Oil Recovery Applications Research Articles

Technology Focus: EOR Operations (November 2024)

International agreements and national policies on environmental sustainability are changing the outlook for enhanced oil recovery (EOR) globally. These changes are highlighted by both monetary and intellectual commitments by oil companies around the world. Saudi Aramco has pledged $1.5 billion toward sustainable technology. In practice, members of Aramco’s EXPEC Advanced Research Center have collaborated with King Fahd University of Petroleum and Minerals to develop sustainable surfactants for use in high-temperature, high-pressure, and high-salinity carbonate reservoirs. They used no or only green solvents to produce soluble, stable surfactants with the potential for biodegradability. In Colombia, Ecopetrol is committed to reducing CO2 emission by 25% by 2030. As part of its efforts, it has been optimizing polymer injection in Chichimene, a heavy-oil field. By estimating life cycle greenhouse-gas emissions and energy consumption, it was able to show that polymer injection and its associated carbon intensity reduction could prevent the emission of 3,200 tons CO2 equivalent. To comply with the UK’s North Sea Transition Deal, which mandates a 50% reduction in offshore oil and gas emissions by 2030, Ithaca Energy and Energy Research Norway is using life-cycle assessment to guide more efficient heavy-oil recovery. By using low-dose polymer injection, instead of alternatives such as thermal EOR, it was able to increase exergy while also reducing CO2 emissions by 35%. In these studies, we already see the effect of the energy transition as companies turn away from traditionally effective but environmentally burdensome EOR methods such as steam injection and new polymers that show equal, if not greater, effectiveness with a reduced environmental cost. As we move forward with further regulation and innovation, it will be interesting to see how emerging technological developments in polymers, nanofluids, and even artificial intelligence can help producers meet both the economic and environmental criteria to maintain profitable fields. Recommended additional reading at OnePetro: www.onepetro.org. SPE 218653 Coinjection EOR Technology Increases Recovery and Reduces Greenhouse-Gas Emissions by G. Wasylchuk, GERI SPE 218690 Steam Generation Using Renewables Energy—An Integrated Approach for Enhanced Oil Recovery Applications by Mustafa Al Ajmi, Petroleum Development Oman, et al. SPE 218962 Reaching a Million Barrels in an Abu Dhabi Field by Focusing on Operations Efficiency by Masud J. Akhtar, Abu Dhabi National Oil Company, et al.

Water-soluble chitosan polymer for enhanced oil recovery in the carbonate reservoir

Numerous surfactants, nanoparticles and polymers have been developed and utilized for enhanced oil recovery applications, irrespective of their environmental impact. Most of these oilfield chemicals were prepared through multi-steps from fossil-based starting materials using hazardous solvents. However, there is a desire to advance eco-friendly and sustainable materials to reduce CO2 emissions and enhance the sustainability of oil production. Herein, we propose the development of chitosan salt, a solely green polymer, prepared in water in the presence of acetic acid (0.1% v/v). The resulting water-soluble polymer demonstrated excellent stability under reservoir conditions and was tested for enhanced oil recovery in the carbonate reservoir. The oil-wet rock wettability was significantly reduced after using chitosan salt solution. Nuclear magnetic resonance (NMR) experiments were used to show the oil displacement at different pores regions using relaxation time (T2 distribution). Imbibition and coreflooding experiments showed that the chitosan salt is able to increase the enhanced oil recovery by extra 16.2% which surpass the recovery obtained from commercial surfactants such as α-olefin sulfonate (AOS) and cetrimonium bromide (CTAB). This study shows that green materials are promising candidates for oil recovery and upstream applications.

Enhancing the emulsification and demulsification efficiency of switchable surfactants through molecular dynamics simulation: The roles of surfactant concentration, salinity, and structure

