Hydrolyzed Polyacrylamide Polymer Research Articles

Effect of silicon dioxide nanoparticles on the rheology properties of fresh and mechanically degraded hydrolyzed polyacrylamide polymer solutions

AbstractPartially hydrolyzed polyacrylamide is extensively utilized in enhanced oil recovery operations. However, its efficacy is compromised by mechanical degradation during transport through injection lines, valves, and reservoir, which leads to a reduction in the average molecular weight, diminishing the solution's viscosity and viscoelastic properties, critical for efficient oil displacement. In this investigation, we characterized the degree of mechanical degradation in HPAM solutions by evaluating shear and extensional rheological parameters preand post‐degradation. Mechanical degradation was induced by subjecting them to controlled flow through a valve featuring varying degrees of constriction and flow rates. Our results demonstrate a significant reduction in zero‐shear viscosity and high‐strain extensional viscosity of mechanically degraded solutions, with reductions of up to 64%. To mitigate this issue, we explored the incorporation of silica nanoparticles as a potential remedy for mechanical degradation. These nanoparticles strengthen the network structure of HPAM, thereby reducing its susceptibility to mechanical degradation. Our findings reveal that shear and extensional viscosities of mechanically degraded NPs‐HPAM solutions experienced only minimal reductions, dropping to 12% and 0%, respectively. This underscores the effectiveness of the nanoparticle‐enhanced HPAM solutions in preserving viscosity and viscoelasticity under mechanical stress, presenting a promising avenue for improving the robustness of EOR processes.

Synergistic Effect of Opuntia ficus-indica Cladode mucilage on Physicochemical and Rheological properties of HPAM polymer solutions for EOR Application

This study focuses on the synthesis of a series of mixtures of a partially hydrolyzed polyacrylamide (HPAM), noted (H), and a cladode Opuntia ficus-indica mucilage (M). The main objective is to minimize the exclusive dependence of HPAM in the field of tertiary oil recovery, specifically in the process known as EOR.This study showed that a combination of 20% mucilage and 80% HPAM, for a total concentration of 800 ppm in solution, gives rheological performance equivalent to a solution of HPAM alone at 6000 ppm. The resulting mixture which is characterized by viscoelastic liquid behavior, exhibits remarkable flow and elasticity properties.This characteristic is considered favorable for extracting trapped oils from pores under effect of the normal stress. Spectral analysis revealed the presence of silica groups in the mixture, elements widely used in researchers in association with HPAM. Thermogravimetric analysis (TGA) demonstrated that mucilage decomposition only occurs at temperatures above 200 °C. As the main conclusion, all the physicochemical and rheological data argue in favor of the integration of mucilage in HPAM in order to minimize its concentration in Enhanced Oil Recovery (EOR) applications.

Low-Salinity Polymer Flood for Enhanced Oil Recovery in Low-Permeability Carbonates

Summary Low-salinity waterflooding and brine ion modification, in general, can improve displacement efficiency in initially oil-wet reservoirs if it can alter wettability, but it is often a slow process. Polymer flooding usually does not improve displacement efficiency (without significant viscoelasticity) but enhances sweep efficiency. The main objective of this work is to study the synergy between ion modification and polymer flooding for low-permeability carbonate rocks. High-salinity high-temperature reservoirs often need a sulfonated polymer for thermal stability in the high-salinity brine, but a low-salinity water (LSW) injection at that temperature can use a common hydrolyzed polyacrylamide (HPAM) polymer. The second objective of this study is to compare the performance of these two polymer injections. With the proper preparation method, two polymers (HPAM and AN132) with the molecular weight of approximately 6 MDa were successfully injected into the oil-aged carbonate rocks with the absolute permeability of 10–20 md. A low-salinity polymer (LSP) flood was carried out using HPAM prepared in diluted seawater (with added sulfate concentrations). High-salinity polymer (HSP) floods increased the oil recovery in tight cores by 4–5% original oil in place (OOIP) due to higher pressure gradient. Low-salinity corefloods (with added sulfate ions) produced little incremental oil in a few pore volumes (PVs) of injection, but the combination of sulfated low-salinity brine and polymer improved the oil recovery by 8–10% OOIP in less than 1.5 PV. It is shown for the first time that the low-salinity brine with additional sulfate and negatively charged HPAM polymer changed the wettability of the originally oil-wet carbonate rock to water-wet. The synergy between polymer and wettability alteration can recover oil from bypassed pores and shorten the time for oil recovery.

