 to SiO2 in the tailings decreased from 1.73 to 1.36. These indexes proved the feasibility of reusing the treated water for bauxite flotation. Microbial diversity analysis showed that Labrenzia played an important role in the biological pretreatment, and Gemmobacter, Stappia, Exiguobacterium, Pseudofulvimonas, and Acetoanaerobium played supporting roles. Based on the research results, a prototype reuse technology based on bauxite flotation wastewater treatment was established, and an industrial engineering application was developed through engineering design.