This study aims to investigate the impacts of a surfactant structure, surfactant concentration, and salt content on switchable emulsification processes through molecular dynamics (MD) simulations. Specifically, we focus on assessing the properties and behaviors of water/tetradecane systems containing CO2-switchable acetamidine surfactant N’-dodecyl-N, N-dimethylacetamidine (C12DMAA) and C18 naphthalene sulfonate (C18PS), both of which are relevant to enhanced oil recovery processes. Utilizing MD simulations, we comprehensively explore the influence of the molecular composition of switchable surfactants, salinity, and surfactant concentration on the reversible processes of emulsification and demulsification in a complex oil/water/C18PS/C12DMAA system. This system can be activated through the injection of CO2 or N2 gas. Various analyses, including molecule mobility, hydration behavior, void volume analysis, a solvent accessible surface area (SASA), a diffusion coefficient, and relative concentration profiles, are employed to gain insights into the emulsification and demulsification processes. Our study reveals that lower surfactant concentrations result in the formation of partial emulsions, while the presence of salt disrupts surfactant hydration and weakens emulsification properties. Additionally, we observe that the impact of hydrogen bonding interactions is less pronounced at lower surfactant concentrations. Furthermore, the MD simulations provided insights into the interplay of a surfactant monomer number and alkyl phenyl introduction with a solvent-accessible surface area (SASA) and a void volume. Understanding these factors is crucial for designing and optimizing emulsion systems, particularly in oil recovery processes. The findings advance our understanding of CO2/N2-switchable surfactants, offering insights into their potential for sustainable development in the petroleum industry. This research contributes to the optimization of switchable surfactants, providing a foundation for improved emulsification processes in enhanced oil recovery applications.

Viscoelasticity of maxell fluid in a permeable porous channel

This study examines the flow dynamics and heat transfer characteristics of Maxwell fluid in a channel influenced by magnetohydrodynamics (MHD), Joule heating, thermal radiation, and boundary layer suction/blowing effects. The governing partial differential equations (PDEs) for momentum, energy, and concentration are transformed into ordinary differential equations (ODEs) using similarity transformations. The boundary value problem (BVP) is solved numerically using the bvp4c solver in MATLAB, yielding accurate solutions for velocity, temperature, and concentration profiles under various parameters. Key findings reveal that the porous parameter decreases the velocity profile but increases the temperature profile for both suction and blowing effects. Additionally, the MHD, Deborah, and Eckert numbers significantly influence the velocity and temperature profiles differently under these conditions. This study highlights the crucial role of integrating MHD, thermal, and boundary control effects to optimize performance and efficiency in engineering systems involving Maxwell fluids, with applications in polymer processing, biomedical engineering, electronics cooling, oil recovery, and chemical processing.

Thermodynamic analysis of the air separation unit and CO2 purification unit in the semi-closed supercritical CO2 cycle with nearly zero emission

The natural gas-fired semi-closed supercritical CO2 cycle is an efficient oxyfuel combustion power generation technology featuring nearly zero emissions. This study investigated the interaction of the semi-closed supercritical CO2 power unit with the air separation unit (ASU), which supplies O2 for combustion and adiabatic compression heat for the heat recovery process in the power unit, and the CO2 purification unit (CPU), which refines the CO2 in the exhaust gas to 99.97% for enhanced oil recovery (EOR) applications. The detailed thermodynamic models of the power unit, ASU, and CPU have been constructed to explore the impact of variations in oxygen purity and excess oxygen coefficient on the overall thermodynamic performance of the system. The results demonstrate that the net electric efficiency peaks at an oxygen purity of 98%, and a one percent decrease in oxygen purity reduces the net electrical efficiency by approximately 0.36% to 0.97% points. Moreover, the net electric efficiency decreased by 0.10% points when the excess oxygen coefficient increased from 3.00% to 13.67%. These findings may offer valuable guidance for developing oxyfuel combustion power generation technologies.

Dynamic-Permeability Variations Induced During CO2-EOR Application in Carbonate Reservoirs: Upper Red River Formation, North Dakota