Enhancing ASP Flooding by Using Special Combinations of Surfactants and Starch Nanoparticles.

This study aimed to address the challenges faced by mature oilfields in extracting substantial oil quantities. It focused on improving the efficiency of alkaline-surfactant-polymer (ASP) flooding technique, which is a proven tertiary recovery technology, to overcome scaling issues and other hindrances in its large-scale implementation. Appropriate materials and their suitable concentrations were selected to enhance the ASP flooding technique. Special surfactants from Indonesia were introduced to improve the interfacial tension reduction and wettability alteration. Reservoir rock model that resembling Langgak oilfield in Sumatra was utilized, and low-salinity water was employed to mimic the oilfield conditions. Starches derived from cassava nanoparticles (CSNPs) and purple yam nanoparticles (PYNPs) were combined separately with conventional hydrolyzed polyacrylamide (HPAM) polymer to enhance its performance. Sodium hydroxide and sodium carbonate were used as alkaline in final ASP formula. It was demonstrated from this research that only two combinations of ASP formulations have led to improved oil recovery. One combination utilizing PYNPs resulted in 39.17% progressive recovery, while the other combination incorporating CSNPs achieved 35% incremental oil recovery. The ASP combination that resulted in recovery rate of 39.17% was composed of sodium hydroxide (NaOH) at a concentration of 1.28 wt.%, PSC EOR 2.2 (0.98 wt.%), and a combined polymer consisting of HPAM (0.2 wt.%) and PYNPs nano-starch (0.6 wt.%). The second combination led to 35% recovery rate and involved NaOH also at concentration 1.28 wt.%, PSC HOMF (0.63 wt.%), and a combined polymer comprising from HPAM (0.2 wt.%) and CSNPs nano-starch (0.8 wt.%). These findings of this study highlighted the potential of this modified ASP flooding to enhance oil recovery in mature oilfields, thereby offering valuable insights for oil industry.

Experimental investigation of wettability alteration of oil-wet carbonate surfaces using engineered polymer solutions: The effect of potential determining ions ([Mg2+/ SO42−], and [Ca2+/ SO42−] ratios)

Engineered water polymer flooding (EWPF) is a promising method to improve oil recovery in carbonate reservoirs holding more than half of the world's oil reserves. It involves combining engineered water (EW) and polymer flooding (PF) to modify rock wettability, reduce mobility ratio, promote polymer stability, and lower required polymer concentration. However, limited studies addressed the simultaneous effect of engineered water compositions (i.e. potential determining ions (PDIs)) on the viscosity of polymer and wettability alteration of various carbonate surfaces. Accordingly, this study aimed to investigate the effect of salinity, PDIs, and polymer functional groups (partially hydrolyzed polyacrylamide (HPAM), and acrylamide tertiary butyl sulfonic acid (ATBs)) on the wetting properties of calcite, chalk, and dolomite surfaces as well as the viscosity of solutions at static conditions. The experimental protocol included viscosity, contact angle (CA), pH, and static adsorption tests. Two combinations of PDIs were considered in the study: [Mg2+/SO42−], and [Ca2+/SO42−]. The results revealed that the polymer becomes more tolerant to the salinity as the sulfonation degree increases, given the same molecular weight. However, at a polymer concentration of 5000 ppm, the HPAM polymer showed higher viscosity than the ATBs-based polymers, as the formation brine (FB) was diluted to 100 folds (100DFB). The tendency of shifting the wettability of carbonate surfaces towards a more water-wet state using EW and EWP treatment solutions decreased in the following order: Chalk ≥ Calcite˃ Dolomite. The study also indicates that, the wettability alteration towards favorable condition is dependent on the initial wettability of the carbonate surface. The higher level of oil-wetness detected in aged dolomite, compared with calcite and chalk, resulted in less effectiveness of EWP for dolomites. However, the low polymer interaction with dolomite surfaces indicates a positive impact on reducing polymer consumption. Moreover, the HPAM polymer was more effective in altering the wettability of dolomite towards a water-wet state compared to the ATBs-based polymer. The overall results indicate that ATBs-based polymer is a potential candidate for optimizing the effectiveness of EWPF in carbonates.

