Steam Flooding Research Articles

Importance of Clay Swelling on the Efficacy of Cyclic Steam Stimulation in the East Moldabek Formation in Kazakhstan

Both steam and hot water flooding of high-viscosity oils in the presence of swelling clays are difficult methods for producing oil efficiently because of potential formation permeability reduction. This paper pertains to heavy oil recovery from the East Moldabek formation where the oil API gravity is about 22 and is inundated with swelling clays. To achieve this, we used the IntersectTM reservoir simulator to compare oil recovery economics using both hot water and steam injection as a function of steam cycle duration, temperature, and steam dryness. We also studied clay swelling in the East Moldabek formation where clay poses a significant challenge due to its impact on permeability reduction. In this research, we developed an equation based on experimental data to establish a relationship between water mineralization and permeability in the East Moldabek formation. The equation provides valuable insight on how to mitigate clay swelling which is crucial for enhancing oil recovery efficiency—especially in sandstone reservoirs. Our modeling studies provide the recovery efficiencies for salinities of the hot water EOR versus cyclic steam EOR methods in a formation containing swelling clays. Specifically, the reduction in formation permeability as a function of the distilled water fraction is the controlling parameter in hot water or steam flooding—when the formation water mixture becomes less saline, oil recovery decreases. Our research shows that clay swelling can significantly impact cyclic steam stimulation outcomes, potentially reducing its effectiveness, while hot water flooding may offer a more cost-effective and operationally feasible solution in formations where clay swelling is a concern. Economic analysis reveals the potential for achieving an optimal favorable condition for hot water injection. Therefore, this paper provides a guideline on how to conduct thermal oil recovery for heavy oils in fields with high clay content such as the East Moldabek deposit.

Phased optimization of multi-thermal fluid flooding for enhanced oil recovery

Multi-thermal fluid flooding has become a critical technique in heavy oil reservoirs and is widely applied in China. Owing to the complexity of the displacement process and the involvement of multiple injection media, conventional optimization methods are unable to achieve economic and efficient development of heavy oil. In this study, an efficient phased parametric optimization method for multi-thermal fluid flooding was developed using horizontal wells in heavy oil reservoirs. This method utilizes particle swarm optimization (PSO), which targets the net present value for the phased optimization of multi-thermal fluid flooding. A comparison between the phased optimization and non-phased optimization shows that the cumulative oil production increased by 16.74% and the net present value increased by 39.66% with phased optimization. The effectiveness of the phased optimization method was verified using a field model. Optimal injection parameter charts were developed for each phase of the multi-thermal fluid flooding under different reservoir parameter conditions. The charts illustrate that the optimal gas injection rate and chemical mass concentration tend towards zero during the steam flooding initiation phase under varying reservoir parameter conditions. Conversely, all the media injection rates increased during the thermal fluid control and steam breakthrough phases. Additionally, with an increase in the crude oil viscosity, effective formation thickness, and original oil saturation, the optimal injection rate of the various media increases. However, with an increase in the permeability and reservoir depth, the optimal injection rate of the various media decreases.

Pore-Scale Mechanism Analysis of Enhanced Oil Recovery by Horizontal Well, Dissolver, Nitrogen, and Steam Combined Flooding in Reducer Systems with Different Viscosities for Heavy Oil Thermal Recovery

Horizontal well, dissolver, nitrogen, and steam (HDNS) combined flooding is mainly applied to shallow and thin heavy oil reservoirs to enhance oil recovery. Due to the lack of pore-scale mechanism studies, it is impossible to clarify the oil displacement mechanism of each slug in the process combination and the influence of their interaction on enhanced oil recovery (EOR). Therefore, in this study, HDNS combined flooding technology was simulated in a two-dimensional visualization microscopic model, and three viscosity reducer systems and multi-cycle combined flooding processes were considered. In combination with an emulsification and viscosity reduction experiment, two-dimensional microscopic multiphase seepage experiments were carried out to compare the dynamic seepage law and microscopic occurrence state of multiphase fluids in different systems. The results showed that the ability of three viscosity reducers to improve viscosity reduction efficiency in HDNS combined flooding was A > B > C, and their contributions to the recovery reached 65%, 41%, and 30%, respectively. In the system where a high viscosity reduction efficiency was shown by the viscosity reducer, the enhancements of both sweeping efficiency and displacement efficiency were primarily influenced by the viscosity reducer flooding. Steam flooding collaborated to improve displacement efficiency. The thermal insulation characteristics of N2 flooding may not provide a gain effect. In the system where a low viscosity reduction efficiency was shown by the viscosity reducer, the steam flooding was more important, contributing to 57% of the sweeping efficiency. Nitrogen was helpful for expanding the sweep area of the subsequent steam and viscosity reducer, and the gain effect of the thermal insulation steam chamber significantly improved the displacement efficiency of the subsequent steam flooding by 25%. The interaction of each slug in HDNS combined flooding resulted in the additive effect of increasing production. In actual production, it is necessary to optimize the process and screen the viscosity reducer according to the actual conditions of the reservoir and the characteristics of different viscosity reducers.

