Core Flooding Research Articles

Macroscale Modeling of Geochemistry Influence on Polymer and Low-Salinity Waterflooding in Carbonate Oil Reservoirs.

The enhancement of oil recovery (EOR) through low-salinity waterflooding (LSWF) and the emerging hybrid with a polymer (LSP) has proven to be effective at microscale investigations and cost-effective with ease of operation at field-scale tests. Their application in carbonate oil reservoirs, which typically occur oil-wet, presents a particularly essential capacity given that over half of the global oil reserves are hosted in carbonate formation. However, modeling the mechanisms involved to predict and evaluate the performance of low salinity-based EOR at a large scale is complex and requires the integration of geochemistry in reservoir simulation to upscale the interfacial interactions of crude oil, brine, and rock observed at the micrometer scale. This study presents an integrated approach that combines MRST's polymer model with PHREEQC geochemical modeling to simulate LSWF at the reservoir scale. Using single-phase and multiphase experimental flooding data for validation, the coupled model was shown to accurately predict effluent ionic and oil recovery profiles. The simulation of LSWF and LSP both exhibited additional tertiary oil recovery, with LSWF and LSP showing 3 and 2%, respectively, which are consistent with previously reported field and core flooding results. Furthermore, the sequential application of formation water (FW), LSWF, and LSP flooding in secondary mode showed a high increase in oil recovery, with oil recovery percentages of 61, 20, and 19%, respectively. However, the FW results were 50% lower compared to regular core flooding due to upscaling limitations. The modeling of vertical and anisotropic permeability heterogeneity effects showed a positive synergy with low-salinity floodings, resulting in a 4% drop and 3 and 1% increase in FW, LSWF, and LSP, respectively. These findings demonstrate the potential of the coupled MRST-PHREEQC model in accurately simulating hydrogeochemical interactions during LSWF/LSP at the reservoir scale, providing valuable insights for the optimization of low salinity-based EOR strategies in carbonate reservoirs.

Water shutoff treatment of low permeable reservoirs by in situ polymerization: laboratory scale development and verification through core flow experiments

Excessive water generation in oil reservoirs poses economic challenges, diminishing hydrocarbon yield and incurring additional costs for water management. This study focuses on enhancing reservoir conformance control, particularly in low-permeability zones with high water production, where traditional gel-based methods face limitations. The goal is improved penetration into narrow fractures and effective sealing of water-inflow zones through in situ polymerization and sequential cross-linking. The study systematically optimized key polymerization parameters, including initiator/monomer ratios, initiator types, and environmental conditions. Core flooding tests demonstrated a significant 17% increase in original oil recovery, alongside a substantial reduction in permeability. Analytical techniques such as CT scans, thin section scans, SEM, and EDS were employed to assess gel distribution within pores and penetration rates. This in situ polymerization and gelation approach show promise in addressing water production challenges, offering enhanced recovery, and adapting well to diverse reservoir conditions. The comprehensive optimization of polymerization parameters and the use of advanced analytical methods contribute to the study’s potential impact on mitigating economic and operational issues associated with excessive water production in oilfields.

Experimental investigation of copper oxide nanofluids for enhanced oil recovery in the presence of cationic surfactant using a microfluidic model

Microfluidics is an appealing technique for enhanced oil recovery since it offers numerous advantages over traditional core flooding mechanisms due to their realistic representation of reservoir conditions at the microscale. In this work, we investigated the performance of copper oxide-based nanofluids in the presence of a DCMS-8 cationic surfactant. First, copper oxide nanoparticles of an average particle size of 10 nm were synthesized by the sol–gel method and characterized using various characterization techniques. The results indicated that copper oxide and surfactant-based nanofluids reduced the interfacial tension by 54 %, depending on the concentration of nanoparticles in the suspension. Furthermore, the formation wettability alteration was investigated using contact angle measurements, and the results showed that nanofluid was able to reduce the contact angle from 48o to 20o in 10 min. The shear rheological response indicated that the nanofluids could reduce the viscosity of crude oil from 0.48 (Pa s) to 0.31 (Pa s). Notably, the flooding results showed that copper oxide-based nanofluids were able to recover 61 % of the original oil initially in place, with additional recovery rates of 65 % and 72 % when used with cationic surfactants, polyvinyl alcohol (PVA), and polyvinyl pyrrolidone (PVP), respectively. Finally, the fluorescent images confirmed that surfactant-based nanofluid has a higher sweeping efficiency in porous formation. In this study, the use of copper oxide nanoparticles and cationic surfactant has resulted in the creation of captivating and compelling nanofluids that exhibit reasonable stability of nanoparticles in the base fluid and high recovery rates of residual oil.

