Enhanced Oil Recovery Research Articles

Impact of the Hydrophobic Phase on the Interfacial Dilational Rheology of Alkoxy Carboxylate/Cetyltrimethyl Ammonium Chloride Mixtures.

Despite extensive investigations on the interfacial activities of mixed anionic and cationic surfactants (Sa/c), the influence of the hydrophobic phase on their interfacial assembly and dilational rheology remains unaddressed. In this study, the interfacial dilational rheology of alkoxy carboxylate (anionic)/cetyltrimethylammonium chloride (cationic) surfactant mixtures was studied at various interfaces. The dilational modulus of Sa/c increases linearly with interfacial pressure at the interfaces of air, n-hexane/n-octane/n-hexadecane, and toluene. The limit elasticity (ε0) is similar at air and alkane interfaces but significantly decreases at the toluene interface. To explain these phenomena, all-atom molecular simulation was carried out to investigate the microscopic features of surfactants at the interface. The findings emphasize the crucial role of anionic/cationic surfactant bound pairs in regulating interfacial rheology. Sa/c tend to form large aggregates at the air/water surface. When mixed with alkanes like octane, most Sa/c remain as ion pairs. However, when toluene is employed, the coordination number between anionic and cationic surfactants sharply decreases due to π-π interactions between the toluene molecules and the phenyl groups in the anionic surfactant. This leads to a much lower interfacial modulus because interactions between oil molecules and surfactants cannot compensate for weakened interactions among anionic/cationic surfactants. These results suggest that Sa/c in this study tolerate alkanes but are not resistant to aromatics, which helps explain why Sa/c demonstrate excellent performance for the chemical enhanced oil recovery of a high-wax reservoir and further provides fundamental knowledge of their potential applications, such as gas well deliquification using foamers in the presence of condensate oil, textiles, etc.

Experimental Study on Improving the Recovery Rate of Low-Pressure Tight Oil Reservoirs Using Molecular Deposition Film Technology

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods.

Heuristic algorithm for calculating the component composition of recombination gas without an adapted equation of state

Background. To conduct laboratory research of projects of gas enhanced oil recovery methods, a large volume of reservoir system is required. Often its replenishment by depth and/or separator samples is not economically feasible. Therefore, the task of fluid recombination from wellhead liquid sample and natural gas simulator arises. Objective. To calculate the component composition of recombination gas under the conditions of the task. Materials and methods. The heuristic calculation algorithm uses the tools of: modeling, inverse problems of physics, set theory, mathematical programming. Special focus is given to its empirical and theoretical justification. Results. The paper considers the limitations of the thermodynamic method. The conditions of the problem to be solved are outlined and justified. The applied algorithm of the solution is formulated and derived. The efficiency of the algorithm for oil systems is experimentally confirmed. Conclusions. The work will be of interest for specialists in the field of laboratory research projects of gas enhanced oil recovery methods. The issues of improving the accuracy of the applied algorithm and its further development are still under discussion.

Biosurfactants: Chemical Properties, Ecofriendly Environmental Applications, and Uses in the Industrial Energy Sector

The exploitation of nature and the increase in manufacturing production are the cause of major environmental concerns, and considerable efforts are needed to resolve such issues. Oil and petroleum derivatives constitute the primary energy sources used in industries. However, the transportation and use of these products have huge environmental impacts. A significant issue with oil-related pollution is that hydrocarbons are highly toxic and have low biodegradability, posing a risk to ecosystems and biodiversity. Thus, there has been growing interest in the use of renewable compounds from natural sources. Biosurfactants are amphipathic microbial biomolecules emerging as sustainable alternatives with beneficial characteristics, including biodegradability and low toxicity. Biosurfactants and biosurfactant-producing microorganisms serve as an ecologically correct bioremediation strategy for ecosystems polluted by hydrocarbons. Moreover, synthetic surfactants can constitute additional recalcitrant contaminants introduced into the environment, leading to undesirable outcomes. The replacement of synthetic surfactants with biosurfactants can help solve such problems. Thus, there has been growing interest in the use of biosurfactants in a broad gamut of industrial sectors. The purpose of this review was to furnish a comprehensive view of biosurfactants, classifications, properties, and applications in the environmental and energy fields. In particular, practical applications of biosurfactants in environmental remediation are discussed, with special focus on bioremediation, removal of heavy metals, phytoremediation, microbial enhanced oil recovery, metal corrosion inhibition, and improvements in agriculture. The review also describes innovating decontamination methods, including nanobioremediation, use of genetically modified microorganisms, enzymatic bioremediation, modeling and prototyping, biotechnology, and process engineering. Research patents and market prospects are also discussed to illustrate trends in environmental and industrial applications of biosurfactants.