Summary Carbonate-based mineral dissolution and precipitation, driven by carbon dioxide (CO2) injection, introduces complexities to carbonate reservoir systems that trigger interactions different from those seen in traditional CO2-enhanced oil recovery (CO2-EOR) applications in siliciclastic/sandstone reservoirs. The thrust of this paper is to couple experimental (laboratory-scale) and numerical (computationally-assisted) analyses in order to assess how CO2-induced petrophysical alterations impact the resultant hydrocarbon recovery from CO2-EOR applications in carbonate reservoirs. The Upper Red River Formation, located in North Dakota’s Cedar Creek Anticline (CCA) Field, presents significant remaining oil in place (OIP), albeit with a high water saturation from waterflood operations undergoing since the 1960s. The residual oil saturation (post-waterflooding) makes the Upper Red River Formation a good target for modern-day CO2-EOR technology. The first part of this study involves a core-scale investigation of dynamic-permeability variations triggered by the CO2 injection into three primary-productive zones, designated as “Red River Units” (RRU2, RRU4, and RRU6). The second part involves a compositional reservoir model used to perform numerical simulations of CO2 injection incorporating pre-established dynamic-permeability variations that honor the laboratory-obtained results. Correlations between differential-pressure variations observed during carbonated brine (CO2/brine mixture) injection were assessed against pore volumes injected (PVI). These pressure fluctuations were induced by dynamic-permeability variations resulting from carbonate-based mineral dissolutions/precipitations. Baseline-permeability variations were established a priori using nitrogenated-brine (N2/brine) injection to correct for physicochemical effects from the brine. During CO2/brine injection, the recorded permeability increased significantly compared to its original value, peaking before sharply decreasing. Inductively coupled plasma optical emission spectrometry (ICP-OES) and scanning electron microscopy (SEM) were utilized for deciphering the triggers of these dynamic-permeability variations, which revolve around mineral dissolutions and precipitations following the carbonate rock’s exposure to CO2. The history-matched compositional reservoir model was used to project the incremental production from CO2-EOR through a section incorporating four existing wells, incorporating the laboratory-derived dynamic-permeability variations, yielding different results compared with “base case” simulations performed at constant permeability. Reduced reservoir permeability correlated with decreased oil recovery, emphasizing the significant impact of dynamic-permeability variations on CO2-EOR performance and hence the importance of their integration in fieldwide development analyses.

A CO2-Modified Surfactant for Chemical Flooding

Summary Carbon dioxide (CO2) modification of a nonionic surfactant alkyl polyglycoside (C-APG) was conducted based on a commercial APG product under mild synthesis conditions, including a low temperature (50°C) and a low pressure (2.5 bar). Using this method, CO2 was incorporated into APG molecules through the formation of carbonyl structures. The effectiveness and performance of C-APG as a novel surfactant for enhanced oil recovery (EOR) application in carbonate reservoirs were investigated and compared with its precursor—the unmodified APG. The key factors in the chemical structure of C-APG were characterized by Fourier transform infrared spectroscopy (FTIR) to confirm successful CO2 modification. The properties, including compatibility, surface tension, wettability alteration, interfacial tension (IFT), phase behavior, and static and dynamic adsorption of both APG and C-APG, were evaluated by various techniques and methods. Crude oil displacement efficiency of the surfactants was investigated via spontaneous imbibition, visualized micromodel, and coreflooding tests, respectively. Both surfactants were compatible with a high-salinity water (HSW), they exhibited a similar critical micelle concentration (CMC) of 8.5 mg/L and 13.5 mg/L for APG and C-APG, respectively, and had the same contact angle of around 135°. Interestingly, C-APG was found more effective in reducing IFT between oil and water phases. The IFT of oil in the C-APG solution was 0.058 ±0.001 mN/m, one order of magnitude lower than the value of 0.47 ±0.02 mN/m obtained from the solution of original APG, suggesting a better performance of C-APG in chemical flooding for oil displacement. A Winsor Type I microemulsion was formed by APG within the salinity range, while a transition of Type I to Type II microemulsion was observed for C-APG. The static adsorption of APG and C-APG at 2 g/L in carbonate were 0.93 mg/g rock and 1.08 mg/g rock, and the adsorption decreased to 0.11 mg/g rock and 0.13 mg/g rock under dynamic conditions for APG and C-APG, respectively. The spontaneous imbibition test demonstrated a higher oil imbibition recovery of 18.0% from C-APG solution compared to the result of 10.2% obtained from APG solution. A micromodel test showed that more crude oil was displaced by injection of APG or C-APG solution after waterflooding, while C-APG injection exhibited a stronger emulsification. The oil displacement by coreflood test showed that C-APG injection led to a lower differential pressure and a higher cumulative oil production (48%) compared to APG chemical flooding with a cumulative oil production of 41%. The produced fluids containing displaced crude oil from C-APG flooding, and subsequent waterflooding demonstrated very strong emulsification compared to the fluids produced after APG injection. This study demonstrates the significant potential of C-APG in two aspects—CO2 reduction and chemical EOR for the upstream petroleum industry.