Literature Review and Experimental Observations of the Effects of Salinity, Hardness, Lithology, and ATBS Content on HPAM Polymer Retention for the Milne Point Polymer Flood

Summary At the Milne Point polymer flood (North Slope of Alaska), polymer retention is dominated by the clay, illite. Illite, and kaolinite cause no delay in polymer propagation in Milne Point core material, but they reduce the effective polymer concentration and viscosity by a significant amount (e.g., 30%), thus reducing the efficiency of oil displacement until the full injected polymer concentration is regained [which requires several pore volumes (PVs) of throughput]. This work demonstrates that polymer retention on illite is not sensitive to monovalent ion concentration, but it increases significantly with increased divalent cation concentration. The incorporation of a small percentage of acrylamido tertiary butyl sulfonic acid (ATBS) monomers into hydrolyzed polyacrylamide (HPAM) polymers is shown to dramatically reduce retention. The results are discussed in context with previous literature reports. Bridging adsorption was proposed as a viable mechanism to explain our results. Interestingly, an extensive literature review reveals that polymer retention (on sands and sandstones) is typically only modestly sensitive to the presence of oil. Extensive examination of the literature on inaccessible pore volume (IAPV) suggests the parameter was commonly substantially overestimated, especially in rock/sand more permeable than 500 md (which comprises the vast majority of existing field polymer floods).

Polymer Screening for Efficient Water Cut Reduction in a Sandstone Oilfield in Kazakhstan.

Polymer flooding is one of the most widely used and effective enhanced oil recovery techniques. It can improve the macroscopic sweep efficiency of a reservoir by controlling the fractional flow of water. The applicability of polymer flooding for one of the sandstone fields in Kazakhstan was evaluated in this study and polymer screening was carried out to choose the most appropriate polymer among four hydrolyzed polyacrylamide polymer samples. Polymer samples were prepared in Caspian seawater (CSW) and assessed based on rheology, thermal stability, sensitivity to non-ionic materials and oxygen, and static adsorption. All the tests were performed at a reservoir temperature of 63 °C. Based on the results of the screening study, tolerance of a polymer towards high-temperature reservoir conditions, resistance to bacterial activity and dissolved oxygen present in make-up brine, chemical degradation, and reduced adsorption on rock surface were considered the most important screening parameters. As a result of this screening study, one out of four polymers was selected for the target field as it showed a negligible effect of bacterial activity on thermal stability. The results of static adsorption also showed 13-14% lower adsorption of the selected polymer compared to other polymers tested in the study. The results of this study demonstrate important screening criteria to be followed during polymer selection for an oilfield as the polymer should be selected based on not only polymer characteristics but also the polymer interactions with the ionic and non-ionic components of the make-up brine.

Evaluation of ATBS Polymers for Mangala Polymer Flood

Summary Mangala field has been under polymer flood since 2015. The polymer flood has been more successful in accelerating recovery compared to waterflood. As the flood matured, field performance indicated that part of the injected polymer was degrading in the reservoir. Laboratory studies and polymer samples collected from the reservoir suggest that the most likely reason for the degradation is increased hydrolysis due to thermal aging. This degradation compels higher dosing of polymer to make up for the lost viscosity and increases operating costs. Polymer precipitation in the reservoir may also lead to loss of reservoir permeability. Literature surveys and preliminary laboratory studies showed that polymers with acrylamide-tertiary-butyl-sulfonic acid monomer units (referred to as ATBS polymers) could be a suitable option for Mangala. To evaluate the hypothesis, the team did a series of laboratory and coreflood studies. The studies include accelerated thermal ageing, rheology, dynamic adsorption, injectivity, waterflood with fresh and degraded samples, and compatibility studies with topside chemicals. Two hydrolyzed polyacrylamide (HPAM) polymers with different degrees of hydrolysis (DOH) and two ATBS polymers were evaluated. The selected ATBS polymer was then tested for compatibility with surface topside chemicals. The studies show that the classic 20 to 25% DOH HPAM suffers viscosity degradation and possible precipitation in Mangala reservoir conditions. ATBS polymers and a lower DOH HPAM provide superior results to the incumbent HPAM with an acrylamide (AM) (86)-ATBS (14) copolymer providing the best results. ATBS polymers were especially resistant to cloudpoint lowering and provide some superiority in shear degradation. The ATBS monomer was resistant to hydrolysis during the period of testing. Contrary to the published literature, ATBS polymers showed higher adsorption and their propagation through cores required a higher pressure drop. ATBS polymer seemed to plug a low-permeability section of the core stack. All polymers reach their peak viscosity at 30 to 40% hydrolysis and decline sharply after 40%, but viscosity and cloudpoints measured during accelerated aging are possibly conservative. A large-scale pilot of ATBS injection in Mangala is under way to validate the laboratory test results. ATBS polymer can be a suitable polymer for some layers of Mangala with a high residence time and permeability. The choice is driven by the economics of the incremental cost of ATBS for the benefits it offers. In some sands with shorter interwell spacing, a lower DOH HPAM may be a more cost-effective solution. The study results in this paper provide insights to operators to understand the reservoir performance of existing polymer floods and plan for future polymer floods.

