Partially Hydrolyzed Polyacrylamide Research Articles

Impact assessment of polymer, cross-linker, and nanoparticles on gelation kinetics and properties of silica nanocomposite hydrogel for water shut-off treatment in harsh reservoir conditions

The study presented the impacts of various parameters like compositional combinations of PHPA (partially hydrolyzed polyacrylamide), organic cross-linker (hydroquinone-HQ and hexamethylenetetramine-HX), and silica nanoparticles (SNP) in addition to the degree of hydrolysis and molecular weight of PHPA on the efficacy of hydrogel for water shut-off jobs. The investigation indicated that the gelation time, gel strength of the gel, tolerance against salinity, and temperature were tuned as required by the field conditions by changing the variables mentioned above. The gelation time was found to vary inversely with the concentration of polymer, cross-linkers, and silica nanoparticles, whereas the gel strength and temperature tolerance followed the reverse trend. SNP was observed to control the gel properties significantly, even at the lower polymer and cross-linker compositions, as evidenced by the stronger network in FESEM, rheological, and other related properties. The hydrogels prepared with the PHPA-LM (low molecular wt) and PHPA-HM (high molecular wt) polymers and HX-HQ cross-linkers showed improved temperature tolerance from 126.49 °C to 131.78 °C and 99.88 °C to 164.34 °C, respectively when improvised with SNP. The gel’s microstructure (FE-SEM image) exhibited significant silica nanoparticle aggregation and evenly distributed compact three-dimensional network structure. The prepared nanohydrogel with optimized composition maintained its stability even at a salinity of 60000 ppm and 120 °C for more than two years. Sand-pack flooding with the nanohydrogel proved very effective, with a permeability reduction of ∼ 90 %. Thus, the prepared nano-hydrogel could be effectively used for high temperature and high salinity conditions with preferred resistance to water flow.

How does the presence of an oleic phase influence salt transport during polymer-enhanced low-salinity waterflooding?

Our preceding single-phase experiments demonstrated that polymer enhanced low-salinity waterflooding (PELS) can significantly reduce salt dispersion and improves low-salinity waterflooding (LSWF) performance. In this paper, we extended the research to two-phase fluid flow conditions in the presence of an oleic phase. To assess this quantitatively, a series of two-phase coreflooding experiments using artificial cores were conducted. To eliminate the impact of fluid–fluid and rock–fluid interactions associated with LSWF on salt dispersion, a model, non-polar oleic phase was chosen. The salinity breakthrough results of two-phase corefloods were interpreted using a non-Fickian model based on the Mobile-Immobile Model to infer salt dispersion coefficient. The impact of Partially-Hydrolyzed Polyacrylamide (HPAM) concentration, injection rate, salinity difference, and flooding mode (secondary or tertiary) on salt transport and dispersion through porous media were studied. The results revealed an increase in the salt dispersion coefficient under two-phase conditions by as much as sixfold; taking significantly larger times to displace the high salinity brine. Thus, the optimal HPAM concentration required to effectively suppress mixing was found to be twice (∼400 ppm) as much under the single-phase flow. Reduction of salinity difference also resulted in the reduction of the salt dispersion coefficient by 32%. Moreover, it was observed that in tertiary mode injection where the starting water saturation of the core is higher due to a prior high salinity flooding, the salt dispersion can be increased by more than 21%. These new two-phase results and insights support the possibility of mixing-control under two-phase condition by using PELS and provides a solution to facilitate field implementation.

Iron Stress Testing of Oilfield Produced Waters and Hydraulic Fracturing Fluids in the Bakken