Slow release of surfactant by smart thermosensitive polymer-functionalized mesoporous silica for enhanced oil recovery: Synthesis and characterization

The efficiency of surfactant flooding can be improved through slow-release technology, which enables stimuli-sensitive and gradual release of surfactant. In this study, we synthesized a novel nanocomposite capsule composed of mesoporous silica functionalized with thermosensitive poly N-vinyl caprolactam (PNVCL). Well-optimized nanocarriers were synthesized by conducting sensitivity analyses on key synthesis parameters such as pH, reaction duration, and hydrophobic phase, resulting in hydrodynamic diameters ranging from 47 to 109 nm. Characterization of the nanocarrier structure was performed using dynamic light scattering (DLS), Brunauer–Emmett–Teller (BET) analysis, and field emission scanning electron microscopy (FESEM), while Fourier-transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), and energy-dispersive X-ray spectroscopy (EDS) were employed to analyze the nanocarrier composition. Poly N-vinyl caprolactam (NVCL)-functionalized mesoporous silica exhibited high surfactant loading (approximately 52 % w/w) and a large specific surface area (542.88 m2/g), featuring ink-bottle pores. Additionally, it demonstrated thermosensitive behavior, with the lower critical solution temperature of 39 °C. Gradual release of cetyltrimethylammonium bromide (CTAB) was observed in both deionized water and formation brine, with release rates increasing with temperature. Overall, the synthesized nanocomposite carrier holds significant potential as an ideal candidate for effectively controlling the release of surfactants in reservoirs subjected to high-temperature and high-salinity conditions.

Chemical enhanced oil recovery from shale‐rich tight carbonate reservoirs using 2‐butoxyethanol as a mutual solvent and diluted seawater

AbstractOil production from tight reservoirs due to their very low permeability and high capillary pressure requires complex operations and materials, so that hydraulic fracturing in these reservoirs is recommended before any chemical injection. This operation turns the reservoir into a fractured one that can produce more oil by activating the imbibition mechanism. The interfacial tension (IFT) of oil and water and reservoir rock wettability as key parameters of overproduction from this type of reservoir can affect this mechanism. In this study, the potential of 2‐butoxyethanol as a mutual solvent for enhanced oil recovery (EOR) was investigated with a focus on the oil production under imbibition in this type of reservoir through performing experiments and calculations of IFT, oil swelling, contact angle, and oil production. The analysis of the results shows that the mechanisms of IFT reduction, wettability alteration, and oil swelling, which all directly affect the oil production under imbibition, reached the desired values using 2‐butoxyethanol in the appropriate concentration along with the dilution of seawater. The lowest values for interfacial tension and contact angle at 0.03 M concentration of the solvent and 5000 ppm salinity at 90°C temperature were 1.315 mN/m and 71.57°, respectively. These values are much lower compared to the values obtained by similar additives, while solvents, unlike 2‐butoxyethanol, are effective in much higher volume ratios. The oil swelling increased by about 14% using 2‐butoxyethanol due to its mass transfer between water and oil phases through the interface. Finally, the oil recovery factors of 42% and 59% were achieved under one‐ and multi‐dimensional spontaneous imbibition (ODSI and MDSI), respectively.