Study on the Alkali-Free Three-Component Flooding System in the Daqing Oilfield.

ASP flooding is an important method to further improve oil recovery by a large margin. At present, it has entered the stage of industrial application, but there are still problems of scaling in the injection production system and high production maintenance costs. Based on the industrialized mature technology of weak alkali ASP flooding, sodium chloride is used to replace sodium carbonate, and the alkali-free three-component flooding (TC) system in the Daqing Oilfield is developed by mixing with petroleum sulfonate and partially hydrolyzed polyacrylamide. Based on the experiments of viscosity increasing, interface performance, stability, adsorption, and oil displacement effect, the differences between the alkali-free TC system and the weak alkali ASP system are compared and analyzed. The laboratory research results show that both systems are basically the same in terms of viscosity, viscoelasticity, shear resistance, interfacial activity, stability, and flowability. Due to the lack of alkaline water, the adsorption, emulsification, and oil displacement performance of the alkali-free TC system is slightly lower than that of the weak alkali ASP system. The recovery factor of core flooding can be increased by 27.31% over water flooding, which is 2.56 percentage points lower than that of the weak alkali ASP system. On the premise of the same 1% EOR effect, the agent cost of the alkali-free system is 17.02% lower than that of the alkali ASP system. This article innovatively verifies the feasibility of using NaCl instead of Na2CO3 and explains the mechanism of significantly improving oil recovery in composite systems under alkali-free conditions from the ion level. However, the emulsification effect of the alkali-free TC system is relatively weak. The next step of research would be to consider adding an E-surfactant to enhance the emulsification performance of the composite system. By improving the system composition, technical references are provided for the efficient development of other terrestrial sandstone oilfields.

An Experimental Investigation of Interaction between CO2 Solution and Rock under Reservoir Conditions in the Jimsar Shale Oil Formation

Chemical sequestration is one important manner of CCUS. The injection of CO2 into an oil reservoir can not only sequestrate CO2 but also raise the oil recovery factor. The performance of chemical sequestration of CO2 depends on the interaction between CO2 solution and reservoir rock. In this paper, we have conducted three different scales of experiments, e.g., microscopic scale, core scale, and time scale, to fully investigate the interaction and resultant variation to mineral content, microscopic structure, porosity, and permeability under reservoir conditions (i.e., reservoir temperature of 90 °C) in Jimusar shale oil formation. The microscopic-scale experiment applied SEM and hyperspectral scanning to obtain microscopic pore throat structure and element distribution before and after soaking the rock in CO2 solution. The core-scale experiment employed XRD to evaluate mineral content variation caused by CO2 solution. Core flooding experiments were conducted to evaluate porosity and permeability variation caused by the dissolution of CO2 solution into the core samples. The third type of experiment was employed to investigate the effect of time sequence on the dissolution, in which the time ranged from 1 day to 14 days continuously. The experimental results indicate that, under Jimsar reservoir conditions, CO2 solution exhibits a relatively robust dissolution capability, causing significant alterations to the properties of the core samples. Specifically, the CO2 solution effectively dissolves carbonate upon contact. Calcite is the primary target for dissolution, followed by dolomite. In the presence of sufficient CO2, complete dissolution of all carbonates is achievable. On a microscopic scale, dissolution primarily occurs in the calcium-rich areas, leaving other regions unaffected. The typical pore size resulting from CO2 solution-induced dissolution ranges from several to dozens of micrometers. This dissolution process significantly enhances both porosity and permeability. For Jimsar shale core samples, porosity experienced an increase of over 20%, and permeability nearly doubled. Under Jimsar reservoir conditions at 90 °C, CO2 solution can consume all carbonates present in core samples within 8 days. The increase in porosity and permeability is rapid during the initial days and stabilizes around the 6th day. These research findings establish a theoretical foundation for CO2 chemical sequestration.