Friction reducers are a major additive in almost all water-based hydraulic fracturing fluids. Despite the important role they play in friction reduction during hydraulic fracturing, they pose a veritable threat to the permeability of tight reservoirs upon precipitation. In the industry today, the potential for such precipitation is seldom assessed and as a result, an additional contributor to the formation damage problem has been given little attention. In this work, the sensitivity and affinity of friction reducers to very low concentrations of ferric ions are exploited to provide a qualitative assessment of their propensity to precipitate in hydraulically fractured hydrocarbon reservoirs. Representative samples of produced water and a routinely utilized hydraulic fracturing fluid recipe were spiked with 50ppm Iron (III) trichloride and incubated for 24 hours in a water bath at 200 degrees Fahrenheit. The results showed that precipitation of friction reducers in fracturing fluid is highly likely at low concentrations of ferric ions. This precipitate formed turned from yellow to brown color over time upon heating. The test showed presence of fragmented/unfragmented Partially Hydrolyzed Polyacrylamide (PHPAM) in the produced water, with varying degrees of FR gel precipitation depending on the processing treatment given to the water used for hydraulic fracturing. Evidence for the presence of partially hydrolyzed polyacrylamide was demonstrated in one of the produced waters while the rest did not produce any discernable precipitates. The results indicate that formations with lower iron concentrations may be more vulnerable to Fe3+-PHPAM precipitation than those with higher ferric ion concentration. Therefore, to mitigate formation damage through precipitation of FRs during hydraulic fracturing, a routine iron stress test like the one described herein is required on both hydraulic fracturing fluid and produced water to determine the vulnerability of the reservoir to formation damage by fragmented/unfragmented anionic PHPAMs.

Influence of coal fly ash on the PPG properties and plugging ability in carbonate rocks for conformance control of oil reservoirs

The operation of explored reservoirs has become necessary due to the difficulty in achieving new and economically viable oil fields. However, the injected recovery fluids may flow on preferential paths in some heterogeneous reservoir rocks, which decreases the oil production efficiency. To avoid these problems, conformance control techniques have been used to optimize reservoir sweep. This process works redirecting the injected fluids to the lower permeability segments, which increase the sweep efficiency. In recent years, several studies of preformed particle gel (PPG) have been performed to reduce reservoir heterogeneity and enhance oil recovery. In this work, PPGs constituted by the partially hydrolyzed polyacrylamide (PHPA) crosslinked with polyethyleneimine (PEI), containing coal fly ash (CFA), were evaluated. The results indicated that the presence of CFA in PPGs enhanced elasticity, stability, and resistance to thermal degradation. The PPG injection into carbonate rock reduced core permeability by 96.78%, indicating their promising applications in oil reservoir conformance control.

Experimental studies on effectiveness of graphene oxide nanosheets dispersion in water/aqueous PHPA for enhanced oil recovery

Nanoparticle application in enhanced oil recovery is emerging as a novel technology because of their unique characteristics, viz. reduction of IFT, wettability alteration, and stable dispersion in injection water and aqueous polymer solution. In the present study, graphene oxide nanosheets (GONs) are synthesized by modified Hummer's method. The nanosheets are characterized by FTIR, XRD and UV–vis spectroscopy analysis. The size of the nanosheets was confirmed by the AFM and HR-TEM imaging. The stability of nanofluid (NF) with dispersed GONs in the aqueous solution was confirmed by Turbiscan stability analysis, DLS studies and zeta-potential values (less than −34 mV). The experimental research reveals that NF alters the wettability of intermediate oil-wet sandstone reservoir rock with a reduction of contact angle from 112.4° to 17.2°. Further, it is observed that the IFT between oil (decane) and deionized water decreases from 42.34 mN/m to 32.76 mN/m for the NF system. It has been observed that the synthesized GONs can emulsify crude oil, which is also an important mechanism of EOR. The rheological studies show that GONs enhance the viscosity and viscoelastic properties of partially hydrolyzed polyacrylamide (PHPA) polymer. GONs form a robust three-dimensional network structure facilitated by hydrogen bonding with the PHPA polymer chain, which leads to the improvement of sweep efficiency. The core flooding experiment demonstrates that the incremental oil recovery over the conventional water flooding by GONs dispersed in the PHPA polymer with flooding is significantly higher (26% of original oil in place) than that of individual NF and polymer flooding.

Rock-on-a-chip: "Seeing" the association/disassociation of an adaptive polymer in solutions flowing through porous media.

