High-temperature Oil Reservoirs Research Articles

Modified guanidine gel fracturing fluid system and performance optimization for ultra-deep and ultra-high temperature oil and gas reservoirs

The development of deep high-temperature oil and gas reservoirs gives rise to a rise in reservoir temperature along with the depth of the oil reservoir, thereby imposing higher requirements on the heat resistance of fracturing fluid. Guar gum fracturing fluid has difficulty tolerating temperatures exceeding 160 °C, thereby demanding the development of corresponding cross-linking agents, temperature stabilizers, and other additives to enhance the thermal stability of the fracturing system. Considering the distinctive characteristics of deep and ultra-deep reservoirs, such as extreme burial depth (exceeding 6000 m), ultra-high temperature (higher than 160 °C), and high fracturing pressure, an experimental modification of a guar gum fracturing fluid system was carried out, specifically tailored for ultra-high temperatures. The experiment identified and selected individual agents for ultra-high temperature fracturing fluids, including crosslinking agents, thermal stabilizers, flowback aids, and clay inhibitors. Through rigorous experimentation, these key agents for an ultra-high temperature fracturing fluid system have been successfully developed, including the optimal thickener GBA1-2, crosslinking agent BA1-1, anti-swelling agent FB-1, and gel breaker TS-1. The evaluation of diverse additive dosages has facilitated the development of an optimal guar fracturing fluid system, which exhibits outstanding high-temperature resistance while minimizing damage and friction. The outcomes of our experiments indicate that even after subjecting our ultra-high temperature fracturing fluid to 2 h of shearing at 170 s−1 at 180 °C, its viscosity remained above 200 mPa s—a distinct proof of its superior performance in withstanding high temperatures. This achievement represents a substantial progress in providing a suitable fracturing fluid system for the transformation and stimulation of ultra-deep and ultra-high temperature reservoirs, and also lays a solid foundation for further exploration and application in related fields in the future.

Magnetic smart polymer gel with directional plugging for conformance control in oil reservoirs

Polymer gel technology has been proven to be one of the most effective methods for conformance control and enhanced oil recovery. However, to effectively gel highly permeable layers, precise placement of the gelant within the formation is required. Herein, to make the most use of polymer gel in conformance control, a novel magnetic smart polymer gel consisting of polyacrylamide and Fe3O4@polyethylenimine, is designed and prepared as a conformance fluid to achieve directional plugging in target reservoirs. To deeper understanding of the properties of Fe3O4@polyethylenimine and smart gel, as well as how they are formed and function, the microstructure of these materials was characterized through various techniques, including analysis of their crystal and chemical structures, micromorphology, and cross-linking mechanism, et al. The rheological tests suggest that the system has good viscosity and elasticity, and the gel strength can reach 105,463 mPa⋅s after aging 30 days at 120 °C. Furthermore, the controlled manipulation indicated that smart gel can move quickly and repeatedly to a designated location under a magnetic field. Additionally, the influence of the magnetic generator on the intelligent plugging performance of the smart gel system is also explored. It has been found that magnetic plugging can extend the effective lifespan of smart gel. Finally, the conformance control performance of the smart gel system is revealed by the parallel cores flow experiment. This work presents a novel smart gel system designed for directional plugging, to enhance conformance control in high-temperature oil reservoirs.

A robust viscoelastic surfactant tolerating 20% HCl up to 150 °C for oil well stimulation