Production of biosurfactant by Bacillus megaterieum using agro-food wastes and its application in petroleum sludge oil recovery.

The objective of this study is to utilize cost-effective renewable substrates derived from agro-food wastes for the production of biosurfactant by Bacillus megaterium, which was isolated from petroleum sludge. Various agro-food waste materials, namely potato peelings (PP), rice cooking water (RW), biscuit by products (BB), carob pods (CP), and eggshells, were evaluated as nutrient sources for bacterial growth compared to a synthetic medium (SM). The results indicate that the medium comprising carob pods, potato peels supplemented with eggshells promoted the growth of the bacteria and the production of Biosurfactants at a rate of 150mg/l and 140mg/l respectively. The biosurfactant exhibited an emulsification index (E24) of 55.23 ± 0.32%, 46.47 ± 3% 43.80 ± 0.4%, 18.33 ± 0.25% and 20 ± 0.11% for PP, CP, SM, BB and RW respectively. The biosurfactant produced from PP had the ability to decrease the surface tension of water from 74 to 39.38 mN/m, with a critical micelle concentration (CMC) of 15mg/L. The chemical characterization of purified biosurfactant was done using Fourier-transform infrared spectroscopy (FTIR) and Thermal gravity (TG), as well as differential scanning calorimetry (DSC) analysis (TG/DSC), revealing the functional groups and thermostability of the biosurfactant. The DSC spectrum for PP biosurfactant showed the highest thermostability with crystalline temperature (Tc) of 150°C and melting point (Tm) of 295°C. The extracted biosurfactant was mixed with petroleum sludge, composed of heavy oil, 40.64 ± 0.19% of extracted oil was obtained after 5h of reaction while using PP based medium.

Optimizing acid microemulsions for cleaner gas production: A study on enhanced adsorption characteristics and implications in retardation

The ultralow interfacial tension between the oil and aqueous phases and the solubilization characteristics in microemulsion systems make them useful for surface cleaning and enhanced oil recovery applications. Microemulsions can form an adsorbed barrier on rock, reducing the acid-rock reaction rate. However, as acid retardation additives, the adsorption patterns of microemulsions are not clearly defined. In this study, microemulsions composed of various electrical surfactants, oil cores, and oil core additives were obtained, and their phase behaviors were investigated. Through adsorption and reaction experiments, cleaning microemulsions that enhance adsorption effects were identified, and their adsorption patterns and adaptability under flow conditions were evaluated. The results demonstrate that incorporating negatively charged polar compounds forms an enhanced adsorption microemulsion characterized by an average droplet size of less than 30 nm after mixing with the acid. The introduction of negatively charged polar compounds resulted in a 177 % increase in adsorption and an 81 % improvement in static retardation effect. Dynamic adsorption tests indicate that the pseudo-second-order model more accurately describes the kinetics of dynamic adsorption of microemulsions on rock surfaces. Under a fixed flow rate, the dynamic retardation rate increased with the concentration of the microemulsion. In practical acidification, the adsorption of microemulsions results mainly from combined electrostatic forces and fluid scouring, characterized by a continuous process of adsorption and desorption. Scanning electron microscope also confirmed that microemulsions can form an adsorptive film on the rock, reducing the acid-rock reaction rate. This study offers practical guidelines for the selection and application of retardation additives, aiming to enhance the ecological compatibility of chemical treatments in low-permeability limestone reservoirs.

Genetically modified indigenous Pseudomonas aeruginosa drove bacterial community to change positively toward microbial enhanced oil recovery applications.

Microbial enhanced oil recovery (MEOR) is cost-effective and eco-friendly for oil exploitation. Genetically modified biosurfactants-producing high-yield strains are promising for ex-situ MEOR. However, can they survive and produce biosurfactants in petroleum reservoirs for in-situ MEOR? What is their effect on the native bacterial community? A genetically modified indigenous biosurfactants-producing strain Pseudomonas aeruginosa PrhlAB was bioaugmented in simulated reservoir environments. Pseudomonas aeruginosa PrhlAB could stably colonize in simulated reservoirs. Biosurfactants (200mg l-1) were produced in simulated reservoirs after bio-augmenting strain PrhlAB. The surface tension of fluid was reduced to 32.1 mN m-1. Crude oil was emulsified with an emulsification index of 60.1%. Bio-augmenting strain PrhlAB stimulated the MEOR-related microbial activities. Hydrocarbon-degrading bacteria and biosurfactants-producing bacteria were activated, while the hydrogen sulfide-producing bacteria were inhibited. Bio-augmenting P. aeruginosa PrhlAB reduced the diversity of bacterial community, and gradually simplified the species composition. Bacteria with oil displacement potential became dominant genera, such as Shewanella, Pseudomonas, and Arcobacter. Culture-based and sequence-based analyses reveal that genetically modified biosurfactants-producing strain P. aeruginosa PrhlAB are promising for in-situ MEOR as well.