The flow and transport of polymer solutions through porous media are ubiquitous in myriad scientific and engineering applications. With escalating interest in adaptive polymers, understanding the flow dynamics of their solutions is indispensable (yet lacking). Here, the hydrophobic-effect-driven reversible associations in a self-adaptive polymer (SAP) solution and its flow characteristics in a microfluidic-based "rock-on-a-chip" device have been analyzed. The hydrophobic aggregates were fluorescent labeled; this enabled a direct visualization of the in situ association/disassociation of the polymer supramolecular assemblies in pore spaces and throats. Furthermore, the influence of this adaptation on the macroscopic flow behavior of the SAP solution was analyzed by comparing its flow with that of two partially-hydrolyzed polyacrylamide (the molecular weight (MW)-equivalent HPAM-1 and ultrahigh-MW HPAM-2) solutions in the semi-dilute regime with similar initial viscosities. At low flow rates (with shear predominance), the SAP solution showed a low shear viscosity compared to HPAM-1, indicating a higher shear susceptibility for association than chain entanglement. Although the SAP exhibited the same elastic instability as the non-adaptive polymers above a threshold flow rate, the adaptable structure of the former advanced the onset of its viscoelastic-governed flow, providing a stronger flow resistance, possibly through an extension resistance. Furthermore, 3D-media analysis indicated that the reversible association/disassociation of SAP increased the accessible pore space during nonaqueous-liquid displacement, facilitating oil production.

Mercury(II) and lead(II) ions removal using a novel thiol-rich hydrogel adsorbent; PHPAm/Fe3O4@SiO2-SH polymer nanocomposite.

The abundant release of toxic heavy metals into wastewater has been a serious threat to human health, aquatic environments, plants, and animals; thus, it is critical to purify wastewater of these pollutants through a proper treatment process. A novel hydrogel compound was synthesized using partially hydrolyzed polyacrylamide (PHPAm) and functionalized Fe3O4-coated magnetic nanoparticles (PHPAm/Fe3O4@SiO2-SH) that is efficient in removal of mercury and lead from wastewater. This new magnetic nanoadsorbent is characterized using scanning electron microscope, Fourier-transform infrared, thermogravimetric analysis, vibrating sample magnetometer, and energy-dispersive X-ray analysis. The central composite design under response surface methodology (CCD-RSM) was applied in designing the experiments to optimize the main parameters affecting the adsorption capacity: initial concentration (77.50 mg L-1), pH (6.11 and 6.48), adsorbent dosage (25 mg), and contact time (115 and 106 min) for both Hg2+ and Pb2+ adsorption, respectively. Quadratic models were used for variable predictions and analysis of variance was applied to evaluate the statistical parameters and investigate the interactions of the variables. The high determination coefficient (R2 0.99) for both metals indicates a good correlation between actual and predicted response values. Additionally, thermodynamic modeling showed an endothermic and exothermic for Hg2+ and Pb2+, respectively, and also the spontaneous nature of both metals' adsorption process within the temperature range of 288-318 K. Mercury and lead kinetic studies were in agreement with pseudo-second-order modeling, and the equilibrium results revealed that the Langmuir isotherm best fit the experimental data with maximum adsorption capacities of 256.41 and 227.27 (mg g-1) for Hg2+ and Pb2+, respectively. Overall, PHPAm/Fe3O4@SiO2-SH is thought to have highly promising potential for investigating heavy metals in wastewater treatment, and will make important contributions to similar studies that may be conducted in the future.

Effects of nanoparticles, polymer and accelerator concentrations, and salinity on gelation behavior of polymer gel systems for water shut-off jobs in oil reservoirs

Excess water production is one of the crucial complications in the oil industry, leading to a rapid decline in oil production. To overcome this problem, different polymer gels are used to block the water's path to reduce water production. In the present work, polymer gel systems were prepared with polymers namely partially hydrolyzed polyacrylamide (PHPA), organic crosslinkers like hexamine, and hydroquinone with the incorporation of silica and alumina nanoparticles. Nanoparticles are used to enhance the stability of the gel framework in high salinity and high temperature reservoir environment. When designing the polymer gel system, factors such as pH, thermal stability, brine composition, injection rate, and chemical concentration were considered. Concentrations of PHPA and nanoparticles were varied from 1 to 2 wt% and 0.25–1.0 wt% respectively for the preparation of different gel systems. The concentration of the organic crosslinker was extended from 5000 to 11000 ppm for investigating the effect on gelation time. Brine concentration was chosen from 2 to 8 wt% to find the impact of high salinity. Succinic acid as an accelerator was also used to study the effect on gelation time, and it was found that the gelation time is reduced as the concentration of succinic acid increases. The prepared polymer solution was taken in a test tube and was kept inside a hot air oven at 95 °C to perceive the gelation time and nature of the produced gel. Results showed that nanoparticles do not influence the gelation time, but they considerably affect gel stability. However, concentrations of polymer, accelerator, and salt (salinity) have significant effects on the gelation behavior of the gel systems.