Viscoelastic surfactants (VES) are often used as viscous diverters in acidizing stimulation to prolong the acid consumption time and maximize zonal coverage of the acid for improving well productivity. However, the ceiling temperature of commercial VES cannot exceed 120 °C in practical use because of the poor thermal stability and fragile molecular structure, hindering their implementation in high-temperature oil reservoirs, i.e., ≥150 °C. Here we synthesized a novel C22-tailed diamine, N-erucaminopropyl-N,N-dimethylamine (EDPA), and examined comparatively its rheological behavior, assemblies morphology and molecular stability in 20 wt% HCl with a commercial VES, erucyl dimethyl amidopropyl betaine (EDAB). The feasibility of EDPA for acidizing stimulation was assessed by acid etching of carbonate rock with its HCl solution at 150 °C. Rheological results showed that the 2.5 wt% EDPA–20 wt% HCl solution maintains stable viscosity of 90 mPa s at 150 °C for 60 min, while that of 2.0 wt% EDAB HCl solution is just 1 mPa s under identical conditions. 1H NMR spectra and cryo-TEM observations revealed that the chemical structure and self-assembled architectures of EDPA remained intact in such context, but the EDAB suffered from degradation due to the hydrolysis of the amide group, accounting for the poor heat-resistance and acid-tolerance. The reaction rate of 2.5 wt% EDPA HCl solution with carbonate rock was one order of magnitude lower than that of 20 wt% HCl solution at 150 °C, underpinning the potential of EDPA to be used in the high-temperature reservoirs acidizing. This work improved the thermal tolerance of VES in highly concentrated HCl solution, paving a feasible way for the acidization of high-temperature reservoir environments (∼150 °C).

Enhanced Oil Recovery Using Indigenous Microbiome of High Temperature Oil Reservoirs.

Crude oil is a primary energy source used for economic expansion across the world. Secondary recovery processes employed by industries to recover oil from oil wells leave behind 70% of the oil trapped in marginal and deleted zones of reservoirs. To recover the oil from depleted zones, microbial enhanced oil recovery (MEOR) tertiary processes were introduced, which involve the production of metabolites from the indigenous microbiome. In this study, the indigenous microbiota was identified as Marinobacterium sp., Silvanigrella sp., Petrothermobacter sp., Pseudomonas sp., Bacillus sp., Nitrincola sp., Halomonas sp., Uncultured Roseovarius sp., and Phaeobacter. Further, the secondary metabolites such as volatile fatty acids (ethanol, acetone, and acetate), biomass, gases (CO2, CH4), and biosurfactants were estimated through gas chromatography and FTIR spectroscopy. Once stable microbial growth was attained in the baltch media, it was optimized through response surface methodology (RSM) to minimize the process cost. The optimized media with 9g/L of molasses, 1.75g/L of sodium bicarbonate, and 1.25g/L of ammonium chloride showed a significant impact on metabolite production. Additionally, core flood studies to simulate field studies were performed that represented that TeriK-1 brought a significant increment of 18.9%, which makes it suitable for MEOR field implementation. This study is one of its kind where the indigenous thermophilic sp. was successfully established and is capable of producing the secondary metabolites that aid in the MEOR process.

A New Thermal Stable and Salt Tolerant Alkyl Polyether Benzyl Sulfonate Surfactant with Ultralow Interfacial Tensions for Enhanced Oil Recovery

A large variety of surfactants have been widely used in enhanced oil recovery, yet there is still a challenge for the application of surfactants in oil reservoirs with high salinity and high temperatures. Herein we report a new alkyl polyether benzyl sulfonate anionic surfactant named sodium iso-tridecanol polyoxyethylene ether benzyl sulfonate with ultralow interfacial tensions at high salinity and high temperatures synthesized through a strategy connecting the alkyl polyether with a benzyl group. Its structure was confirmed by 1H NMR. Effects of the temperature, salinity, divalent ion, and surfactant concentration on interfacial tensions and phase behaviors were investigated. The alkyl polyether benzyl sulfonate surfactant demonstrated a strong interfacial activity and excellent phase behavior with high solubilization parameters at salinities up to 18.0 wt % NaCl and temperatures up to 120 °C, which suggest that the new alkyl polyether benzyl sulfonate surfactant has good temperature resistance and salt tolerance and is promising for applications in enhanced oil recovery in high temperature and high salinity oil reservoirs.

Degradation of long-chain n-alkanes by a novel thermal-tolerant Rhodococcus strain.

A novel bacterial strain, CH91, was isolated from a high-temperature oil reservoir. Morphological characterization, phylogenetic analyses of 16S rRNA gene sequence and genome relatedness indicated that the strain is a potential new species in the genus Rhodococcus. Strain CH91 could grow in the temperature range of 25-50°C (optimally at 37°C) and utilize a broad range of long-chain n-alkanes from hexadecane to hexatriacontane. The utilization of the n-alkanes mixture of strain CH91 revealed that the degradation rate was correlated to the length of the carbon chain. Two novel alkB genes encoding alkane 1-monooxygenase were found in the genome of this strain. The protein sequences of both alkane 1-monooxygenases showed a remarkable phylogenetic distance to other reported AlkB protein sequences. These results would help broaden our knowledge about alkane degradation by Rhodocuccus and its potential ecological role. The ability of the strain in the long-chain alkane degradation and thermal tolerance could also be further exploited for bioremediation of oil contaminations and microbial enhanced oil recovery.