Design and analysis of KA-130, the marine-based SMR for icebreakers

Designed for icebreakers, the KA-130 integral SMR provides a carbon-free solution for navigating the North Pole Route with nuclear propulsion. As an integral reactor, all primary components are integrated into the reactor pressure vessel, eliminating large-break loss-of-coolant accidents and enhancing reactor safety. The study evaluates its load following capability and demonstrates efficient load changes within two minutes. The safety analysis during small break loss-of-coolant accidents (SBLOCA) incorporates ship movements into the minimum critical heat flux ratio (MCHFR) calculations and includes a sensitivity analysis to identify significant scenarios. The most limiting case was the guillotine break at the safety injection line with low initial pressure, high core exit temperature and bottom-peaked core. The analysis shows that core flooding is maintained, and decay heat removal is successfully performed. Acceptance criteria, aligned with regulatory and KA-130 specific standards, ensure safety during and after SBLOCA, meeting MCHFR and collapsed water level conditions above the core.

Rock structural changes monitored by fibre Bragg Grating sensors and Nuclear magnetic Resonance during static and dynamic carbonated brine core flooding experiments

One proposed solution to reduce greenhouse gas emissions is the capture and storage of carbon dioxide (CCS) in geological formations such as depleted oil and gas reservoirs. Injected carbon dioxide (CO2) forms carbonic acid once dissolved in the formation water, which can lead to dissolution of certain types of rock minerals. This may weaken rock geomechanical properties that can jeopardize the safety of long-term storage. In this work, the use of Fibre Bragg Grating (FBG) sensors associated with Nuclear Magnetic Resonance (NMR) was investigated to measure the change in rock strain during core flooding experiments. Optical fibres were glued onto two synthetically calcite cemented sandstone rock samples (called CIPS). The samples were saturated with dead brine followed by live brine.The FBG sensors accurately monitored a change of approximately −30 µstrain during dead brine migration at a fast rate within 10–20 min, and then the FBG strain became constant when the sample reached 100% saturation. Exposing the CIPS to live brine induced up to −1000 µstrain in a dynamic injection exercise and – 250 µstrain in the static condition, these changes occurred after 5 h exposure, which was interpreted as the result of fluid-rock interactions occurred within the sample. Those changes continued to increase over the next 35 h, albeit at lower rate. The NMR T2, spatial T2 and FBG data confirmed structural changes within the rock samples. X-ray Computer Tomography (CT) imaging also supported the structural change at certain locations in the sample while featuring good agreement with FBG results.Overall, FBG sensing technology associated with NMR can accurately measure the changes in rock strain during core flooding experiments, while allowing it to monitor the reservoir’s geo-mechanical strength which is a key factor to ensure the long-term safety of CO2 storage.

Methane foam performance evaluation in fractured oil-wet carbonate systems at elevated pressure and temperature conditions

This study investigates the potential of foam flooding for enhanced oil recovery in oil-wet fractured systems under reservoir conditions. Two surfactants with distinct ionic properties were employed in combination with methane to generate foam via simultaneous injection into propped fractures, aiming to optimize the diversion of gas from fractures to the matrix for improved oil recovery. Core flooding experiments demonstrated the critical roles of total injection rate and foam quality in controlling foam performance. Increasing the total injection rate from 1 to 3 cm³/min enhanced foam generation rates and foam lamella stability, facilitating better interactions between fractures and the matrix. However, beyond an injection rate of 4 cm³/min, there was a decline in apparent viscosity and mobility reduction factor. Foam strength was directly proportional to higher foam quality within the 50 to 80% range, but beyond 85% foam quality, fluctuations in pressure drop signaled the formation of weaker, less stable foams. Micro-scale experiments validated these macroscopic findings, revealing that smaller bubbles were associated with higher flow rates and lower foam qualities. This research contributes valuable insights into both micro and macro-scale in-situ foam generation, which can inform the design and application of foam-based enhanced oil recovery methods in fractured reservoirs.