Riedel shear structures reactivation may induce earthquakes through long-term steam injection: A case study of a heavy oil production field in northwestern China

Conventional heavy oil exploitation methods involve steam stimulation and flooding. An oil field in northwestern China has been producing heavy oil via steam injection for several decades. The production area has been seismically quiet until an increase in seismicity occurred several years ago. An array of 40 seismographs has been deployed between July and October 2021 to monitor seismicity and resolve the possible causes of the recent seismicity. Using an end-to-end machine-learning-based high-precision earthquake location workflow, we analyze a microseismic sequence comprised of 178 events that occurred in the study area. Numerical simulations incorporating Coulomb failure stress suggest that prolonged steam injection can reactivate faults and induce seismic events. Similarly, fluid diffusion through conduits may achieve the same effect. Analysis of the focal mechanism solutions of 21 strike-slip and thrust events with [Formula: see text] in conjunction with the background stress regime ([Formula: see text] azimuth = N15°W) reveal that the stress distribution is compatible with a left-lateral Riedel shear structure (RSS) model. Therefore, we can speculate that steam injection may induce earthquakes by reactivating preexisting RSS fault structures. To conclude, the recent seismic events could have been induced by two possible mechanisms: (1) long-term steam injection may cause the static stress level on the faults beneath the reservoir to build up to critical levels, following which a slight stress disturbance can trigger an earthquake and (2) fluid conduits may transport condensed water to basement faults, weakening the faults through fluid diffusion.

Research for Flow Behavior of Heavy Oil by CO2 Foam Viscosity Reducer-Assisted Steam (CFVAS) Flooding: Microscopic Displacement Experiment Study

Steam displacement is prone to cross-flow, small swept area, large oil–water ratio, large oil–water interfacial tension, and low oil displacement efficiency. Compared with steam flooding, foam flooding can effectively reduce the residual oil in the small throat of the main flow channel and the small hole in the near flow channel and increase the overall recovery factor. Therefore, researchers carried out CO2 and chemical agent-assisted steam displacement. However, at present, there is a lack of research on the occurrence mechanism and model of residual oil. Steam flooding often encounters challenges such as cross-flow, limited sweep area, and high oil–water ratio. Foam flooding offers a promising alternative by effectively reducing residual oil in narrow throats and the near flow channel, thereby enhancing overall recovery rates compared to steam flooding alone. Therefore, chemical agent-assisted steam flooding was applied to enhance heavy oil recovery. However, the occurrence mechanism and model of residual oil after chemical agent-assisted steam is not clear. To fill this gap, the CO2 foam viscosity reducer assisted steam (CFVAS) flooding technology has been adopted and carried out in several studies. First, the foam viscosity reducer was prepared and its foam properties (viscosity reduction effect, foam volume, and half-life) were tested. Subsequently, the CFVAS displacement experiments after steam flooding were carried out, and the flow behavior of the remaining oil in multiple regions (main flow channel, near flow channel, and far flow channel) was analyzed. Finally, the shape and number of remaining oil under different displacement stages were compared, and the occurrence mode of remaining oil under CFVAS displacement was determined. The results indicate the following: (1) During steam flooding, the amount of near flow channel residual oil decreased with injected pore volumes (PV), transforming into columnar structures in small perforations and film-like formations in far flow channels. (2) CFVAS flooding, including the foam stability mechanism, flow channel adjustment mechanism, and emulsification and dispersion mechanism, can improve overall recovery rates by 55.2% by driving the remaining oil in near flow channels. (3) During CFVAS flooding stage, crude oil mobility notably improved and flooding front expanded more evenly. Residual oil primarily existed as oil-in-water (O/W) emulsions with discontinuous columns. (4) In the CFVAS flooding stage, residual oil mainly formed O/W emulsions through emulsification and dispersion, with foam-filled large and medium pores, concentrating residual oil in thick and middle throats. This work can provide important references for injecting CO2 gas into reservoirs to enhance heavy oil recovery and promote carbon sequestration.

High-Efficiency High-Temperature-Resistant Nanosilica Viscosity Reducer for Extra-Heavy Oil Viscosity Reduction.

