Evaluation of Novel Preformed Particle Gel System for Conformance Control in Mature Oil Reservoirs.

To address challenges associated with excessive water production in mature oil reservoirs, this study introduces a carboxymethyl cellulose (CMC)-based material as a novel preformed particle gel (PPG) designed to plug excessive water pathways and redistribute the subsequent injected water toward unswept zones. Through microwave-assisted grafting copolymerization of CMC with acrylamide (AM), we successfully generated multi-sized dry particles within the range of 250-800 µm. Comprehensive analyses, including Fourier-transform infrared spectroscopy (FTIR) and scanning electron microscopy (SEM), have confirmed the chemical composition and morphology of the resulting carboxymethyl cellulose-grafted crosslinked polyacrylamide (CMC/PAMBA). Swelling kinetics and rheology tests were conducted to confirm the ability of this novel PPG system to perform at different reservoir conditions. The results of core flooding experiments showed that the CMC/PAMBA PPG is capable of plugging open fractures with a water breakthrough pressure gradient of up to 144 psi/ft. This preformed particle gel (PPG) system was designed specifically for application in Middle East reservoirs, which are distinguished by high salinity and elevated temperature levels. This PPG system is able to swell up to 10 times its original size in seawater and maintain a strength of about 1300 Pa at a temperature of 80 °C. Further optimization is conceivable to enhance injection efficiency and achieve superior plugging outcomes.

Biodegradable Preformed Particle Gel (PPG) Made of Natural Chitosan Material for Water Shut-Off Application.

Oil and gas extraction frequently produces substantial volumes of produced water, leading to several mechanical and environmental issues. Several methods have been applied over decades, including chemical processes such as in-situ crosslinked polymer gel and preformed particle gel, which are the most effective nowadays. This study developed a green and biodegradable PPG made of PAM and chitosan as a blocking agent for water shutoff, which will contribute to combating the toxicity of several commercially used PPGs. The applicability of chitosan to act as a crosslinker has been confirmed by FTIR spectroscopy and observed by scanning electron microscopy. Extensive swelling capacity measurements and rheological experiments were performed to examine the optimal formulation of PAM/Cs based on several PAM and chitosan concentrations and the effects of typical reservoir conditions, such as salinity, temperature, and pH. The optimum concentrations of PAM with 0.5 wt% chitosan were between 5-9 wt%, while the optimum chitosan amount with 6.5 wt% PAM was in the 0.25-0.5 wt% range, as these concentrations can produce PPGs with high swellability and sufficient strength. The swelling capacity of PAM/Cs is lower in high saline water (HSW) with a TDS of 67.2976 g/L compared with fresh water, which is related to the osmotic pressure gradient between the swelling medium and the PPG. The swelling capacity in freshwater was up to 80.37 g/g, while it is 18.73 g/g in HSW. The storage moduli were higher in HSW than freshwater, with ranges of 1695-5000 Pa and 2053-5989 Pa, respectively. The storage modulus of PAM/Cs samples was higher in a neutral medium (pH = 6), where the fluctuation behavior in different pH conditions is related to electrostatic repulsions and hydrogen bond formation. The increase in swelling capacity caused by the progressive increment in temperature is associated with the amide group's hydrolysis to carboxylate groups. The sizes of the swollen particles are controllable since they are designed to be 0.63-1.62 mm in DIW and 0.86-1.00 mm in HSW. PAM/Cs showed promising swelling and rheological characteristics while demonstrating long-term thermal and hydrolytic stability in high-temperature and high-salinity conditions.

Lysine Crosslinked Polyacrylamide─A Novel Green Polymer Gel for Preferential Flow Control.

Acrylamide-based polymer gels have been applied to control the preferential flow in the subsurface for decades. However, some commonly used crosslinkers, such as Cr (III) and phenol-formaldehyde, are highly toxic and are being phased out because of stringent environmental regulations. This work uses l-lysine as the green crosslinker to produce acrylamide-based polymer gels. This article systematically studied the effect of lysine and polymer concentration, salinity, pH, and temperature on gelation behavior and thermal stability. Besides, the gelation mechanism and crosslinking density were elucidated in this work. A high-permeability sandstone core was used to test the plugging efficiency of this novel green gel system. This polyacrylamide/lysine system has a controllable gelation time. It can form gels at temperatures higher than 80 °C, with the gelation time from hours to days, and the elastic modulus of the gel can reach over 400 Pa. In addition, the crosslinked gels have been stable at 80 to 130 °C for over 200 days. This novel gel system could decrease rock permeability by over 1000 times. Besides, the Frrw is two times higher than the Frro, confirming that the current gel system can reduce the permeability to water more than that to oil. As a green gel system, this novel polymer gel system could replace the current toxic gel systems for the preferential fluid control for water management projects in oil and gas reservoirs, enhanced geothermal systems, and carbon capture and sequestration projects.