Chemical enhanced oil recovery under Harsh conditions: Investigation of rock permeability and insights from NMR measurements

Injecting surfactant into a hydrocarbon reservoir stands out as a highly effective method for EOR due to its ability to reduce water/oil IFT and alter rock wettability in certain cases. However, the efficiency of this process is compromised in heterogeneous reservoirs, especially carbonates, characterized by significant permeability variations. This study presents findings from three core flooding experiments on heterogeneous carbonate core samples with different permeabilities. The experiments were conducted under representative reservoir conditions of 100 °C, pressures higher than 3000 psi, and seawater salinities and formation water of 57,745 ppm and 213,768 ppm, respectively. In each experiment, seawater was continuously injected followed by continuously injecting a 2500-ppm solution of in-house synthesized Gemini surfactant. Results revealed that the recovery factor was highest in low-permeability rocks and lowest in high-permeability rocks for both seawater and surfactant floods. Surfactant floods yielded additional recoveries of 31%, 23%, and 19% for low, medium, and high-permeability samples, respectively. Nuclear magnetic resonance (NMR) analysis on short analogous core plugs at different flooding stages confirmed these results. Effluent analysis on the produced aqueous phase indicated that dynamic retention was highest (0.467 mg/gm-rock) in the lowest permeability and lowest (0.146 mg/gm-rock) in the highest permeability rock. NMR analysis suggested that the surfactant's recovery performance and dynamic retention were influenced by the larger surface area of low-permeability rocks, facilitating increased contact with the surfactant. Utilizing NMR monitoring in this work enhances EOR insights through integrated studies and coreflooding experiments and establishes a novel framework for complex reservoir conditions.

Using X-ray computed tomography and pore-scale numerical modeling to study the role of heterogeneous rock surface wettability on hydrogen-brine two-phase flow in underground hydrogen storage

Underground hydrogen storage (UHS) is receiving increasing attention to address the challenges in hydrogen storage. A crucial aspect of UHS is understanding the transport of hydrogen in subsurface porous media. In this work, hydrogen core flooding experiments were conducted in a sandstone sample and then the pore-scale distribution of hydrogen and brine was visualized using high-resolution X-ray micro-computed tomography (micro-CT). After CT image processing, we measured the surface contact angles (CAs) on rock surfaces and found that the measured CAs followed a log-normal distribution. To investigate the influence of rock surface wettability on the transport properties in the hydrogen-brine-sandstone system, the lattice Boltzmann (LB) method was used to simulate two-phase flows with different surface CA distributions; hydrogen-brine relative permeability and capillary pressure curves through the primary drainage, imbibition, and secondary drainage processes were obtained by LB simulations. X-ray CT scanning showed that hydrogen resided in both large pores and small pores and pore throats after the primary drainage process (i.e., hydrogen displacing brine), whereas after the imbibition process (i.e., brine displacing hydrogen) hydrogen stayed primarily in large pores where the capillary pressure barriers were low. The LB two-phase flow modeling illustrated that water’s relative permeability increased whereas hydrogen’s relative permeability decreased when the core flooding moved from primary drainage to imbibition; in contrast, when the core flooding moved from imbibition to secondary drainage, water’s relative permeability decreased whereas hydrogen’s relative permeability increased. Decreasing the surface CA increased the capillary pressure and reduced the hydrogen residual rate, which indicates high hydrogen retrievability and thus is favorable for UHS practice. The change in CA’s standard deviation did not cause noticeable changes in water’s relative permeability curves, whereas it resulted in noticeable changes in hydrogen’s relative permeability curves. This work is the first study that utilizes X-ray micro-CT scanning and pore-scale multiphase flow modeling to quantitatively and comprehensively investigate hydrogen-brine two-phase flow properties under different rock surface wettability distributions. The research findings from this study will advance the understanding of hydrogen transport in an underground storage system and provide essential data for large-scale field studies in UHS.

β-Cyclodextrin modified SiO2 nanofluid for enhanced oil recovery

Recently, with the deterioration of oil storage conditions, the extraction of oil has been limited. In this experiment, β-cyclodextrin (β-CD) was grafted onto the surface of SiO2 nanoparticles. The structure and morphology of nanoparticles were analyzed by various characterization tools to effectively validate the synthesis of nanomaterials. In addition, it was experimentally demonstrated that the developed β-CD-SiO2 nanofluid has excellent stability and salt resistance. Finally, the comparative studies of the nanofluids were carried out by wettability, interfacial tension (IFT), Pickering emulsion, viscosity, and core flooding experiments. The results showed that β-CD-SiO2 nanofluid exhibited better performance: β-CD-SiO2 nanofluid changed the contact angle (CTA) of carbonate plate from 131.5º to 90.1º; the IFT was significantly reduced from about 35 mN/m to 22.5 mN/m; the emulsion droplets formed were fine and dense; the viscosity increased and viscosity not changed with shear rate; and total crude oil recovery up to 59.2%, 23.9% higher than using water drives. Overall, these results showed the great potential of β-CD-SiO2 nanofluid in ultra-low permeability reservoirs.