Eco-friendly poly(vinyl alcohol)/partially hydrolyzed polyacrylamide/graphene oxide semi-IPN nanocomposite hydrogel as a reusable and efficient adsorbent of cationic dye methylene blue from water

Eco-friendly semi-interpenetrating polymer network (IPN) nanocomposite hydrogels composed of poly(vinyl alcohol) (PVA) chains and graphene oxide (GO) nanosheets embedded within the cross-linked partially hydrolyzed polyacrylamide (PHPAm) network were prepared in a one-stage approach via the internal ionic gelation in an aqueous solution. After full characterizations by various techniques, optimization of the hydrogel synthesis reaction condition based on the equilibrium swelling ratio criterion was performed by using Taguchi standard method. The performance of the prepared PVA/PHPAm/GO semi-IPN nanocomposite hydrogel as methylene blue (MB) adsorbent was evaluated by treating aqueous solutions in batch mode and kinetic models and isothermal models were used to describe the adsorption mechanism. The experimental results indicated that the incorporation of GO in the semi-IPN nanocomposite formulation enhanced the thermal stability, swelling ability and (MB) removal efficiency by 49% compared to empty hydrogels. Adsorption kinetics and equilibrium adsorption isotherm fitted the pseudo-second-order kinetic model and Langmuir isotherm model well, respectively. Moreover, the prepared semi-IPN hydrogel had good stability and reusability as it exhibited excellent removal efficiency of 70% after five consecutive adsorption-desorption cycles. The maximum adsorption capacity calculated from the Langmuir isotherm model reached qmax = 714.8 mg.g−1 at 30°C, obviously higher than the hydrogel prepared without this addition (293.8 mg.g−1). According to the calculated thermodynamic parameters ΔG°, ΔH°, and ΔS°, MB adsorption onto the adsorbent was a spontaneous, endothermic, and physical adsorption process.

Design and Evaluation of a Polymer Support Fluid in a Soil-Rock Mixture.

Soil–rock mixtures are commonly encountered in the construction of bored piles. Conventional bentonite support fluids have disadvantages, such as more significant environmental impacts, more complex mixing, bigger site footprint, weaker foundation performance, and overall low economies. The present study conducted a comprehensive investigation of partially hydrolyzed polyacrylamide (PHPA) polymer fluids, an alternative to bentonite ones, to drill into a soil-limestone mixture. The fluid flow pattern, aging behavior, and the influence of finer silty clay on polymer fluid were explored. The test results showed that polymer fluids were reasonably well fitted to the power-law model and were a good alternative to the conventional bentonite ones. In terms of their aging behavior, the remaining active viscosity of the polymer was at least 70% after a prolonged aging time of up to 30 days, showing the effective on-site use of polymer fluids. The mixing of silty clay significantly reduced the apparent viscosity of polymer fluids, with 10% silty clay causing a viscosity reduction of 76%, indicating the importance of fluid control in drilling these materials. A polymer formula, water + 0.08%PHPA + 0.1~0.5%Na2CO3, was proposed and was verified by drilling into a soil–limestone mixture. The polymer fluids led to small radial displacements around the boreholes with a high drilling quality. This work would be helpful for consultants and contractors designing and constructing bored piles in soil and rock mixtures utilizing polymer fluids.