Genomics and simulated laboratory studies reveal Thermococcus sp. 101C5 as a novel hyperthermophilic archaeon possessing a specialized metabolic arsenal for enhanced oil recovery.

Laboratory evaluation of hyperthermophiles with the potential for Enhanced Oil Recovery (EOR) is often hampered by the difficulties in replicating the in situ growth conditions in the laboratory. In the present investigation, genome analysis was used to gain insights into the metabolic potential of a hyperthermophile to mobilize the residual oil from depleting high-temperature oil reservoirs. Here, we report the 1.9Mb draft genome sequence of a hyperthermophilic anaerobic archaeon, Thermococcus sp. 101C5, with a GC content of 44%, isolated from a high-temperature oil reservoir of Gujarat, India. 101C5 possessed the genetic arsenal required for adaptation to harsh oil reservoir conditions, such as various heat shock proteins for thermo-adaptation, Trk potassium uptake system proteins for osmo-adaptation, and superoxide reductases against oxidative stress. Microbial Enhanced Oil Recovery (MEOR) potential of the strain was established by ascertaining the presence of genes encoding enzymes involved in the production of the metabolites such as hydrogen, bio-emulsifier, acetate, exopolysaccharide, etc. Production of these metabolites which pressurize the reservoir, emulsify the crude oil, lower the viscosity and reduce the drag, thus facilitating mobilization of the residual oil was experimentally confirmed. Also, the presence of crude oil degradative genes highlighted the ability of the strain to mobilize heavy residual oil, which was confirmed under simulated conditions in sand-pack studies. The obtained results demonstrated additional oil recoveries of 42.1% and 56.5% at 96°C and 101°C, respectively, by the strain 101C5, illustrating its potential for application in high-temperature oil reservoirs. To our best knowledge, this is the first report of genome analysis of any microbe assessed for its suitability for MEOR from the high-temperature oil reservoir.

Research on geothermal development model of abandoned high temperature oil reservoir in North China oilfield

As a green, low-carbon and renewable energy, the geothermal energy has attracted great attentions. Abundant geothermal resources are hosted in several depleted oilfields. Geothermal development in abandoned oilfields has its advantages that operators are familiar with the geographic environment, geological conditions, and drilling and development techniques in the oilfield. In this study, a thermo-hydro- mechanical multi-field coupling mathematical model was established with data from Liubei Buried Hill reservoir in North China Oilfield. Then, the geothermal development in abandoned high-temperature oilfields was simulated, and the sensitivity of the geothermal development effect to well patterns, fracturing conditions, and working media was analyzed. The results show that the well pattern of one-injector and four-producer leads to the largest heat-exchange area. The hydraulic fracture model causes earlier thermal breakthrough but produces more heat than the non-fractured model. CO2 has the better working fluid performance and leads to the better geothermal development effect than water. This study provides a theoretical basis for the high-efficiency development of geothermal energy in abandoned oilfields, and a guidance for research on geothermal development model and fracturing design.

Geochemical reactions and their effect on CO2 storage efficiency during the whole process of CO2 EOR and subsequent storage

CO2-formation water-rock geochemical reactions can occur, affecting the reservoir physical properties and CO2 trapping forms during the CO2 enhanced oil recovery (CO2-EOR) process. In this paper, based on the properties of the reservoir and fluids in a high-temperature oil reservoir, a comprehensive model, including formation water evaporation, dissolution, diffusion of CO2 in water, CO2-water-rock geochemical reactions, and relation of porosity and permeability, is established to simulate the CO2 EOR process and subsequent geological storage. The geochemical reactions and CO2 trapping forms in these two stages are analyzed using this model, and the influences of reservoir heterogeneity and different CO2 injection schemes on EOR and CO2 geological storage are studied. The results show that the geochemical reactions can change reservoir porosity and permeability, but their effect is little, and most of the injected CO2 is trapped as the supercritical gas during the CO2 EOR process. During the stage of CO2 geological storage, the supercritical CO2 continuously converts into mineral form under the action of geochemical reactions, which results in the reservoir pressure decreasing. Whether the reservoir is heterogeneous or homogenous, the water-alternating-gas (WAG) scheme should be the first choice because it can enhance both oil recovery and CO2 storage efficiency in the EOR process. The injection of CO2 after the CO2 EOR process can improve the CO2 storage capacity and simultaneously maintain the reservoir pressure stabilization.