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.

PENGARUH POLIMER PC DENGAN ADDITIF TWEEN-80 TERHADAP KARAKTERISTIK POLIMER DAN RECOVERY FACTOR PADA MINYAK 39 °API DI BATUAN SANDSTONE

Background: The increasing demand for petroleum and the depletion of oil reserves in oil fields require the development of more efficient oil recovery techniques to enhance oil production. One method that can be employed is Enhanced Oil Recovery (EOR), where chemical injection becomes a viable approach. One chemical injection method that can be used is polymer injection. One suitable polymer for this purpose is cellulose polymer (PC). Cellulose polymer (PC) is the most abundant polymer in nature, a renewable material that is degradable, biocompatible, cost-effective, and non-toxic. Cellulose can be derived from plants and certain types of bacteria.Objective: This research aims to investigate the influence of temperature variations on cellulose polymer (PC) with Tween-80 additive on the Recovery Factor.Methodology: Laboratory experiments were conducted using the core flooding technique with a core holder, applying the slug method with various °API variations on light crude oil with an API gravity value of 39. Sandstone rock samples were used in the experiments, prepared by saturating with brine and oil.Result: The laboratory results showed a recovery percentage of 7.89% at a temperature of 60 °C and 17.86% at a temperature of 80 °C. The highest increase in oil recovery was observed at a temperature of 80 °C, with a recovery factor of 17.86%. In conclusion:, based on the conducted core flooding experiments, the best recovery factor was found in polymer injection using PC with Tween-80 additive at a temperature of 80 °C.

Biphasic interfacial functioning improvement using naturally derived Hop and Dill surfactants in carbonate reservoirs

This study mainly focuses on the application of environmentally friendly surfactants in enhanced oil recovery (EOR). Two natural and environmentally friendly surfactants of Hop and Dill were introduced to observe their visions of fluid/fluid/rock interfacial activity of surfactant solutions as ion tuned EOR method. Investigations of interfacial tension (IFT) reduction and wettability alteration toward a water-wetting tendency were conducted to evaluate the improvement of oil recovery factor. Dynamic displacement tests of carbonate porous medium flooding including both secondary and tertiary flooding were conducted to observe the validity of IFT reduction and wettability alteration (contact angle decrease, CA) effects. IFT measurements showed that Dill and Hop surfactants can reduce the initial IFT of 28 mN/m to 2.443 and 5.614 mN/m, respectively. Ion concentration tuning showed that 10,000 ppm of NaCl is the optimum concentration that could enhance the optimization value of Dill surfactant from 91.27% to 92.8% (with 17.46% improvement compared with CMC of Dill). In addition, NaCl salt at the same concentration improved the effectiveness of Hop surfactant by 6.1%. Meanwhile, the used surfactants reduced the contact angle from 151° to 75° and 65° for Dill and HOP, respectively. Ion tuning showed that 10,000 ppm of salinity effect could enhance the optimization by Dill and Hop to 70.86 and 71.54%, respectively. Zeta potential measurements proved that the contact angle results in a complementary manner. Core flood tests validated previous results through the improvements in the recovery of oil by 8.56 and 10.11% original oil in place (OOIP) for HOP and Dill natural surfactants, respectively.

Surfactant-polymer flood with seawater for a high temperature carbonate reservoir

Developing ultralow tension surfactant formulations for carbonate reservoirs at high temperatures (> 100 °C) in the presence of hard brine is challenging. The target carbonate reservoir had been flooded with seawater and changing of the injection brine (softening or low salinity) for enhanced oil recovery was considered expensive. Seawater was presumed to be the injection brine for this study. The goal of this research work was to develop an ultralow tension surfactant-polymer (SP) formulation with seawater for this carbonate reservoir at 115 °C and to evaluate core floods with and without salinity gradient. Phase behavior was studied for many surfactants and ultralow IFT formulations were identified with the optimal salinity near the seawater salinity. SP core floods were conducted in reservoir sand packs at 115 °C; a novel 2-oven technique was used to collect the effluent with no wax formation and minimal hydrocarbon vaporization. The residual oil saturation was reduced to less than 1% in floods with salinity gradient and about 5% in constant salinity floods (at seawater salinity). The novelty of the work lies in developing SP formulations with seawater at a high temperature and studying the effect of salinity gradient. This process can be considered for many off-shore fields which have been waterflooded with seawater.