Application of MgO based‐nanofluid for controlling the growth of asphaltene flocs under static and micromodel dynamic conditions

AbstractIn this study, the impact of magnesium oxide (MgO) nanoparticles on the control of asphaltene aggregates growth was examined. The investigation began with static testing, followed by dynamic testing, where nanofluid was injected into a constructed glass micromodel simulating a porous medium. The results obtained from light microscopy and asphaltene dispersant tests demonstrated that the MgO nanoparticles with an average diameter of 50 nm postpone the asphaltene onset point (AOP) and delay the growth of asphaltene aggregates in crude oil. Also, the results obtained from these experiments illustrated the performance of synthesized nanoparticles in various concentrations on inhibition of asphaltene deposit in the crude oil medium, in the order of 750 > 1500 > 100 > 1000 > 500 ppm. The results from both microscopy and ADT experiments strongly validate the effectiveness of MgO nanoparticles across varying concentrations, highlighting the optimal dosage of 750 ppm. Images of nanofluid flooding at the optimal concentration in the glass micromodel demonstrate effective nanoparticle inhibition and enhanced oil recovery from the porous medium. These findings corroborate the results obtained from ADT and microscopy tests. The results of FT‐IR analysis show the adsorption of asphaltene particles on the surfaces of MgO nanoparticles in wavelengths of 2900–3000 cm−1. Moreover, dynamic light scattering (DLS) analysis results indicated that the average diameter of suspended particles was 3580 nm before adsorption and 6230 nm after adsorption, indicating the controlled adsorption of asphaltene onto the surface of MgO nanoparticles. The findings from this study can be applied to manage asphaltene formation across all stages of oil processing and production.

Mono- and di-rhamnolipids mixtures from Pseudomonas aeruginosa for use in extreme conditions of pre- and post-salt oil reservoirs compared with synthetic surfactants

Rhamnolipids are multipurpose molecules known as natural glycolipid biosurfactants that are often biosynthesized by Pseudomonas aeruginosa strains. They are readily biodegradable, have less impact on the environment and are less toxic than conventional surfactants. They can be applied in ex situ microbial enhanced oil recovery. However, there is still a lack of knowledge concerning the drastic environmental conditions of post and pre-salt reservoirs. In this study, different mixtures with different proportions of homologs of rhamnolipids from two genetically modified strains (GMOs) of P. aeruginosa and a non-GMO strain compared to commercial surfactants (Arquad C-50 and/or Ultrasperse II®) regarding their efficiency under high pressure, temperature and salinity conditions. Wettability reversal and interfacial tension tests were performed together with central composite rotational designs. Both genetically modified P. aeruginosa strains produced mainly di-rhamnolipids, whereas the non-GMO strain produced approximately 50 % mono- and 50 % di-rhamnolipids. Rhamnolipids and Arquad C-50 reversed 100 % of the wettability under pre-salt and post-salt conditions, whereas Ultrasperse II® achieved 73.3 % and 34.2 % (100 ppm) wettability, respectively. Interfacial tension presented the lowest values for rhamnolipids, with values of 0.4 mN/m and 0.5 mN/m, whereas Ultrasperse II® presented values of 2.6 and 2.5 mN/m, respectively under post-salt and pre-salt conditions at the +1 level of the tested variables. All rhamnolipid congeners tested here were more effective under post and pre-salt reservoirs conditions than commercial surfactants, thus expanding their potential for use not only in environmental bioremediation but also in oil industry processes.