Structural Insights into the Methane-Generating Enzyme from a Methoxydotrophic Methanogen Reveal a Restrained Gallery of Post-Translational Modifications.

Methanogenic archaea operate an ancient, if not primordial, metabolic pathway that releases methane as an end-product. This last step is orchestrated by the methyl-coenzyme M reductase (MCR), which uses a nickel-containing F430-cofactor as the catalyst. MCR astounds the scientific world by its unique reaction chemistry, its numerous post-translational modifications, and its importance in biotechnology not only for production but also for capturing the greenhouse gas methane. In this report, we investigated MCR natively isolated from Methermicoccus shengliensis. This methanogen was isolated from a high-temperature oil reservoir and has recently been shown to convert lignin and coal derivatives into methane through a process called methoxydotrophic methanogenesis. A methoxydotrophic culture was obtained by growing M. shengliensis with 3,4,5-trimethoxybenzoate as the main carbon and energy source. Under these conditions, MCR represents more than 12% of the total protein content. The native MCR structure refined at a resolution of 1.6-Å precisely depicts the organization of a dimer of heterotrimers. Despite subtle surface remodeling and complete conservation of its active site with other homologues, MCR from the thermophile M. shengliensis contains the most limited number of post-translational modifications reported so far, questioning their physiological relevance in other relatives.

Thermodynamically favorable reactions shape the archaeal community affecting bacterial community assembly in oil reservoirs.

Microbial community assembly mechanisms are pivotal for understanding the ecological functions of microorganisms in biogeochemical cycling in Earth's ecosystems, yet rarely investigated in the context of deep terrestrial ecology. Here, the microbial communities in the production waters collected from water injection wells and oil production wells across eight oil reservoirs throughout northern China were determined and analyzed by proportional distribution analysis and null model analysis. A 'core' microbiota consisting of three bacterial genera, including Arcobacter, Pseudomonas and Acinetobacter, and eight archaeal genera, including Archaeoglobus, Methanobacterium, Methanothermobacter, unclassified Methanobacteriaceae, Methanomethylovorans, Methanoculleus, Methanosaeta and Methanolinea, was found to be present in all production water samples. Canonical correlation analysis reflected that the core archaea were significantly influenced by temperature and reservoir depth, while the core bacteria were affected by the combined impact of the core archaea and environmental factors. Thermodynamic calculations indicate that bioenergetic constraints are the driving force that governs the enrichment of two core archaeal guilds, aceticlastic methanogens versus hydrogenotrophic methanogens, in low- and high-temperature oil reservoirs, respectively. Collectively, our study indicates that microbial community structures in wells of oil reservoirs are structured by the thermodynamic window of opportunity, through which the core archaeal communities are accommodated directly followed by the deterministic recruiting of core bacterial genera, and then the stochastic selection of some other microbial members from local environments. Our study enhances the understanding of the microbial assembly mechanism in deep terrestrial habitats. Meanwhile, our findings will support the development of functional microbiota used for bioremediation and bioaugmentation in microbial enhanced oil recovery.