Development and performance evaluation of nonionic surfactant-stabilized nanoemulsion for enhanced oil recovery applications in tight reservoir

Nanoemulsions have garnered great attention as a chemical additive for enhanced oil recovery (EOR) technology worldwide due to their small size and unique physicochemical properties. Herein, this work introduces a novel nonionic surfactant-stabilized nanoemulsion prepared using a low-energy method for EOR projects in the Chang 8 tight reservoir. Spontaneous imbibition experiments were conducted in oil-saturated cores, and secondary imbibition experiments were carried out in water-bearing cores. Additionally, core flooding experiments were performed to study the EOR performance of both nanoemulsion and complex surfactant. Finally, the EOR mechanisms were thoroughly investigated, specifically focusing on oil-washing capacity, reduced interfacial tension, and wettability alteration. The designed nanoemulsion, with droplets averaging 10.5 ± 0.7 nm in synthetic formation brine at ambient temperature, exhibits excellent thermal and long-term stability even under reservoir temperature conditions. The oil recovery efficiency of the nanoemulsion system in oil-saturated cores through spontaneous imbibition was 31.28%, representing a 6.42% improvement over the complex surfactant solution. In the secondary imbibition experiments, the nanoemulsion mobilized 8.53% of the residual oil, compared to 4.11% for the complex surfactant. Core flooding experiments revealed that the nanoemulsion system achieved a total oil recovery of 62.69%, outperforming the complex surfactant system by 8.68% during the chemical flooding stage and 1.82% during the subsequent brine flooding stage. The EOR mechanisms of nanoemulsion in tight reservoirs can be attributed to four aspects: reduction of oil/water interfacial tension, wettability alteration, miscibility with crude oil, and increased sweep volume. The generation of the Marangoni effect and the adsorption and diffusion characteristics are essential differences between the nanoemulsion system and the complex surfactant system. The presented findings in this paper could aid in promoting the large-scale use of nanoemulsions in Chang 8 tight reservoirs.

Wettability alteration of oil‐wet carbonate rocks by chitosan derivatives for application in enhanced oil recovery II: High‐temperature and high‐pressure conditions—Core flooding tests

AbstractBiopolymers, serving as Enhanced Oil Recovery (EOR) agents, are posing challenges and opportunities within the oil industry, particularly in demanding operational conditions. The assessment of trimethyl chitosan (TMC) and its hydrophobized derivative with myristoyl chloride (TMC‐C14) becomes crucial in these rigorous scenarios, presenting a significant challenge for polymer flooding. The study subjected TMC and TMC‐C14 to comprehensive evaluations as EOR agents, employing contact angle measurements, interfacial tension tests using the Drop Shape Analyzer (DSA), and core flood tests under conditions of 60°C, 1000 psi, and elevated salinity. Relative permeabilities were deduced from the results, while spontaneous imbibition tests provided insights into rock wettability. Amott cell tests underscored that both TMC and TMC‐C14 induced accelerated spontaneous oil production within a span of 30 days. Notably, TMC‐C14 exhibited superior interfacial activity compared to TMC, attributed to its hydrophobic segments. The impact on rock wettability was distinct: TMC shifted it towards water‐wet, while TMC‐C14 induced a neutral‐wet condition. This transformation was corroborated by contact angle measurements, imbibition tests, and relative permeability curves. Capillary forces, computed from DSA data and spontaneous imbibition tests, further validated the wettability‐altering tendencies of the chitosan derivatives on the rock. In core flooding tests and relative permeability curves, TMC demonstrated a notable improvement in the recovery factor (RF) compared to seawater. Specifically, RFTMC achieved 69%, surpassing RFbrine at 49%, affirming that the primary mechanism of action for chitosan derivatives lies in their ability to modify rock wettability. This study shows the potential of TMC and TMC‐C14 as effective EOR agents, shedding light on their interfacial activities, impact on rock wettability, and enhanced recovery factors in challenging operational conditions.

Laboratory investigation and core flood demonstration of enhanced biogenic methane generation from lignite.