Synthesis of amphiphilic silicon quantum dots and its application in high efficiency imbibition oil recovery in low permeability reservoirs

In this work, a novel three-step method was used to modify the surface of silicon quantum dots to synthesize amphiphilic silicon quantum dots (A-SiQDs) with higher interfacial activity. The particle size of A-SiQDs was only 3.5 nm. By adding a small amount of dodecyl dimethyl betaine (BS-12), the performance of A-SiQDs was further improved. Through particle size and zeta potential testing, it can be seen that the mixed system of A-SiQDs and BS-12 had good temperature and salinity resistance, and can be stable at 120 °C and 50,000 mg/L NaCl. Meanwhile, the mixed system exhibited superior interfacial activity compared with individual A-SiQDs and BS-12. The mixed system can lower the interfacial tension from 32.15 mN/m to 1.82 mN/m and transform the rock surface from an oil-wet to a strong water-wet state. This ensured the excellent imbibition ability of the mixed system, which can increase the oil recovery to 35.7 %. Finally, from the perspective of force, the influence of nanofluids on oil stripping and migration was analyzed to reveal the imbibition mechanism. This paper proposes a facile three-step method for synthesizing A-SiQDs, and also provides a novel nanomaterial for high efficiency imbibition in low-permeability reservoirs.

Sustainable potassium-doped graphene oxide from oak fruit agricultural waste for a synergistically improved nanofluid-surfactant slug for enhancing oil recovery

This study presents an eco-friendly solvothermal method for synthesizing potassium-doped graphene oxide (K-GO) from agricultural waste, specifically oak fruit. Various spectrographic analyses, including XRD, FTIR, Raman, and UV–Vis, confirmed the successful synthesis of graphene oxide. The synthesized K-GO was combined with different surfactants to create nanofluids to enhance oil recovery. Anionic sodium dodecyl sulfate (SDS) demonstrated the best performance among the surfactants tested. When 250 ppm of K-GO was added to a 2500 ppm SDS solution, the surface tension was reduced by over 10 %. The study of zeta potential experiments validated that the K-GO-SDS nanofluid is compatible with sandstone reservoirs. Furthermore, the interfacial tension between the K-GO-SDS nanofluid and crude oil decreased by approximately 40 %. Batch adsorption studies showed that the combination of SDS and K-GO significantly reduced surfactant loss to reservoir surfaces by up to 32 %. Additionally, incorporating K-GO resulted in a notable improvement in wettability alteration, with contact angle measurements showing an improvement of over 20°. The sustainable synthesis of potassium-doped graphene oxide (K-GO) facilitates synergistic interactions with sodium dodecyl sulfate (SDS), thereby optimizing the formulation of nanofluids for enhanced oil recovery applications. This combination demonstrates superior efficacy in accessing trapped oil compared to using surfactants alone, highlighting the significant potential of K-GO-SDS nanofluids in advancing oil recovery techniques.

New long tail gemini surfactant in aqueous solution: Self-assembly, rheological properties and responsiveness to hydrocarbon