Silica Nanoparticles in Xanthan Gum Solutions: Oil Recovery Efficiency in Core Flooding Tests.

Polymer flooding is one of the enhanced oil recovery (EOR) methods that increase the macroscopic efficiency of the flooding process and enhanced crude oil recovery. In this study, the effect of silica nanoparticles (NP-SiO2) in xanthan gum (XG) solutions was investigated through the analysis of efficiency in core flooding tests. First, the viscosity profiles of two polymer solutions, XG biopolymer and synthetic hydrolyzed polyacrylamide (HPAM) polymer, were characterized individually through rheological measurements, with and without salt (NaCl). Both polymer solutions were found suitable for oil recovery at limited temperatures and salinities. Then, nanofluids composed of XG and dispersed NP-SiO2 were studied through rheological tests. The addition of nanoparticles was shown to produce a slight effect on the viscosity of the fluids, which was more remarkable over time. Interfacial tension tests were measured in water-mineral oil systems, without finding an effect on the interfacial properties with the addition of polymer or nanoparticles in the aqueous phase. Finally, three core flooding experiments were conducted using sandstone core plugs and mineral oil. The polymers solutions (XG and HPAM) with 3% NaCl recovered 6.6% and 7.5% of the residual oil from the core, respectively. In contrast, the nanofluid formulation recovered about 13% of the residual oil, which was almost double that of the original XG solution. The nanofluid was therefore more effective at boosting oil recovery in the sandstone core.

Parameter Analysis of Polymer on Sandstone Reservoir in Indonesia: An Experimental Laboratory Study

Polymers are often used to increase oil recovery by improving sweeping efficiency. The screening was carried out as a first step in evaluating the test parameters of several polymers of the Hydrolyzed Polyacrylamide (HPAM) type in fluid and sandstone reservoir rocks. The test was carried out using a reservoir fluid classified as light oil (35°API) and at a reservoir temperature (60°C). The HPAM polymers used are A1, F1, F2, F3, and P1 polymers. The test parameters carried out on these 5 types of polymer (A1, F1, F2, F3 dan P1) include a compatibility test for formation water. The rheology polymer test includes concentration vs Tres, and shear rate vs viscosity which aims to determine the type of polymer solution being tested is a non-Newtonian or pseudoplastic fluid group. Thermal stability test of polymer for 60 days to determine the stability of the polymer solution and whether it is degraded or stable. Filtration testing with criteria FR value 1.2, screen factor test, and adsorption testing using the static method with a standard limit of adsorption value 400 µg/gr and polymer injectivity test. From these tests, scoring (range 0-100) was carried out to determine polymer candidates in polymer flooding testing. The F1 polymer candidate for the sandstone reservoir was obtained with a score of 82.25. From the scoring results, the selected F1 polymer candidate has a concentration value of 2000 ppm. For thermal degradation, the polymer F1 2000 ppm experienced degradation of 15.5%. The results of the F1 2000 ppm polymer static adsorption test were 54.8 µg/gr. With the RRF = 1 value indicating rock permeability after injection of polymer F1 2000 ppm, it tends not to experience plugging due to injection of polymer solution.

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.