Exploring the Impact of Mineralogy on Pore Structure and Fluid Dynamics in Tight Reservoir Rocks: Insights for Enhanced Oil Recovery and Gas Storage

Exploring the Impact of Mineralogy on Pore Structure and Fluid Dynamics in Tight Reservoir Rocks: Insights for Enhanced Oil Recovery and Gas Storage

Geochemistry in Geological CO2 Sequestration: A Comprehensive Review

The increasing level of anthropogenic CO2 in the atmosphere has made it imperative to investigate an efficient method for carbon sequestration. Geological carbon sequestration presents a viable path to mitigate greenhouse gas emissions by sequestering the captured CO2 deep underground in rock formations to store it permanently. Geochemistry, as the cornerstone of geological CO2 sequestration (GCS), plays an indispensable role. Therefore, it is not just timely but also urgent to undertake a comprehensive review of studies conducted in this area, articulate gaps and findings, and give directions for future research areas. This paper reviews geochemistry in terms of the sequestration of CO2 in geological formations, addressing mechanisms of trapping, challenges, and ways of mitigating challenges in trapping mechanisms; mineralization and methods of accelerating mineralization; and the interaction between rock, brine, and CO2 for the long-term containment and storage of CO2. Mixing CO2 with brine before or during injection, using microbes, selecting sedimentary reservoirs with reactive minerals, co-injection of carbonate anhydrase, and enhancing the surface area of reactive minerals are some of the mechanisms used to enhance mineral trapping in GCS applications. This review also addresses the potential challenges and opportunities associated with geological CO2 storage. Challenges include caprock integrity, understanding the lasting effects of storing CO2 on geological formations, developing reliable models for monitoring CO2–brine–rock interactions, CO2 impurities, and addressing public concerns about safety and environmental impacts. Conversely, opportunities in the sequestration of CO2 lie in the vast potential for storing CO2 in geological formations like depleted oil and gas reservoirs, saline aquifers, coal seams, and enhanced oil recovery (EOR) sites. Opportunities include improved geochemical trapping of CO2, optimized storage capacity, improved sealing integrity, managed wellbore leakage risk, and use of sealant materials to reduce leakage risk. Furthermore, the potential impact of advancements in geochemical research, understanding geochemical reactions, addressing the challenges, and leveraging the opportunities in GCS are crucial for achieving sustainable carbon mitigation and combating global warming effectively.

Artificial intelligence‐driven sustainability: Enhancing carbon capture for sustainable development goals– A review

AbstractArtificial intelligence (AI) and environmental points are equally important components within the response to local weather change. Therefore, based on the efforts of reducing carbon emissions more efficiently and effectively, this study tries to focus on AI integration with carbon capture technology. The urgency of tackling climate change means we need more advanced carbon capture, and this is an area where AI can make a huge impact in how these technologies are operated and managed. It will minimize manufacturing emissions and improve both resource efficiency as well as our planet's environmental footprint by turning waste into something of value again. Artificial intelligence could be leveraged to analyze huge data sets from carbon capture plants, searching for optimal system settings and more efficient ways of identifying patterns in the available information at a larger scale than currently possible. In addition, AI incorporated sensors and monitoring mechanisms in the supply chain can identify any operational failure at reception itself allowing for timely action to protect those areas. Artificial intelligence also helps generative design for carbon capture materials, which allows researchers to explore new types of carbon‐absorbing material, including metal–organic frameworks and polymeric materials that are important in industrial CO2, such as moisture. In addition, it increases the accuracy of reservoir simulations and controls CO2 injection systems for storage or enhanced oil recovery. Through applying AI algorithms on reservoir geology, production performance and real‐time data this study would like to facilitate the optimization of injection processes as well as minimize CO2 emissions while assuring a maximum efficiency. Artificial intelligence integrates with renewable‐based carbon capture efforts that can be employed by AI‐driven smart grid systems to improve carbon capture methods.