Gemini surfactants are promising to replace conventional monomeric surfactants in various applications. In this paper, a new gemini surfactant with long unsaturated oleyl tails and bis(hydroxyethyl) ammonium head groups linked by butyl spacer was synthesized. Its critical micelle concentration in salt-free water (12 µM) is much lower than for its monomeric analog (220 µM). Without any additives this surfactant can form viscoelastic solutions with the viscosity of up to 1 kPa·s and elastic modulus of 15 Pa at the conditions, when the viscosity of the single-chained monomeric analog is close to that of pure water. These are one of the highest values reported so far for C18-tailed gemini surfactants without additives. The structure of the gemini surfactant solutions was studied by cryo-TEM and SAXS. Cryo-TEM revealed the presence of closed-looped micelles coexisting with linear wormlike micelles as well as the regular spacing between the micelles arising from strong electrostatic repulsion between them. The SAXS curves were well-fitted by a form-factor of core–shell cylinder, which yielded the radius of the core and the thickness of the shell equal to 1.4 nm each. Addition of n-decane induced the drop of viscosity by 6 orders of magnitude accompanied by the transformation of wormlike micelles into microemulsion droplets with 4.4 nm radius. Such gemini surfactants providing high viscoelasticity to aqueous solution that is responsive to added hydrocarbon are promising for the application in oil recovery as thickeners of fracturing fluids that can be cleaned up without any breakers at the backflow of oil.

Programmable multi-stimulus-responsive whirligig beetle inspired soft robot with multifunctionality based on composite materials

In nature, surfaces are evolutionarily designed to allow species to adapt to their environments. Nowadays, more and more researchers have paid attention to soft robots based on superhydrophobic surfaces. Inspired by the swimming characteristics of whirligig beetles on the surface of water, we propose in this study a multi-stimulus-responsive soft robot that can be driven by light, magnetism and chemistry to achieve fast straight-line motions, turns and rotations on the surface of water. The soft robot is made of a composite material based on graphene oxide (GO) and polydimethylsiloxane (PDMS), which has high hydrophobicity and excellent photothermal properties. With a multi-stimulus-responsive driving mechanism, the soft robot can be used in applications such as oil recovery, cargo transportation, obstacle avoidance, and material dispersion. It is envisioned that this study can guide the development of multi-stimulus-responsive soft robots and offer some useful reference for their applications in water quality monitoring and oil recovery.

Laboratory Investigation on Permeability Change and Economic Analysis Using Some Selected Nanoparticles for Enhanced Oil Recovery

Enhanced oil recovery using nanoparticles is an emerging technique that can potentially alter permeability and wettability of porous media for improved oil mobilization. This study experimentally investigates the permeability alteration caused by three commonly used nanoparticle types – copper (ii) oxide, zinc oxide and silicon oxide. Core flooding experiments were conducted on reservoir rock samples before and after treatment with nanoparticle dispersions. Results show decrease in permeability by 35% for copper (ii) oxide, 30% for zinc oxide and 10% silicon oxide respectively. Pore-scale analysis indicates that permeability change occurs through mechanisms like pore throat blocking/wettability alteration. Nanoparticle concentration is also found to influence the permeability variation, with optimal dosage. Among the systems tested, Silicon oxide is the most effective formulation for enhancing oil recovery applications based on its ability to recover oil with minimal alteration to formation permeability. From the result, Silicon oxide had a cumulative recovery of 17ml, 18.0ml and 18.5ml thereby generating a percentage recovery of 73.91%, 78.26% and 80.43% while Zinc oxide had a cumulative recovery of 15.5ml, 18.0ml and 16.5ml thereby generating a percentage recovery of 77.50%, 78.26% and 71.74ml%, lastly Copper (ii) oxide had a cumulative recovery of 16.5ml, 17.0 and 16.0 generating a percentage recovery of 75%, 73.91% and 72.72% respectively with a concentration of 0.1%, 0.3%, and 0.5%. This study demonstrates the potential of Silicon oxide nanoparticles for enhanced oil recovery through permeability manipulation in porous media, however, the economic analysis shows that it’s quite expensive due to its cost of production and won’t be ideal for use. Hence Zinc oxide which also has a high volume of oil recovery, and less production cost can be used.

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

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

Understanding the Factors Affecting the Adsorption of Surface-Active Agents onto Reservoir Rock in Chemical Enhanced Oil Recovery Applications: A Comprehensive Review

Understanding the Factors Affecting the Adsorption of Surface-Active Agents onto Reservoir Rock in Chemical Enhanced Oil Recovery Applications: A Comprehensive Review

Superhydrophobic Co-MOF-based sponge for efficient oil-water separation utilizing photothermal effect