Comprehensive Review of Polymer and Polymer Gel Treatments for Natural Gas-Related Conformance Control.

Conformance problems often exist in natural gas-related activities, resulting in excessive water production from natural gas production wells and/or excessive natural gas production from oil production wells. Several mechanical and chemical solutions were reported in the literature to mitigate the conformance problems. Among the chemical solutions, two classes of materials, namely polymer gels and water-soluble polymers, have been mostly reported. These systems have been mainly reviewed in several studies for their applications as water shutoff treatments for oil production wells. Natural gas production wells exhibit different characteristics and have different properties which could impact the performance of the chemical solutions. However, there has not been any work done on reviewing the applications of these systems for the challenging natural gas-related shutoff treatments. This study provides a comprehensive review of the laboratory evaluation and field applications of these systems used for water control in natural gas production wells and gas shutoff in oil production wells, respectively. The first part of the paper reviews the in-situ polymer gel systems, where both organically and inorganically crosslinked systems are discussed. The second part presents the water-soluble polymers with a focus on their disproportionate permeability reduction feature for controlling water in gas production wells. The review paper provides insights into the reservoir conditions, treatment design and intervention, and the success rate of the systems applied. Furthermore, the outcomes of the paper will provide knowledge regarding the limitations of the existing technologies, current challenges, and potential paths forwards.

A Novel Numerical Model of Gelant Inaccessible Pore Volume for In Situ Gel Treatment.

Inaccessible pore volume (IAPV) can have an important impact on the placement of gelant during in situ gel treatment for conformance control. Previously, IAPV was considered to be a constant factor in simulators, yet it lacked dynamic characterization. This paper proposes a numerical simulation model of IAPV. The model was derived based on the theoretical hydrodynamic model of gelant molecules. The model considers both static features, such as gelant and formation properties, and dynamic features, such as gelant rheology and retention. To validate our model, we collected IAPV from 64 experiments and the results showed that our model fit moderately into these lab results, which proved the robustness of our model. The results of the sensitivity test showed that, considering rheology and retention, IAPV in the matrix dramatically increased when flow velocity and gelant concentration increased, but IAPV in the fracture maintained a low value. Finally, the results of the penetration degree showed that the high IAPV in the matrix greatly benefited gelant placement near the wellbore situation with a high flow velocity and gelant concentration. By considering dynamic features, this new numerical model can be applied in future integral reservoir simulators to better predict the gelant placement of in situ gel treatment for conformance control.

Pattern Recognition for Steam Flooding Field Applications Based on Hierarchical Clustering and Principal Component Analysis.

Steam flooding is a complex process that has been considered as an effective enhanced oil recovery technique in both heavy oil and light oil reservoirs. Many studies have been conducted on different sets of steam flooding projects using the conventional data analysis methods, while the implementation of machine learning algorithms to find the hidden patterns is rarely found. In this study, a hierarchical clustering algorithm (HCA) coupled with principal component analysis is used to analyze the steam flooding projects worldwide. The goal of this research is to group similar steam flooding projects into the same cluster so that valuable operational design experiences and production performance from the analogue cases can be referenced for decision-making. Besides, hidden patterns embedded in steam flooding applications can be revealed based on data characteristics of each cluster for different reservoir/fluid conditions. In this research, principal component analysis is applied to project original data to a new feature space, which finds two principal components to represent the eight reservoir/fluid parameters (8D) but still retain about 90% of the variance. HCA is implemented with the optimized design of five clusters, Euclidean distance, and Ward's linkage method. The results of the hierarchical clustering depict that each cluster detects a unique range of each property, and the analogue cases present that fields under similar reservoir/fluid conditions could share similar operational design and production performance.

Direct Pore-Level Visualization and Verification of In Situ Oil-in-Water Pickering Emulsification during Polymeric Nanogel Flooding for EOR in a Transparent Three-Dimensional Micromodel.