Preliminary evaluation of a natural surfactant extracted from Myrtus communis plant for enhancing oil recovery from carbonate oil reservoirs

Surfactants are among the materials used to improve water properties for injection into oil reservoirs, and reduce injection phase and crude oil interfacial tension (IFT). Recently, the interest in the use of natural surfactants has increased and is constantly on the rise to solve some challenges of using chemical surfactants such as incompatibility with the environment and the high cost. In this study, we have used aqueous extract of powdered leaf of Myrtus communis as an available source of natural surfactant. The extracted surfactant was characterized by TGA, 1H NMR and FTIR techniques. The surfactant efficiency was demonstrated by performing some experiments including IFT and injection of chemical slug and surfactant into carbonate plugs. The surfactant adsorption on carbonate rock was also studied. It was observed that this natural surfactant can reduce IFT to 0.861 mN/m at surfactant critical micelle concentration (CMC) of 5000 ppm. This minimum IFT was further reduced at optimum salinity and alkali. Finally, an increase of 14.3% oil recovery by surfactant flooding and 16.4% oil recovery by ASP slug injection containing NaOH alkali and partially hydrolyzed polyacrylamide (PHPA) polymer with 0.5 PV volume from carbonate plugs was achieved.

A comparative study on enhancing oil recovery with partially hydrolyzed polyacrylamide: Emulsion versus powder

AbstractIn China, powders of partially hydrolyzed polyacrylamide (P‐HPAM) have been extensively used in chemically enhanced oil recovery (cEOR) processes. However, the relatively longer dissolution time of P‐HPAM and high investment in surface facilities diminish the profit. Here, we compared the properties between P‐HPAM and emulsion HPAM (E‐HPAM) with similar molecular weight of 1.5 × 107 g/mol at polymer concentration of 1000 mg/L under a simulated Daqing Oilfield reservoir. We found only 20 min was needed to completely dissolve E‐HPAM, 75% less time than for P‐HPAM. The apparent viscosity of E‐HPAM reached 69.6 mPa · s, 26% higher than that of P‐HPAM. Sheared at 7000 rpm for 30 s, 73.8% viscosity retention was maintained for E‐HPAM solution, 13.7% higher than that of P‐HPAM solution. After 90 days of thermal aging, E‐HPAM solution had 72.8% viscosity retention, 15.2% higher than P‐HPAM. After being adsorbed in a sand package, E‐HPAM and P‐HPAM solutions had 87.0% and 83.2% viscosity retention, respectively. The interfacial tension (IFT) between E‐HPAM solution and Daqing oil could reach 15.3 mN/m, 75.1% lower than that of the P‐HPAM solution with Daqing oil. After 1.2 PV of polymer solution was injected, E‐HPAM solution got an oil recovery factor of 24.1% (OOIP), 10.0% higher than that of P‐HPAM under identical conditions. Both polymer solutions could propagate smoothly in porous media without plugging. In the field trial of 63 wells, after 0.098 PV of E‐HPAM solution was injected within nine months, the injection pressure increased by 1.3 MPa, and an interim recovery factor of 0.58% was obtained.

Improving the Viscosity of Partially Hydrolyzed Polyacrylamide (PHPAM) Solution for Enhanced Oil Recovery (EOR) Application

Enhanced Oil Recovery (EOR) is a promising technology for increasing crude oil production, especially from old wells. Polymer flooding is one of the techniques used in EOR in which the water-soluble polymer is added to increase the viscosity of the injected fluid. However, this technique has not been implemented in Indonesia due to the unavailability of locally-synthesized polymers. Therefore, this research aims to synthesize polyacrylamides and their partially-hydrolyzed derivatives and to study the possibility of their utilization for the EOR application. Various polymerization conditions using potassium persulfate (KPS) as initiators have been realized and the resulting polymers were characterized using FTIR spectroscopy and rheology measurement. It was found that higher monomer concentration resulted in higher viscosity-average molecular weight of polyacrylamide. Further study revealed that the hydrolysis of polyacrylamide by alkaline solution significantly increased the viscosity of 1000 ppm solution from 1.5 to 145.40 cP at room temperature, which is comparable to one of the commercial products. These results showed that the simple synthesis and hydrolysis method could be effectively used to produce water-soluble polymers for the EOR application.