Investigation of a high temperature gel system for application in saline oil and gas reservoirs for profile modification

The deeper the burial of the oil and gas reservoir, the higher the temperature of the oil and gas reservoir. When profile adjustment of water injection wells, plugging of oil production wells (gas production wells) and temporary plugging or killing of oil production wells (gas production wells) are required, the higher the temperature resistance of the plugging agent (above 150 °C) is required. In addition, high temperature resistant plugging agents should also be used in profile control or water plugging in reservoirs (120°C–200 °C) that are thermally recovered by steam injection or in situ combustion. It is of great importance to develop a high-temperature-resistant gel plugging system to fulfill the requirements of deep buried high-temperature oil or gas reservoirs or thermal recovery high-temperature oil reservoir operations.A gel system formed by the terpolymer (L-1) and a new cross-linking system (HB-1) was developed, and its properties were systematically studied in the condition of extremely high temperature. Studies have shown that the gel system could form stable continuous 3D network structures in high temperature (120°C–200 °C) and thus have an excellent long-term thermal stability.The gel system can adjust the strength by changing the concentration of the terpolymer (0.05%–1%) and the crosslinker (0.05%–1%), which can achieve different construction requirements. Compared with the conventional high-temperature-resistant gel, the cross-linking system HB-1 contains 4 hydroxyl groups (–CH2OH), it can crosslink with 4 amide groups (–CONH2) on the terpolymer. Therefore, this gel system can form a smaller grid size of 3D network structures (less than 5 μm), so it has stronger temperature resistance and better long-term thermal stability. When the temperature is 200 °C, the grid size of network structure is about 10 μm, but the strength of the gel system can still be maintained at code F-G. When the salinity of the water solution is 200,000 mg/L, the gel system on the contact surface can still maintain a small grid size of 3D network structures (about 10 μm). The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. A gel system with strength F can still be formed after shearing by the pore media of 10 sand-packed tubes, and the plugging rate of each sand-packed tube exceeds 97%. It can be found by scanning electron microscope pictures that the gel system can be very firmly attached to the pore media, which can achieve profile adjustment of the formation. The gel system could have great potential in the application of high temperature oil or gas reservoirs.

A nano‐Fe3O4 material coated with AM/AMPS copolymer for viscosity enhancement at harsh reservoir conditions

AbstractA Fe3O4 nonaparticles coated with acrylamide/2‐acrylamido‐2‐methyl‐1‐propanesulfonic acid copolymer(Fe3O4‐Polymer NPs) was synthesized by emulsion polymerization. The structure of Fe3O4‐Polymer NPs was then characterized by infrared spectroscopy, thermo‐gravimetric analysis, and scanning electron microscopy. Meanwhile, the rheological properties of Fe3O4‐Polymer NPs solution were systematically studied. The results showed that when dosage of hydrophobic Fe3O4‐Oleic NPs is 10%, the synthesized Fe3O4‐Polymer NPs was with the best viscosity enhancement performance, and the maximum saturation magnetization could reach to 20.0 emu/g. The apparent viscosity value of 5000 mg/L magnetic nano‐composite solution was 154.6 mPa·s at 30°C. It shows strong viscosity enhancement ability and good temperature performance. Hence, it has great application potential in well stimulation of medium and high temperature oil and gas reservoirs.

Sulfate reducing microorganisms in high temperature oil reservoirs.

High temperature reservoirs offer a window into the microbial life of the deep biosphere. Sulfate reducing microorganisms have been recovered from high temperature oil reservoirs around the globe and characterized using culture-dependent and culture-independent approaches. The activities of sulfate reducers contribute to reservoir souring and hydrocarbon degradation among other attracting considerable interest from the oil industry for the last 100 years. The extremes of temperature and pressure shape the activities and distribution of sulfate reducing bacteria and archaea in high temperature reservoirs. This chapter will attempt to summarize the key findings on the diversity and activities of sulfate reducing microorganisms in high temperature reservoirs.

Long-term souring treatment using nitrate and biocides in high-temperature oil reservoirs