Different from inorganic nanoparticles, nanosized cross-linked polymeric nanoparticles (nanogels) have been demonstrated to generate more stable Pickering emulsions under harsh conditions for a long term owing to their inherent high hydrophilicity and surface energy. In both core and pore scales, the emulsions are found to be able to form in situ during the nanofluid flooding process for an enhanced oil recovery (EOR) process. Due to the limitation of direct visualization in core scale or deficient pore geometries built by two-dimensional micromodels, the in situ emulsification by nanofluids and emulsion transport are still not being well understood. In this work, we use a three-dimensional transparent porous medium to directly visualize the in situ emulsification during the nanogel flooding process for EOR after water flooding. By synthesizing the nanogel with a fluorescent dye, we find the nanogels adsorbed on the oil-water interface to lower the total interfacial energy and emulsify the large oil droplets into small Pickering oil-in-water emulsions. A potential mechanism for in situ emulsification by nanogels is proposed and discussed. After nanogel flooding, the emulsions trapped in pore throats and those in the effluents are all found encapsulated by the nanogels. After nanogel flooding under different flow rates, the sphericity and diameter changes of remaining oil droplets are quantitatively compared and analyzed using grouped boxplots. It is concluded that in situ emulsification happens during nanogel injection due to the reduction of interfacial tension, which helps to increase the oil recovery rate under different flow rates and pore geometries.

Systematic Evaluation of a Novel Self-Healing Poly(acrylamide-co-vinyl acetate)/Alginate Polymer Gel for Fluid Flow Control in High Temperature and High Salinity Reservoirs.

Preferential fluid flow often occurs when water and CO2 is injected into mature oilfields, significantly reducing their injection efficiency. Particle gels have been evaluated and applied to control the short circulation problems. This study systematically investigated a novel poly(acrylamide-co-vinyl acetate)/alginate-based interpenetrated gel system (Alg-IPNG) which is designed to control the preferential fluid flow problems in high-temperature reservoirs. Chromium acetate was incorporated into the gel system to provide the delayed crosslinking feature of the particle gels. The alginate polymer system can also take advantage of the Ca2+ ions in the formation water, which exist in most reservoirs, to reinforce its strength by capturing the Ca2+ to form Ca-alginate bonds. In this paper, various characterizations for the Alg-IPNGs before and after the self-healing process were introduced: (1) the elastic modulus is set at up to 1890 Pa, and (2) the water uptake ratio is set at up to 20. In addition, we also discuss their possible self-healing and reinforcement mechanisms. In particular, the self-healing starting time of the Alg-IPNG particles are modified between 38 to 60 h, which is related to the water uptake ratio, Ca2+ concentration, and temperature. The reinforced Alg-IPNG gel has an enhanced thermal stability (180 days) at the temperature up to 110 °C.

Experimental data on water soluble polymers thermal and hydrolytic stability, reactivity ratios of monomers and Frr calculation for thermally stable preformed particle gels therefrom.

Experimental data on water soluble polymer thermal and hydrolytic stability in acidic, neutral and basic pH conditions in aqueous solution is presented. Thermal and hydrolytic stability of polymer aqueous solutions were monitored in variable pH medium by aging at 130 °C temperature for different aging time. Polymer viscosity measurements were performed periodically for 3 months. Furthermore, this data can serve as a basis of monomer selection for thermally stable hydrogels for applications like oil recovery, hydrogel coatings for steam sterilized medical devices and other applications. Reactivity ratios were determined for monomers associated to the most stable polymers using 1H NMR analysis. Monomer reactivity ratios for DMA (M1) and NaSS (M2) depicted to be r 1 = 0.031 and r 2 = 5.379 using Fineman-Ross method and r 1 = 0.028 and r 2 = 5.495 using Kelen-Tudos method. The performance of preformed particle gels developed based on these monomers, in plugging the open fractures is explained using residual resistance factor (Frr) calculation.

Advances of spontaneous emulsification and its important applications in enhanced oil recovery process.

Emulsions, including oil-in-water (O/W) and water-in-oil (W/O) emulsions, can play important roles in both controlling reservoir conformance and displacing residual oil for enhanced oil recovery (EOR) projects. However, current methods, like high-shear mixing, high-pressure homogenizing, sonicators and others, often use lots of extra energy to prepare the emulsions with high costs but very low energy efficiency. In recent decades, spontaneous emulsification methods, which allow one to create micro- and nano-droplets with very low or even no mechanical energy input, have been launched as an overall less expensive and more efficient alternatives to current high extra energy methods. Herein, we primarily review the basic concepts on spontaneous emulsification, including mechanisms, methods and influenced parameters, which are relevant for fundamental applications for industrials. The spontaneity of the emulsification process is influenced by the following variables: surfactant structure, concentration and initial location, oil phase composition, addition of co-surfactant and non-aqueous solvent, as well as salinity and temperature. Then, we focus on the description of importance for emulsions in EOR processes from advances and categories to improving oil recovery mechanisms, including both sweep efficiency and displacement efficiency aspects. Finally, we systematically address the applications and outlooks based on the use of spontaneous emulsification in the practical oil reservoirs for EOR processes, in which conventional, heavy, high-temperature, high-salinity and low-permeability oil reservoirs, as well as wastewater treatments after EOR processes are involved.