Polymer viscosifier systems with potential application for enhanced oil recovery: a review

Due to the growing demand for oil and the large number of mature oil fields, Enhanced Oil Recovery (EOR) techniques are increasingly used to increase the oil recovery factor. Among the chemical methods, the use of polymers stands out to increase the viscosity of the injection fluid and harmonize the advance of this fluid in the reservoir to provide greater sweep efficiency. Synthetic polymers based on acrylamide are widely used for EOR, with Partially Hydrolyzed Polyacrylamide (PHPA) being used the most. However, this polymer has low stability under harsh reservoir conditions (High Temperature and Salinity – HTHS). In order to improve the sweep efficiency of polymeric fluids under these conditions, Hydrophobically Modified Associative Polymers (HMAPs) and Thermo-Viscosifying Polymers (TVPs) are being developed. HMAPs contain small amounts of hydrophobic groups in their water-soluble polymeric chains, and above the Critical Association Concentration (CAC), form hydrophobic microdomains that increase the viscosity of the polymer solution. TVPs contain blocks or thermosensitive grafts that self-assemble and form microdomains, substantially increasing the solution’s viscosity. The performance of these systems is strongly influenced by the chemical group inserted in their structures, polymer concentration, salinity and temperature, among other factors. Furthermore, the application of nanoparticles is being investigated to improve the performance of injection polymers applied in EOR. In general, these systems have excellent thermal stability and salinity tolerance along with high viscosity, and therefore increase the oil recovery factor. Thus, these systems can be considered promising agents for enhanced oil recovery applications under harsh conditions, such as high salinity and temperature. Moreover, stands out the use of genetic programming and artificial intelligence to estimate important parameters for reservoir engineering, process improvement, and optimize polymer flooding in enhanced oil recovery.

Mathematical regression models for rheological behavior of interaction between polymer-surfactant binary mixtures and electrolytes

The characterization of the rheological behaviors of polymer-surfactant binary mixtures is important in several applications and industrial processes. In this paper, rheological behaviors of partially hydrolyzed polyacrylamide (PHPAM) polymer and sodium dodecyl sulfate (SDS) surfactant solutions have been investigated through viscosity measurement and then mathematical regression modeling. The effects of salt (CaCl2) and alkali (NaOH) on the viscosities of these polymer-surfactant solutions have also been experimentally investigated and theoretically modeled. All polymer-surfactant systems are found to exhibit shear-thinning non-Newtonian behavior. The experimental investigations revealed that addition of salt extensively reduced the viscosity of polymer-surfactant solutions by reducing the hydrodynamic size of polymer and this peculiar effect has been explained in terms of electrical double layer (EDL). The non-Newtonian polymer-surfactant solutions became almost Newtonian when the concentration of CaCl2 exceeded some threshold value (≥4.5 × 10−2 mol.L−1 or 0.5 wt%). Presence of NaOH also reduced the viscosity significantly and explained using the theory of molecular dynamics. The Herschel–Bulkley power law model through mathematical regression fitting procedure has been used to estimate the yield stress (τ 0), the consistency index (k) and the flow behavior exponent (n) and analyze the rheology results.

Evaluation of polymer/bentonite synergy on the properties of aqueous drilling fluids for high-temperature and high-pressure oil wells

The increasing demand for energy sources has led to oil field exploration under inhospitable conditions, where non-aqueous drilling fluids are commonly used due their physical and chemical stability. However, they exhibit a number of environmental constraints and the cuttings produced require expensive treatments before disposal. Aqueous drilling fluids are currently less thermally resistant and generally entail the use of chromium lignosulfonate as clay dispersant, which provides stability to rheological properties and filtration control under high temperature and high pressure (HTHP). This study elucidates the role played by synergic effect of a novel eco-friendly high-performance water-based drilling fluid using bentonite and vinyl polymers (polyvinylpyrrolidone (PVP) and partially hydrolyzed polyacrylamide (PHPA)) as the main constituents. Filtration and rheological properties of the drilling fluids were determined on a HTHP filtration system and on a rotational viscometer, respectively. Systems using high molar mass PVP (HMM PVP) showed higher values for viscosity, gel strength and yield stress, due to promotion of flocculation. On the other hand, dispersed systems were obtained using low molar mass PVP (LMM PVP), through ion-dipole interactions between PVP and clay particles. Dispersed systems provided stable rheological parameters over the entire range of temperature and pressure studied (up to around 120 °C and 3450 kPa). Linear clay swelling tests showed that LMM PVP and water had similar profiles, promoting clay dispersion. Profitable low filtrate volumes (12 mL) were obtained for PVP-based drilling fluids in conditions where non-aqueous fluids are currently applied.