Effect of heterogeneity and injection rates on the recovery of oil from conventional sand packs: A simulation approach

The study of flow through porous media has been of cardinal gravity in oil and gas applications like enhanced oil recovery (EOR), acidizing, fracturing, etc. One of the most anticipated apprehensions is that the core flooding and simulation have become prevalent to understand the flow through porous media. This study aims at simulating and analyzing the effect of alkaline surfactant flooding through heterogeneous permeability conditions in the lab-scale methods. The conventional methods of core flood deal with the effective permeability of the system without considering the effect of heterogeneity within the core. The heterogeneous studies are conducted by simulating a finely meshed 2-D axisymmetric model of the sand pack. The novel Karanj oil surfactant extracted from Pongamia Pinnata, and partially hydrolyzed polyacryl amide polymer are considered for the physicochemical properties of displacing fluid used in the simulations. Different heterogeneity combinations and displacing fluid injection flow rates are introduced for a single absolute permeability system. Results indicate a trend of oil recovery upright with increasing vertical permeability. A lower areal sweep efficiency and early breakthrough are observed in models with high horizontal permeabilities. Further, the effect of heterogeneity on oil recovery is reduced with the increase in injection flow rates of displacing fluid. The present work utilizes computational fluid dynamics to model multiphase flow through a heterogeneous permeability media and its effect on oil recovery.

Investigation of Brine pH Effect on the Rheological and Viscoelastic Properties of HPAM Polymer for an Optimized Enhanced Oil Recovery Design.

A novel approach to improve viscous and viscoelastic properties by exploiting the pH and salinity sensitivity of HPAM polymer is proposed in this paper. Polymer flooding is a well-developed and effective enhanced oil recovery technique. The design of the makeup brine is one of the most critical phases of a polymer flood project, since the brine composition, salinity, and pH directly influence the polymer viscosity and viscoelasticity. However, the viscoelastic properties of hydrolyzed polyacrylamide polymers have not been given much consideration during the design phase of polymer flood projects. Our experimental study focuses on the optimization of the makeup water design for polymer flooding by evaluating the optimum solution salinity and pH for better stability and improved viscoelastic behavior of the polymer. Initially, the brine salinity and ionic composition is adjusted and then hydrolyzed polyacrylamide (HPAM) polymer solutions of varying pH are prepared using the adjusted brine. Rheological experiments are conducted over a temperature range of 25–80 °C and at different aging times. Polymer thermal degradation as a function of pH is assessed by examining the solutions at 80 °C for 1 week. Amplitude sweep and frequency sweep tests are performed to determine the viscoelastic properties such as storage modulus, loss modulus, and relaxation time. A 15–40% increase in the polymer solution viscosity and a 20 times increase in relaxation time is observed in the pH range of 8–10 in comparison to the neutral solution. This can be attributed to the low-salinity ion-adjusted environment of the makeup brine and further hydrolysis and increased repulsion of polymer chains in an alkaline environment. These results indicate that the viscoelastic properties of a polymer are tunable and a basic pH is favorable for better synergy between the brine and the polymer. Alkaline low-salinity polymer solutions have exhibited 60% higher thermal stability in comparison to acidic solutions and thus can be successfully applied in high-temperature reservoirs. The results of this study show that polymer solutions with an optimum pH in the basic range exhibit a higher viscoelastic character and an increased resistance toward thermal degradation. Hence, the polymer solution salinity, ionic composition, and pH should be adjusted to obtain maximum oil recovery by the polymer flooding method. Finally, this study shows that more effective polymer solutions can be prepared by adjusting the pH and designing a low-salinity water/polymer recipe to get the additional benefit of polymer viscoelasticity. The optimized low-salinity alkaline conditions can reduce the residual oil saturation by stronger viscous and viscoelastic forces developed by more viscous polymers. The findings of this study can be employed to design an optimum polymer recipe by tuning the brine pH and salinity for maximum incremental oil recovery, particularly in high-temperature and high-salinity formations.

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

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.

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

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.

Effect of Silica Nanoparticles on Polymer Adsorption Reduction on Marcellus Shale.