Fabrication and verification of a glass-silicon-glass micro-/nanofluidic model for investigating multi-phase flow in shale-like unconventional dual-porosity tight porous media.

Unconventional shale or tight oil/gas reservoirs that have micro-/nano-sized dual-scale matrix pore throats with micro-fractures may result in different fluid flow mechanisms compared with conventional oil/gas reservoirs. Microfluidic models, as a potential powerful tool, have been used for decades for investigating fluid flow at the pore-scale in the energy field. However, almost all microfluidic models were fabricated by using etching methods and very few had dual-scale micro-/nanofluidic channels. Herein, we developed a lab-based, quick-processing and cost-effective fabrication method using a lift-off process combined with the anodic bonding method, which avoids the use of any etching methods. A dual-porosity matrix/micro-fracture pattern, which can mimic the topology of shale with random irregular grain shapes, was designed with the Voronoi algorithm. The pore channel width range is 3 µm to 10 µm for matrices and 100-200 µm for micro-fractures. Silicon is used as the material evaporated and deposited onto a glass wafer and then bonded with another glass wafer. The channel depth is the same (250 nm) as the deposited silicon thickness. By using an advanced confocal laser scanning microscopy (CLSM) system, we directly visualized the pore level flow within micro/nano dual-scale channels with fluorescent-dyed water and oil phases. We found a serious fingering phenomenon when water displaced oil in the conduits even if water has higher viscosity and the residual oil was distributed as different forms in the matrices, micro-fractures and conduits. We demonstrated that different matrix/micro-fracture/macro-fracture geometries would cause different flow patterns that affect the oil recovery consequently. Taking advantage of such a micro/nano dual-scale 'shale-like' microfluidic model fabricated by a much simpler and lower-cost method, studies on complex fluid flow behavior within shale or other tight heterogeneous porous media would be significantly beneficial.

Application of α-amylase as a novel biodemulsifier for destabilizing amphiphilic polymer-flooding produced liquid treatment.

The performance and de-emulsification mechanism of α-amylase, a novel environmental friendly biodemulsifier in petroleum industry, was investigated at room temperature. The effects of α-amylase on the viscosity of amphiphilic polymer solution and de-emulsification rate were studied by changing the concentration of α-amylase, temperature and salinity. Polymer molecular weight, Zeta potential, interfacial film strength and interfacial tension were measured to investigate the de-emulsification mechanism of α-amylase. The results show that α-amylase is an efficient biodemulsifier to increase the de-emulsification rate of amphiphilic polymer emulsions. Hydrolysis of α-amylase to amphiphilic polymers destroys the structure of the amphiphilic polymer, thereby reduces the viscosity and the interfacial film strength of the system. Once de-emulsification is completed, the lower layer, i.e. the emulsified layer, will be clear. Thus, α-amylase can be applied as an effective de-emulsifier for amphiphilic polymer-stabilized O/W emulsion.

Dynamic contact angles in oil-aqueous polymer solutions.

Polymer flooding is an important process in enhanced oil recovery. The displacement front is unstable when low viscosity brine displaces the heavy crude oil in the reservoir. Water-soluble polymers are added to the brine to increase its viscosity which stabilizes the displacement process. To analyze the displacement process at the micro-level, we have investigated the dynamic contact angles in silicone oil-polymer (polyethylene oxide) solution and for the first time. The dynamic contact angle is the apparent contact angle at the three-phase contact line which governs the capillary pressure, and thus is important for the displacement process. The data show no obvious signs of either shear thinning or elastic behavior, although for some systems with highest elastic effects some unexplained effects on dynamic contact angles are observed that correlate with elastic effects. Overall, dynamic contact angles are explained well using existing models for two Newtonian fluids, when the zero shear viscosity is used for the polymer solution.

Study of displacement efficiency and flow behavior of foamed gel in non-homogeneous porous media.