Microscopic Experiments to Assess the Macroscopic Sweep Characteristics of Carbon Dioxide Flooding

The Lunnan oilfield in the Tarim Basin, one of China’s major onshore oilfields with substantial geological reserves, faces particular challenges due to the complexity of its reservoir environment and the dispersion of remaining oil. Carbon dioxide, a greenhouse gas, presents an opportunity for enhanced oil recovery (EOR) and geological storage. In this context, the use of carbon dioxide for EOR can simultaneously address environmental concerns and improve oil recovery rates. This study focuses on the TI reservoir in the No. 2 well area of the Lunnan oilfield, employing advanced techniques to analyze the micro- and macro-characteristics of carbon dioxide flooding. Results: From the microscopic point of view, carbon dioxide flooding is mainly miscible with crude oil, which has a strong component exchange effect and can be displaced in the form of full pores, and the microscopic displacement efficiency is close to 100%. Macroscopically, under the combined injection and production of different injected hydrocarbon pore volume multiples (HCPVs), it is injected at the upper and lower layers of the interlayer and produced far away from the lower layer of the interlayer, with a total recovery rate of 52.83%. With the increase in the HCPV, the recovery increased rapidly at first and then slowly, and the HCPV at the demarcation point was 0.5, while the oil production rate increased in a wave-like manner and then decreased rapidly, and the HCPV at the breakthrough point of TI gas was 0.5. However, when the upper and lower layers far away from the interlayer are injected at the same time, the upper and lower layers of the interlayer are produced at the same time, and the total recovery rate can reach 83.02%. With the increase in the HCPV, the recovery rate increases rapidly at first and then slowly, and the HCPV at the turning point is 6.52. The oil production rate increases in a wave-like manner, then decreases rapidly, rises rapidly, and then decreases slowly in a wave-like manner. The HCPV at the breakthrough point of TI gas is 0.63, and the HCPV at the injection–production transition point is 0.63. The total recovery rate of carbon dioxide miscible displacement can reach 88.68% under the condition of separate injection and combined production with different injected hydrocarbon pore volume multiples. With the increase in the HCPV, the recovery increased rapidly at first and then slowly. The HCPV at the demarcation point was 6.5, the oil production rate increased in a wave-like manner, then decreased rapidly, increased rapidly, and then decreased slowly in a wave-like manner. The HCPV at the breakthrough point of TI gas was 0.63, and the HCPV at the injection–production transition point was 6.5. The research results provide data support for the physical reality of the microscopic and macroscopic sweep characteristics of carbon dioxide flooding in the Lunnan oilfield, Tarim Basin.

Synthesis of hydrophobic polymeric surfactant (Polyacrylamide/Zwitterionic) and its effect on enhanced oil recovery (EOR)

Injection of surfactant and polymer at the same time is one of the challenges that reduce their performance in reservoirs. Using a polymeric surfactant (PS) as a single new material can be the best alternative to solve the existing challenges. Considering the basic problems of chemical injection, this work focuses on the surface adsorption of polymer/surfactant on carbonate reservoirs (CRs). In this work, polyacrylamide was synthesized using zwitterionic as a hydrophobic polymeric surfactant (i.e. HZPAA). For a better comparison, this substance was compared with hydrolyzed polyacrylamide (HPAA) in concentrations of 40 to 1000 mg in CRs. Examining the results states that with increasing polymer concentration, the surface absorption of HZPAA and HPAA on dolomite reservoir rocks (DRRs) with positive surface charge increases. The attendance of COO and SO3− functional groups in the matrix of the new polymer (i.e. HZPAA) creates electrostatic forces and superior surface absorption. Their mechanism works in such a way that negative functional groups attract positively charged surfaces and increase the surface absorption of the polymer. Investigations show that the new synthesized material (i.e. HZPAA) can provide a new approach to improving surface absorption in carbonate reservoirs.

Numerical Evaluation of Multi-well Cyclic Gas Injection Technique for Enhanced Oil Recovery in Composite Tight Oil Reservoirs

Numerical Evaluation of Multi-well Cyclic Gas Injection Technique for Enhanced Oil Recovery in Composite Tight Oil Reservoirs

Novel Acinetobacter sp. Isolated from Oil-contaminated Soil for Microbial Enhanced Oil Recovery