Polymers play a major role in developing rheology of fracturing fluids for multistage hydraulic fracturing horizontal wells in unconventional reservoirs. Reducing the amount of polymer adsorbed in the shale formation is essential to maintain the polymer efficiency. In this study, the ability of silica nanoparticles to minimize polymer adsorption in Marcellus shale formation at reservoir temperature was investigated. Partially hydrolyzed polyacrylamide polymers of varying molecular weights (1–12 MD), salinities (2500–50,000 ppm), polymer concentrations (100–2000 ppm), and silica nanoparticle concentrations (0.01–0.1 w/w) were used in the static adsorption experiments. Adsorption of the polymer in the Marcellus shale samples was contrasted with and without the silica nanoparticles at a Marcellus formation reservoir temperature of 65 °C, showing a significant polymer adsorption reduction of up to 50%. The adsorption and adsorption reduction were more sensitive to the variation of the polymer concentration than to the variation of the salinity within the tested conditions. The highest adsorptions were reported at the higher molecular weight of 10–12 MD. In addition, silica nanoparticles significantly improved polymer rheology at elevated temperatures. The results indicate that nanoparticles can play a significant role in reducing polymer adsorption in the fracturing fluid and improve its rheological properties and its efficiency, which will reduce the number of issues caused by the polymers in the fracturing fluid and making it more cost effective.

Defining the optimum sequence in addition of shale inhibitor agents in WBDF considering inhibition of swelling of cuttings

• We proposed and optimized sequence addition of shale inhibitive agents to WBDF. • Inhibitive behavior of WBDF classified to low, med and high, based on performance. • We have shown shale inhibitor agents should be added before rheological additives • Asphasol and polyglycol better to be added as late additives in low temperature WBDF. • PHPA, bentonite should be added before KCl, PAC and XC polymer in mud preparation. Shale swelling inhibition property in water-based drilling fluid (WBDF) is an important issue in drilling fluid engineering. Against the importance of chemical compounds used to give this property to the drilling fluid, sequence of adding those additives is also much of concern. In the presented study, we propose an optimized sequence of additives in the formulation of a standard WBDF. In the formulation, potassium chloride (KCl), partially hydrolyzed polyacrylamide polymer (PHPA), and polyglycol are used as major shale inhibitors. Therefor, 23 drilling fluid samples with variation in sequences of adding additives were experimented. Then 16 different WBDF samples were produced through changing the position of KCl, PHPA, bentonite and polyglycol and more 6 drilling fluids were prepared by simultaneous change in the position of PHPA, bentonite and KCl. Also, one oil-based drilling fluid (OBDF) was also produced and experimented against shale inhibition for performance comparison. Analyzing of swelling curves of all these drilling fluids revealed three different behaviors of them in shale inhibition. Then after, the optimized sequence of adding the shale inhibitors was defined according to the best observed performance of all experimented fluids. It should be noted that the presented study only focuses on the inhibition of swelling of cuttings and not on the dispersion of cuttings.

Dependence of intrinsic viscosity and molecular size on molecular weight of partially hydrolyzed polyacrylamide

AbstractAs a typical water‐soluble polymer, ultra‐high molecular weight (UHMW) partially hydrolyzed polyacrylamide (HPAM) has been widely used in various industries as thickeners or rheology modifiers. However, precise determination of its critical physical parameters such as molecular weight, radius of gyration (Rg) and hydrodynamic radius (Rh) were less documented due to their high viscosity in aqueous solution. In this work, the molecular structure of five UHMW‐HPAM samples with different MW was elucidated by 1H and 13C NMR spectroscopy, and their solution properties were characterized by both static and dynamic light scattering. It is found that all the second virial coefficient (A2) values are positive and approaching zero, indicating of a good solvent of 0.5 M NaCl for UHMW‐HPAM. The weight‐average molecular weight (Mw) dependence of molecular size and intrinsic viscosity [η] for these series of HPAM polymers with MW ranging from 4.81 to 15.4 × 106 g·mol−1 can be correlated as Rg = 3.52 × 10−2Mw0.51, Rh = 1.97 × 10−2Mw0.51, and [η] = 6.98 × 10−4 Mw0.91, respectively. These results are helpful in understanding the relationship between molecular weight and coil size of HPAM polymers in solution, and offer references for quick estimation of molecular weight and screening of commercial UHMW‐HPAM polymers for specific end‐users.