The biogenic production of hydrogen sulfide (H2S) by sulfate-reducing bacteria (SRB) and consequently the souring of reservoirs are still major problems in oil industry. Biocides and/or nitrate are used to control SRB activity in oil reservoirs, but long-term studies are still needed to prove their efficacy. In this study, two high-temperature (80–84 °C) oil reservoirs were analyzed over three years. Nitrate and tetrakishydroxymethyl phosphonium sulfate (THPS) were added to the water injection system (WI) at the beginning of secondary oil recovery in oil reservoir 1, while nitrate was only added 19 months after the beginning of secondary oil recovery in oil reservoir 2. The H2S concentration was quantified monthly in production wells, and the total bacterial community (based on the gene coding for 16S rRNA) and SRB (based on dsrA and apsAB genes) were determined using fluorescence in situ hybridization (FISH) and PCR-DGGE analyses. Nitrate plus THPS controlled H2S production for 34 months in oil reservoir 1. THPS injection in oil reservoir 2 controlled H2S levels for 17 months, and the further addition of nitrate in water injection did not control H2S production. PCR-DGGE analyses and the molecular identification of the dominant groups showed a predominance of thermophilic bacteria, including different SRB (such as Desulfocaldus and Desulfonauticus) and nitrate-reducing bacteria (NRB – Marinobacter) in oil reservoir 1 and mesophilic SRB (Desulfovibrio) and NRB (Halomonas and Acinetobacter) in oil reservoir 2. The strategy chosen during secondary oil recovery modulated the microbial community and, consequently, changed the dynamics of H2S production.

Investigation of a high temperature gel system for application in saline oil and gas reservoirs for profile modification

The deeper the burial of the oil and gas reservoir, the higher the temperature of the oil and gas reservoir. When profile adjustment of water injection wells, plugging of oil production wells (gas production wells) and temporary plugging or killing of oil production wells (gas production wells) are required, the higher the temperature resistance of the plugging agent (above 150 °C) is required. In addition, high temperature resistant plugging agents should also be used in profile control or water plugging in reservoirs (120°C–200 °C) that are thermally recovered by steam injection or in situ combustion. It is of great importance to develop a high-temperature-resistant gel plugging system to fulfill the requirements of deep buried high-temperature oil or gas reservoirs or thermal recovery high-temperature oil reservoir operations.A gel system formed by the terpolymer (L-1) and a new cross-linking system (HB-1) was developed, and its properties were systematically studied in the condition of extremely high temperature. Studies have shown that the gel system could form stable continuous 3D network structures in high temperature (120°C–200 °C) and thus have an excellent long-term thermal stability.The gel system can adjust the strength by changing the concentration of the terpolymer (0.05%–1%) and the crosslinker (0.05%–1%), which can achieve different construction requirements. Compared with the conventional high-temperature-resistant gel, the cross-linking system HB-1 contains 4 hydroxyl groups (–CH2OH), it can crosslink with 4 amide groups (–CONH2) on the terpolymer. Therefore, this gel system can form a smaller grid size of 3D network structures (less than 5 μm), so it has stronger temperature resistance and better long-term thermal stability. When the temperature is 200 °C, the grid size of network structure is about 10 μm, but the strength of the gel system can still be maintained at code F-G. When the salinity of the water solution is 200,000 mg/L, the gel system on the contact surface can still maintain a small grid size of 3D network structures (about 10 μm). The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. A gel system with strength F can still be formed after shearing by the pore media of 10 sand-packed tubes, and the plugging rate of each sand-packed tube exceeds 97%. It can be found by scanning electron microscope pictures that the gel system can be very firmly attached to the pore media, which can achieve profile adjustment of the formation. The gel system could have great potential in the application of high temperature oil or gas reservoirs.

Physicochemical and biological controls of sulfide accumulation in a high temperature oil reservoir.

In order to maintain the reservoir pressure during secondary oil production large volumes of seawater are injected into reservoirs. This practice introduces high concentrations of sulfate into the reservoir promoting the growth of sulfate-reducing microorganisms (SRM) and results in the production of an increasing volume of produced water (PW) that needs to be discharged. SRM reduce sulfate to sulfide causing reservoir souring and as a mitigation strategy nitrate is injecting along with the seawater into the reservoir. We used PW from the Halfdan oil field (North Sea) to set up microcosms to determine the best reinjection strategy in order to inhibit SRM activity and minimize the environmental impact of PW during secondary oil production. We discuss the effect of temperature, electron donor, and sulfate and nitrate availability on sulfide production and microbial community composition. Temperature and the terminal electron acceptor played a key role in shaping the microbial community of the microcosms. PW reinjection at 62°C inhibited SRM activity due to nitrite toxicity by encouraging nitrate reduction to nitrite by thermophilic nitrate reducers, while at 74°C we observed complete absence of any microbial activity over the course of 150days. KEY POINTS: • Temperature and the presence/ absence of nitrate shaped the microbial community structure. • Thermophilic nitrate reducers convert nitrate to ammonia with the accumulation of nitrite that inhibits sulfide production. • Nitrite inhibition is the most effective nitrate-based souring mitigation mechanisms. • The reinjection of hot produced water to oil reservoirs is a promising souring mitigation approach.