The viscosity of hydrocarbon reservoirs increases with age. So, a significant amount of oil is trapped in the underground reservoirs after recovery using primary and secondary methods. To improve the recovery, tertiary methods have been used. However, there is limited research on Microbial Enhanced Oil Recovery (MEOR) as a tertiary method due to microbes' inability to survive the high-temperature reservoir conditions. Consequently, the goal of this research is the creation of a novel bacteria strain for MEOR. The isolated bacteria colonies were inoculated in a batch fermentation broth, and the biosurfactant produced was screened using the oil displacement, emulsification index, modified drop-collapse test, surface tension, and interfacial tension criteria. The effects of pH (7.2 – 10.52), and salinity (15 – 35 %) at optimum temperature were studied on the selected isolate, which was identified by partial 16 rRNA gene sequence analysis. Gas Chromatography-Mass Spectroscopy was used to characterize the biosurfactants produced. The new isolate reduced heavy oil viscosity by 17% and produced a recovery factor in the range of 13-16.72%. The new bacteria is a thermophile and survived at a temperature of 65 °C, indicating promise for use in MEOR.

Modeling the impact of pH and reservoir temperature on the dissolution of quartz mineral due to oilfield chemical treatment

The petroleum industry frequently uses oilfield chemicals, such as corrosion inhibitors, scavengers, drilling fluid, and chemical enhanced oil recovery methods, to improve oil recovery. However, these chemicals can negatively impact the geochemical characteristics of the formation, potentially leading to facility failure and reservoir formation damage. A study using PHREEQC was conducted to predict the impact of reservoir temperature and pH on quartz rock dissolution under different temperatures and pH levels. The results showed consistent dissolving rates for quartz at different pH levels. The solubility of quartz minerals was slightly affected by the solution pH, suggesting that the process variable pH has little effect on the equilibrium rate. However, precipitation caused quartz to dissolve at a rate of 0.04 mmol.L−1.s−1 at 45 °C but increased to 0.07 mmol.L−1.s−1 at 65 °C in 0.8 s. As temperature increased, quartz and NaNO3 solution interaction reached equilibrium concentrations in 0.8 and 2.7 s. The study concluded that temperature significantly impacts quartz dissolution during interaction with sodium nitrate oilfield chemicals compared to pH. The PHREEQ software is a useful research tool for simulating rock-fluid interactions resulting in reservoir formation dissolution and precipitation, which can cause formation damage and sand production.

Enhanced oil recovery and carbon sequestration in low-permeability reservoirs: Comparative analysis of CO2 and oil-based CO2 foam

Excessive CO2 emissions contribute to global climate change thus mandating effective methods for CO2 utilization and sequestering. In this study, one-dimensional flow simulation experiments on CO2 flooding, CO2 Huff-n-Puff, oil-based CO2 foam flooding, and oil-based CO2 foam Huff-n-Puff are conducted using low-permeability sandstone cores modeled after the Q131 block in Liaohe Oilfield, characterized by porosity ranging from 15% to 20% and permeability between 25 mD to 35 mD. Low permeability reservoirs are rich in oil resources and may effectively sequester CO2. Parameters pertaining to oil and gas production and carbon storage are collected. Nuclear magnetic resonance (NMR) is employed to determine the spatial variation of oil saturation in the cores. The experimental results show 8.03% and 41.21% increase in oil recovery factor by foam flooding and foam Huff-n-Puff relative to CO2 as the recovery agent. Moreover, NMR analysis confirms lower residual oil saturation in core samples using foam, suggesting better displacement agent. Oil-based CO2 foam recovery contributed to effective carbon sequestration, with carbon storage increasing by 34.24% and 315% relative to CO2 flooding and CO2 Huff-n-Puff, respectively. CO2 storage mechanisms for oil-based CO2 foam recovery method are detailed.