Effectively addressing crude oil spills remains a global challenge due to its high viscosity and limited flow characteristics. In this study, we successfully prepared a modified sponge (PCP@MS) by embedding the photothermal material of Co-HHTP and coating the melamine sponge (MS) with low-surface-energy polydimethylsiloxane (PDMS). The PCP@MS exhibited outstanding hydrophobicity with WCA of 160.2° and high oil absorption capacity of 59–107 g/g. The PCP@MS showed high separation efficiency of 99.2% for various oil-water mixtures, along with notable self-cleaning properties and mechanical stability. The internal micro-nano hierarchical structure on the sponge surface significantly enhanced light absorption, synergizing with the photo-thermal conversion properties of Co-HHTP, enabled PCP@MS to achieve a surface temperature of 109.2 °C under 1.0 solar light within 300 s. With the aid of solar radiation, PCP@MS is able to heat up quickly and successfully lowering the viscosity of the surrounding crude oil, resulting in an oil recovery rate of 8.76 g/min. Density functional theory (DFT) calculation results revealed that Co-HHTP featured a zero-gap band structure, rendering advantageous electronic properties for full-wavelength light absorption. This in situ solar-heated absorbent design is poised to advance the practical application of viscous oil spill cleanup and recovery.

Rheological behavior of hydrophobic association polyacrylamides with high salt resistance and corrosion inhibition: Cross-linking modification based on trace dopamine hydrochloride derivatives

Hydrophobic association polyacrylamides (HAPAMs) have great potential for use in polymer flooding because of their unique aggregative, hygroscopic, and other compatible properties; however, their poor solubility in high-salt reservoir environments is one of the drawbacks of current polymers for enhanced oil recovery (EOR) applications. Herein, an amphipathic hydrophobic monomer (hexadecyldimethylallyl ammonium chloride, DMAAC16) and a dopamine hydrochloride-derived monomer (DAAM) were successfully introduced into HAPAM to synthesize novel dopamine hydrochloride-modified hydrophobic association polymers (HAPAMC16D). As a result, HAPAMC16D exhibited not only good comprehensive properties based on its porous network structure but also excellent viscosity due to the presence of the DAAM monomer. When the concentration of the polymer solution was greater than the critical association concentration (CAC), the apparent viscosity reached 614 mPa s at 5 g/L C16D5. Importantly, the salt resistance increased significantly in the representative sodium and calcium ion tests, which was attributed to the degree of chemical cross-linking and the intermolecular hydrophobic bonding force. The temperature and salt resistance tests simulating different environments for EOR showed that C16D4 had an apparent viscosity of 158 mPa s, a retention rate of 28.52 % at 90 °C and a total dissolved solids (TDS) greater than 30,000. Additionally, the weight loss method and electrochemical experiments indicated that the highly salt-resistant hydrophobic association polymers had favorable corrosion inhibition effects, with an inhibition efficiency of up to 99.02 % in the 1 M hydrochloric acid-Q235 carbon steel system. This hydrophobic association strategy provides a new approach for designing highly salt-resistant materials for polymer flooding in harsh reservoir environments.

Investigating the Potential of a Transparent Xanthan Polymer for Enhanced Oil Recovery: A Comprehensive Study on Properties and Application Efficacy

This study delves into the properties and behavior of xanthan TNCS-ST, a specialized variant designed for enhanced oil recovery (EOR) purposes. A notable aspect of this polymer is its transparency and capability to dissolve in high salt concentrations, notably up to 18% total dissolved solids. Various laboratory methods are employed to assess the polymer’s distinctive traits, including transparency, salt tolerance, and high pyruvylation. These methods encompass preparing xanthan solutions, conducting filtration tests, assessing energy consumption, and measuring rheological properties. The findings highlight the influence of salt concentration on xanthan’s filterability, indicating increased energy requirements for dissolution with higher salt and xanthan concentrations. Additionally, this study observes temperature-dependent viscosity behavior in different solutions and evaluates the shear stability of xanthan. A significant and novel characteristic of TNCS-ST is its high salt tolerance, enabling complete dissolution at elevated salt concentrations, thus facilitating the filterability of the xanthan solution with sufficient time and energy input. Core flooding experiments investigate fluid dynamics within porous rock formations, particularly sandstone and carbonate rocks, while varying salinity. The results underscore the substantial potential of the new xanthan polymer, demonstrating its ability to enhance oil recovery in sandstone and carbonate rock formations significantly. Remarkably, the study achieves a noteworthy 67% incremental recovery in carbonate rock under the high salinity level tested, suggesting promising prospects for advancing enhanced oil recovery applications.