Synergistic application of polypropylene and silica nanoparticle modified by (3-Aminopropyl) triethoxysilane for cuttings transport

Achieving the desired efficiency in cuttings transport has always been a challenge during drilling situations due to complex wellbore trajectories and drilling hydraulics. These issues require suitable additives to formulate the drilling muds. Hence, nanocomposite (NC) particles formed from silica and polypropylene was modified by (3-Aminopropyl) triethoxysilane (termed PP-SiO2 NC-NH2) and the impact of the concentrations of the PP-SiO2 NC-NH2 between 0.4 and 1.2 ppb on the cuttings transport efficiency (CTE) of complex water-based mud (WBM) system was assessed. Mud system containing 0.5 ppb PP-SiO2 NC-NH2 on CTE was measured and compared with that of partially hydrolyzed polyacrylamide (PHPA) using sandstone grains of diameters between 0.50 and 3.20 mm at hole angles 0, 30, 45, 60, and 90° with a 42 L/min pump rate. The zeta potential (ζ-potential), particle size distribution, morphology, and temperature resistance of the NC were examined. The ζ-potential data revealed the stability and the long-term stabilization of the modified NC in drilling muds. By adding the concentration of the modified NC into the WBM system, the thinning characteristics and consistency factors were enhanced as the NC concentration increases. Furthermore, the rheological test program reveals that the NC concentrations and 0.5 ppb PHPA increased the shear stress of the WBM with an increase in the shear rate. However, the mud system of PHPA exhibited a larger viscosity, while the NC samples showed a flat viscosity-profile. Also, the NC demonstrated better cuttings recovery than the PHPA product at 0.5 ppb concentration, especially at the worst hole angle of 45°. The cuttings recovery from a minimum to a maximum was found to occur in this order; 45°, 60°, 30°, 90°, and 0°. In contrast with the smallest and intermediate sand grains, the largest grains have complex and less fluid transport. With a pipe orbital motion of 150 rpm and a pump rate of 42 L/min, the CTE of the muds showed higher improvement. Overall, the mud properties of the modified NC exhibited a strong enhancing impact on the cuttings carrying capacity of the base mud than the PHPA.

Characterization and evaluation of a natural surfactant extracted from Soapwort plant for alkali-surfactant-polymer (ASP) slug injection into sandstone oil reservoirs

Different types of surfactants are used in the chemical water flooding process in oil reservoirs with the aim of water-oil interfacial tension (IFT) reduction. Recently, much attention is paid to the use of natural surfactants such as plant extracts in enhanced oil recovery (EOR) process. However, some characteristics of these surfactants, such as their efficiencies in achieving the appropriate values of IFT, adaptability to different salinities and their temperature stability at reservoir conditions, must be acceptable. In the current work, a non-ionic surfactant was extracted from Soapwort plant under ultrasonic extraction and saponin purification processes. Proton Nuclear Magnetic Resonance (1HNMR), Fourier Transform Infrared Spectroscopy (FTIR) and Thermal Gravimetric Analysis (TGA) techniques were used to investigate the natural surfactant characteristics. The pendant drop surface tension tests were used to estimate the critical micelle concentration (CMC) of this natural surfactant. Finally, the application of the surfactant in the EOR process was demonstrated using the experiments of water-oil IFT, contact angle and alkali-surfactant-polymer (ASP) slug injection. The effects of different salinities on surfactant performance in reducing interfacial tension and contact angle were also investigated. Based on the results, the CMC of the surfactant was obtained at 2250 ppm and at 80 °C. The water-oil IFT at surfactant CMC was 0.832 mN/m, which decreased by 0.541, 0.714 and 0.775 mN/m at the optimal salinity of the diluted formation water, MgCl2 and NaCl solutions, respectively. The IFT was decreased by 0.047, 0.078 and 0.096 mN/m at the optimal concentration of NaOH, Na2CO3 and NaHCO3 alkalis, respectively. Sandstone wettability was altered from hydrophobicity to hydrophilicity by surfactant solution at CMC and the contact angle was decreased from 124.42° to 45.94°. The contact angle at CMC was decreased by 35.12°, 38.44° and 43.62° at the optimal concentration of FW, MgCl2 and NaCl, respectively and eventually, oil recovery was achieved by 32.1% by tertiary ASP slug injection containing surfactant at CMC, optimal saline, optimal NaOH alkali concentration and 1000 ppm of partially hydrolyzed polyacrylamide (PHPA). Surfactants are used in various applications in the oil industry. The focus of this study was on the use of the plant surfactant in EOR by ASP injection process. However, other applications of this surfactant for injection in various scenarios based on chemical water in EOR process can be developed.