ANALYSIS OF THE ECONOMIC PERFORMANCE OF PROJECT ADVANCED OIL RECOVERY WITH CO2 INJECTION (EOR/CCUS-CO2) THROUGH FINANCIAL INDICATORS: BRAZILIAN OVERVIEW

Enhanced Oil Recovery (EOR) is a method associated with Carbon Capture, Utilization, and Storage (CCUS) that consists of injecting CO2 into mature oil fields to store CO2 and enhance production. CO2-EOR projects are costly, requiring technical and economic evaluations to determine their viability. This research analyzes various economic parameters in CO2-EOR projects to develop a comprehensive model for assessing their economic viability in Brazil. The model was tested on projects developed by Silva et al. (2010) and included six scenarios of CO2-EOR in mature reservoirs. The results demonstrate the impact on well completion costs. The scenario with the highest oil production had one additional completion and, for this reason, did not show the best Net Present Value (NPV) result. This work also conducts a sensitivity analysis of parameters and reviews their impacts on NPV. Results indicate a significant impact of barrel price and minimum attractiveness rate on the NPV, while finding that the taxation of excess CO2 was not very significant. Low barrel prices (<$9) proved to be unfeasible with negative NPVs.

Fluorescence visualization dynamics of carbonated water injection processes in homogeneous glass micromodels

Understanding the flow behavior of oil–water phases in porous media is crucial for revealing the kinetic mechanisms underlying oil–water movement. In this study, we designed and constructed a fluorescence visualization experimental platform for carbonated water injection (CWI). We evaluated the effects of nine distinct injection rates on oil production and CO2 sequestration capabilities using three types of homogeneous porous structure micromodels. The microscale oil–water seepage behavior at the pore scale was also explored. The experimental results indicate that optimally increasing the injection rate can improve displacement efficiency, whereas excessively high rates may lead to viscous and capillary fingering. The geometry of the micromodels, particularly the hexagonal matrix, demonstrates potential advantages in enhancing oil displacement due to its uniform flow paths. The capillary number (Ca) significantly influences oil droplet capture behavior within micromodels. For instance, micromodel A captures the largest ganglion area at low Ca values, with a noticeable reduction in average ganglion area as Ca increases. Conversely, micromodels B and C exhibit similar trends in ganglion size variation at high Ca values, suggesting a more uniform impact of pore structure on oil droplet capture behavior. At elevated Ca values, capillary forces exert a more uniform and controlled effect on oil droplet capture and release, minimizing size variability. Additionally, the injection rate plays a critical role in CO2 sequestration, with higher rates promoting convective mixing between CO2 and reservoir fluids, thereby enhancing dissolution and storage efficiency. The complexity of the pore structure, characterized by the presence of micropores and macropores, affects the dissolution kinetics and mobility of CO2, influencing sequestration efficiency. These experimental findings provide valuable insights into the dynamics of oil–water motion and the potential for enhanced oil recovery (EOR) and CO2 storage, offering essential guidance for optimizing CWI strategies in the petroleum industry.

In situ combustion performance in heavy oil carbonate reservoirs: A triple-porosity numerical model

This study aims to address the challenges of oil recovery in highly heterogeneous carbonate reservoirs by employing a novel triple-porosity numerical model approach for in-situ combustion (ISC). The primary focus is on the performance of ISC within isolated vuggy pore spaces, a characteristic feature of such reservoirs. By simulating triple-porosity through artificially induced vuggs, core matrix, and fractures, we evaluated the feasibility of the ISC technique for heavy oil recovery in a dolomite reservoir using a combustion tube setup.The numerical model, calibrated through history matching, incorporates an extended kinetic reaction scheme to better represent high-temperature oxidation processes. Experimental and simulation results show a strong correlation in temperature profiles, ignition timing, and fluid production, effectively reproducing the observed gas compositions. This integrated experimental and numerical approach demonstrates the potential for applying ISC in triple-porosity systems, offering valuable insights for field-scale implementations in similarly complex carbonate reservoirs. The novelty of this research lies in its comprehensive modeling of the first ISC experiment in a triple-porosity framework, providing a deeper understanding of the interactions between matrix, fracture, and vugg networks, and paving the way for enhanced oil recovery (EOR) strategies in challenging reservoir environments.