Over the last several decades, coalbed methane (CBM) has emerged as an important energy source in developing nations like India as well as worldwide and is expected to play a significant role in the energy portfolio of the future. The current scenario of rapid exhaustion of fossil fuels is leading to the need to explore alternative and efficient fuel resources. The present study demonstrates enhanced methane production per gram of lignite (lowest-rank coal). Optimization of the bioconversion of lignite to methane revealed 55°C temperature and 1.5g/L NaCl concentration as ambient conditions for the process. A scale-up study in the optimized condition showed 2,800mM methane production per 25g of lignite in anaerobic conditions. Further, Fourier transform Infrared (FTIR) and Gas Chromatography Mass Spectrometry (GCMS) analysis showed bioconversion of lignite into simpler intermediate substrates required for methane production. The results highlighted that the bacterial action first converts lignite into volatile fatty acids, which subsequently get converted into methane. Further, the exploration of indigenous microbial consortia in Tharad well (THAA) mainly comprises the order Methanosarcinales and Methanomicrobiales. The pathogenicity of the microbial consortium THAA was declared safe for use in mice via the oral route by The Energy and Resources Institute (TERI), India. The study demonstrated the development of indigenous consortia (TERI THAA), which can potentially enhance methane production from the lowest coal grade under extreme conditions in Indian coal beds.

Evaluation of Profile Control and Oil Displacement Effect of Starch Gel and Nano-MoS2 Combination System in High-Temperature Heterogeneous Reservoir.

The Henan Oilfield's medium-permeability blocks face challenges such as high temperatures and severe heterogeneity, making conventional flooding systems less effective. The starch gel system is an efficient approach for deep profile control in high-temperature reservoirs, while the nano-MoS2 system is a promising enhanced oil recovery (EOR) technology for high-temperature low-permeability reservoirs. Combining these two may achieve the dual effects of profile control and oil displacement, significantly enhancing oil recovery in high-temperature heterogeneous reservoirs. The basic performance evaluation of the combination system was carried out under reservoir temperature. Displacement experiments were conducted in target blocks under different permeabilities and extreme disparity core flooding to evaluate the combination system's oil displacement effect. Additionally, the displacement effects and mechanisms of the starch gel and nano-MoS2 combination system in heterogeneous reservoirs were evaluated by simulating interlayer and intralayer heterogeneity models. The results show that the single nano-MoS2 system's efficiency decreases with increased core permeability, and its effectiveness is limited in triple and quintuple disparity parallel experiments. After injecting the starch gel-nano-MoS2 combination system, the enhanced oil recovery effect was significant. The interlayer and intralayer heterogeneous models demonstrated that the primary water flooding mainly affected the high-permeability layers, while the starch gel effectively blocked the dominant channels, forcing the nano-MoS2 oil displacement system towards unswept areas. This coordination significantly enhanced oil displacement, with the combination system improving recovery by 15.33 and 12.20 percentage points, respectively. This research indicates that the starch gel and nano-MoS2 combination flooding technique holds promise for enhancing oil recovery in high-temperature heterogeneous reservoirs of Henan Oilfield, providing foundational support for field applications.

Enhanced oil recovery by using modified ZnO nanocomposites in sandstone oil reservoirs

Recently, nanocomposites were employed to improve the extraction of oil in different reservoirs. Due to the unique characteristics of nanoparticles such as small size, efficient altering main mechanisms such as IFT, CA, and viscosity reduction, have received wide attention among researchers. This study investigated the application of a newly designed ZnO-cerium N-composite for EOR at reservoir conditions, and the performance was compared to the standalone ZnO nanoparticles. After performing the morphology of the N-composite, the effect of the N-composites on the wettability alteration, interfacial tension, viscosity, Zeta potential, pH, and density was studied at different N-composites concentrations at reservoir conditions. Based on the results of rock/fluid interactions at the static phase, an optimum concentration was chosen for performing dynamic core flooding experiments. At 100 ppm, the highest stability and the highest reduction in capillary force were observed. The presence of Ce in the structure of the N-composite changes the pore volume of ZnO-Ce compared to ZnO nanoparticles, which affects the surface charge. IFT (mN/m), CA (°), and zeta potential (mV) were (22.51, 40.83, and − 44.36), and (30.50, 50.21, and − 31.05) for ZnO-Ce and ZnO, respectively at 100 ppm. By application of the optimized nanofluid in an oil displacement study, RF in the presence of ZnO-Ce, and ZnO were 37.11% and 71.40%, respectively.