Field trials have demonstrated that foamed gel is a very cost-effective technology for profile modification and water shut-off. However, the mechanisms of profile modification and flow behavior of foamed gel in non-homogeneous porous media are not yet well understood. In order to investigate these mechanisms and the interactions between foamed gel and oil in porous media, coreflooding and pore-scale visualization waterflooding experiments were performed in the laboratory. The results of the coreflooding experiment in non-homogeneous porous media showed that the displacement efficiency improved by approximately 30% after injecting a 0.3 pore volume of foamed gel, and was proportional to the pore volumes of the injected foamed gel. Additionally, the mid-high permeability zone can be selectively plugged by foamed gel, and then oil located in the low permeability zone will be displaced. The visualization images demonstrated that the amoeba effect and Jamin effect are the main mechanisms for enhancing oil recovery by foamed gel. Compared with conventional gel, a unique benefit of foamed gel is that it can pass through micropores by transforming into arbitrary shapes without rupturing, this phenomenon has been named the amoeba effect. Additionally, the stability of foam in the presence of crude oil also was investigated. Image and statistical analysis showed that these foams boast excellent oil resistance and elasticity, which allows them to work deep within formations.

Optic imaging of single and two-phase pressure-driven flows in nano-scale channels.

Microfluidic and nanofluidic devices have undergone rapid development in recent years. Functions integrated onto such devices provide lab-on-a-chip solutions for many biomedical, chemical, and engineering applications. In this paper, a lab-on-a-chip technique for direct visualization of the single- and two-phase pressure-driven flows in nano-scale channels was developed. The nanofluidic chip was designed and fabricated; concentration dependent fluorescence signal correlation was developed for the determination of flow rate. Experiments of single and two-phase flow in nano-scale channels with 100 nm depth were conducted. The linearity correlation between flow rate and pressure drop in nanochannels was obtained and fit closely into Poiseuille's Law. Meanwhile, three different flow patterns, single, annular, and stratified, were observed from the two-phase flow in the nanochannel experiments and their special features were described. A two-phase flow regime map for nanochannels is presented. Results are of critical importance to both fundamental study and many applications.

Engineering bacteria for production of rhamnolipid as an agent for enhanced oil recovery.

Rhamnolipid as a potent natural biosurfactant has a wide range of potential applications, including enhanced oil recovery (EOR), biodegradation, and bioremediation. Rhamnolipid is composed of rhamnose sugar molecule and beta-hydroxyalkanoic acid. The rhamnosyltransferase 1 complex (RhlAB) is the key enzyme responsible for transferring the rhamnose moiety to the beta-hydroxyalkanoic acid moiety to biosynthesize rhamnolipid. Through transposome-mediated chromosome integration, the RhlAB gene was inserted into the chromosome of the Pseudomonas aeruginosa PAO1-rhlA(-) and Escherichia coli BL21 (DE3), neither of which could produce rhamnolipid. After chromosome integration of the RhlAB gene, the constitute strains P. aeruginosa PEER02 and E. coli TnERAB did produce rhamnolipid. The HPLC/MS spectrum showed that the structure of purified rhamnolipid from P. aeruginosa PEER02 was similar to that from other P. aeruginosa strains, but with different percentage for each of the several congeners. The main congener (near 60%) of purified rhamnolipid from E. coli TnERAB was 3-(3-hydroxydecanoyloxy) decanoate (C(10)-C(10)) with mono-rhamnose. The surfactant performance of rhamnolipid was evaluated by measurement of interfacial tension (IFT) and oil recovery via sand-pack flooding tests. As expected, pH and salt concentration of the rhamnolipid solution significantly affected the IFT properties. With just 250 mg/L rhamnolipid (from P. aeruginosa PEER02 with soybean oil as substrate) in citrate-Na(2)HPO(4), pH 5, 2% NaCl, 42% of oil otherwise trapped was recovered from a sand pack. This result suggests rhamnolipid might be considered for EOR applications.

Calcium lignosulfonate adsorption and desorption on Berea sandstone.

This paper describes adsorption and desorption studies carried out with calcium lignosulfonate (CLS) on Berea sandstone. Circulation experiments were performed to determine CLS adsorption isotherms and the effects of CLS concentration, temperature, salinity, brine hardness, and injection rate on adsorption density. Flow-through experiments were performed to assess the reversibility of CLS adsorption and the influence of postflush rate, brine concentration, brine hardness, brine pH, and temperature on the desorption process. Results indicate that CLS adsorption isotherms on Berea sandstone follow the Freundlich isotherm law. The results presented in this paper on the effects of CLS adsorption and desorption on Berea sandstone show that: (1) increasing CLS concentration and salinity increases CLS adsorption density; (2) increasing temperature will decrease adsorption density; (3) increasing injection rate of CLS solution will slightly decrease CLS adsorption density; (4) postflush rate and salinity of brine have a large impact on the CLS desorption process; (5) the adsorption and desorption process are not completely reversible; and (5) temperature and pH of the postflush brine have little effect on desorption.