Laboratory studies on a novel salt-tolerant and alkali-free flooding system composed of a biopolymer and a bio-based surfactant for oil recovery

Alkali/surfactant/polymer (ASP) flooding is one of the most effective tertiary oil recovery technologies. However, the formation of an alkali scale potentially results in the reduction of the formation permeability and pipeline corrosion, which affect its industrial application. Recently, the surfactant/polymer (SP) flooding system in the absence of alkali has received increasing attention. Here, we screened a high-yielding strain, which is capable of producing salt-tolerant biopolymer. The results of rheological properties evaluation showed that this biopolymer possessed a stable viscosity at high salinities (up to 200 g/L NaCl, 100 g/L Ca2+, and 100 g/L Mg2+) and a wide range of pH (4–11), indicating its superior salt and pH resistance. Based on these properties, a novel salt-tolerant and alkali-free binary flooding system was constructed with this biopolymer and bio-based surfactant newly synthesized in our lab. The ultra-low interfacial tension (IFT) between crude oil and the binary system containing 0.5 wt % biopolymer and 1.00 g/L surfactant could be achieved in the presence of 100 g/L NaCl or 400 mg/L Ca2+. Moreover, it exhibited good resistance to oil sands adsorption, excellent anti-dilution, and ageing stability. These results indicate that the biopolymer produced by the Kosakonia oryzae strain possessed great potential in the construction of an alkali-free SP system for enhanced oil recovery (EOR) in high salinity and high temperature oil reservoirs.

Percolation threshold of multiwall carbon nanotube-PVDF composite for electromagnetic wave propagation

Advanced physical properties of conductive polymers fibre composites have attracted the attention of material scientists. Here, we produced a polymer fibre composite with aligned multiwall carbon nanotube (MWCNT) of different weight fractions, ranging from 0.25 wt% to 1.5 wt%. At 1.5 wt% additive, a conductor-non-conductor transition occurs that is percolation threshold. This effect enhances the electrical conductivity of polymer composite from 0.050 S m−1 to 326.250 S m−1. Electrically conductor polymer composite will be highly preferred to fabricate radio frequency antennas, due to their unique physical and mechanical properties. We evaluated the performance of the polymer composite antenna and observed the percolation effect in electromagnetic wave propagation of the composite antenna. Far-field radiation of 1.5 wt% MWCNT-polymer antenna was 0.728 V m−1, whereas the maximum far-field result of the antennas made by lower MWCNT concentrations was 0.102 V m−1. Adopting the mechanical properties of PVDF composite, the composite-based RF antenna can be used in robust environments, such as high pressure high temperature oil reservoirs.

Novel clostridial lineages recovered from metagenomes of a hot oil reservoir

Oil reservoirs have been shown to house numerous microbial lineages that differ based on the in-situ pH, salinity and temperature of the subsurface environment. Lineages of Firmicutes, including Clostridiales, have been frequently detected in oil reservoirs, but are typically not considered impactful or relevant due to their spore-forming nature. Here we show, using metagenomics, a high temperature oil reservoir of marine salinity contains a microbial population that is predominantly from within the Order Clostridiales. These organisms form an oil-reservoir specific clade based on the phylogenies of both 16S rRNA genes and ribosomal proteins, which we propose to name UPetromonas tenebris, meaning they are single-celled organisms from dark rocks. Metagenome-assembled genomes (MAGs) of these Petromonas sp. were obtained and used to determine that these populations, while capable of spore-formation, were also likely replicating in situ in the reservoir. We compared these MAGs to closely related genomes and show that these subsurface Clostridiales differ, from the surface derived genomes, showing signatures of the ability to degrade plant-related compounds, whereas subsurface genomes only show the ability to process simple sugars. The estimation of in-situ replication from genomic data suggest that UPetromonas tenebris lineages are functional in-situ and may be specifically adapted to inhabit oil reservoirs.