COMPARATIVE ANALYSIS OF CARBOXYMETHYL CELLULOSE AND PARTIALLY HYDROLYZED POLYACRYLAMIDE – LOW-SOLID NONDISPERSED DRILLING MUD WITH RESPECT TO PROPER-TY ENHANCEMENT AND SHALE INHIBITION

During drilling, different problems are encountered that can interfere with smooth drilling processes, including the accumulation of cuttings, reduced penetration rates, pipe sticking, loss of wellbore stability, and loss of circulation. These problems are generally encountered with conventional drilling mud, such as the bentonite–barite mud system. Formation damage is the most common problem encountered in bentonite mud systems with high solid content. In this work, we aimed to formulate two low-solid nondispersed (LSND) muds: carboxymethyl cellulose (CMC)–LSND mud and partially hydrolyzed polyacrylamide (PHPA)–LSND mud. A comparative analysis was performed to evaluate their property enhancements. LSND muds aid in maintaining hole stability and proper cutting removal. The results of this work show that the addition of both CMC and PHPA helps to improve drilling fluid properties; however, the PHPA–LSND mud was found to be superior. Shale swelling is a major concern in the petroleum industry, as it causes various other problems, such as pipe sticking, low penetration rates, and bit wear. The effect of these two LSND polymer muds in inhibiting shale swelling was analyzed using shale collected from the Champhai district of Mizoram, India.

Enhanced cuttings transport efficiency of water-based muds using (3–Aminopropyl) triethoxysilane on polypropylene-nanosilica composite

The lifting of cuttings has been a challenging phenomenon in the petroleum industry for a long period, given the complexity of different cuttings types and their high tendency to gravitate to the low side of the hole. Although many additives have been applied to improve the efficiency of water-based muds (WBMs) for cuttings transport, only a few success was recorded in the application of these additives once evaluated under different field situations. In this study, a new WBM formulated by nanocomposites was proposed to lift cuttings out of the annulus during drilling. Series of characterization, rheological, filtration loss, and cuttings transport tests were performed on the drilling muds formulated by (3-Aminopropyl) triethoxysilane modified polypropylene-silica nanocomposite (PP-SiO2 NC-NH2). The cuttings transport test was conducted in a 16-ft. annulus using 9.5 ppg muds, a 60°-hole angle, and annular velocities between 66.1 and 138.6 ft/min at different PP-SiO2 NC-NH2 concentrations of 0.4, 0.5, 0.8, and 1.2 ppb. The performance of 0.5 ppb PP-SiO2 NC-NH2 + WBM on CTE was evaluated and compared with that of WBM + 0.5 ppb of partially hydrolyzed polyacrylamide (PHPA) at five different hole angles from 90 to 0°. The results of zeta potential showed that the PP-SiO2 NC-NH2 was stable. The rheological and filtration properties were enhanced by the inclusion of PP-SiO2 NC-NH2 in the WBM. There exists a better enhancement in the CTE of PP-SiO2 NC-NH2 + WBM over that of PHPA + WBM at 0.5 ppb. The highest cuttings lifted to the surface occurred in a vertical well, followed by 90°, 30°, 60°, and 45° wells. An increase in annular velocity and the orbital motion of the drill pipe by mechanical action increased the CTE of the nanocomposite more than the rest mud samples. It seems the PP-SiO2 NC-NH2 can be more effective than the PHPA for the drilling process and can improve the cuttings lifting performance of WBMs but caution should be exercised to ensure its proper dispersion in drilling muds.