Due to the fact that more conventional heavy oil recovery methods (heating, emulsification, dilution, and other methods) have many shortcomings, they cannot meet the demand of heavy oil exploitation. Therefore, there is a need for new recovery methods. In this paper, the surface of nano SiO2 was modified with a silane coupling agent, KH-560, to prepare a nanoviscosity reducer (NRV), which has high-temperature resistance (300 °C), calcium and magnesium resistance (Ca2+ + Mg2+ > 900 mg/L) and high viscosity reduction rate (>99%). FTIR and SEM measurements showed that KH560 has been successfully connected to the surface of SiO2. The particle size distribution of NRV is mainly distributed in 50-80 nm, which matches the results of SEM. The experimental results showed that the viscosity reduction rates of 1 wt % NRV on M-1 heavy oil before and after aging were 99.73% and 99.71%, respectively. The viscosity reduction effect of 1% NRV on M-1 heavy oil and the bleeding rate of emulsion formation were investigated when the oil-water ratio ranged from 9:1 to 1:9. The results showed that when the oil-water ratio was between 7:3 and 1:9, the viscosity reduction rate was greater than 99%. Besides, the bleeding rate of emulsion increases with the decrease of the oil-water ratio. What's more, static and dynamic adsorption experiments showed that the adsorption capacity of 1 wt % NRV was 1.746 mg/g and 1.668 mg/g sand, respectively. The interfacial tension experiment showed that the interfacial tension (IFT) between 1 wt % NRV and M-1 heavy oil was 0.052 mN/m, and low interfacial tension was beneficial to displace the oil in the formation pores. At the same time, the displacement effect of NRV on M-1 heavy oil at different concentrations (0.5, 1.0, and 1.5 wt %) and temperatures (200, 250, and 300 °C) was investigated by core flooding experiments. The results showed that the recovery rate increases with the increase of NRV concentration, and 1 wt % NRV at 300 °C will improve the recovery rate of M-1 heavy oil by 27.3% compared to steam flooding. NRV could reduce the viscosity of crude oil, which provides technical guidelines for the exploitation of heavy oil and extra heavy oil.

Gap Analysis of the Environmental Management System Performance of PT. XXX to ISO 14001:2015 Standard

PT. XXX is one of the oil and gas exploration companies in Indonesia operating in the Rokan Block of the Duri Steam Flood (DSF) Operation Area. To maintain the level of petroleum production in operation, PT. XXX DSF Operating Area adds oil and gas wells, improves, and improves operation reliability through upgrading several existing facilities; seen from the environmental setting at the current operational location, DSF's operational area activity plan has an impact on environmental components. To mitigate it, PT. XXX has developed an Environmental Management System (EMS) DSF Operating Area according to the international standard ISO 14001:2015. This quantitative descriptive research aims to determine the gap in QMS performance implemented by companies with ISO 14001: 2015 standards using seven clauses: Self-Assessment Checklist Internal Audit ISO 14001: 2015 GEMI 2015. To find out the Company's SML gap score with ISO 14001: 2015 standard is determined by the Gap Analysis method. The gap results from the 7 (seven) clauses analysed to show the readiness score of SML PT. XXX DSF operational to implement ISO 14001:2015 Standard is 98.83% refers to range gap analysis if the score range of 75% - 100% indicates PT. XXX DSF Operations is ready to complement EMS ISO 14001:2015 and carry out certification. The gap score between the Company's Environmental Management System (EMS) that is being implemented and the ISO 14001:2015 standard is 1.17%. The gap in clauses that have not met the requirements of SML ISO 14001: 2015 is Clause Support, which scores 95% and Clause Performance Evaluation, which scores 96%.

Nanotechnology Applications in Enhanced Oil Recovery (EOR)

Enhanced Oil Recovery (EOR) techniques are crucial for maximizing crude oil extraction from reservoirs, especially when traditional methods leave significant amounts of oil untapped. Recent advancements in nanotechnology have introduced innovative solutions to longstanding challenges in the oil industry. This research paper explores the application of nanotechnology in EOR, emphasizing the unique properties of nanoparticles that make them highly effective in this context. Nanoparticles, defined by their nanometer-scale dimensions, exhibit high surface area to volume ratios, quantum effects, and enhanced reactivity. These properties enable various mechanisms in EOR, including improved wettability, reduction in interfacial tension, enhanced thermal stability, selective plugging and fluid diversion, and catalytic effects. The study details how silica and titanium dioxide nanoparticles can modify rock surface properties, leading to better water imbibition and oil displacement. It also discusses how surfactant-coated nanoparticles can reduce the interfacial tension between oil and water, facilitating easier oil flow. Furthermore, the research highlights the role of metal oxide nanoparticles, such as aluminum oxide and zinc oxide, in enhancing thermal conductivity and stability during thermal EOR methods like steam flooding. The ability of polymer-coated nanoparticles to selectively plug high-permeability zones and redirect injection fluids is examined, demonstrating how this can lead to a more uniform sweep and higher oil recovery. The catalytic properties of certain nanoparticles, such as iron oxide, are also explored for their potential to promote in-situ chemical reactions that generate gases aiding oil displacement. Field applications and case studies underscore the practical benefits of nanotechnology in EOR. Examples include the use of silica nanoparticles in Middle Eastern oil fields, polymer-coated nanoparticles in Canadian heavy oil reservoirs, and iron oxide nanoparticles in Indian oil fields. These case studies have shown significant increases in oil recovery rates and operational efficiencies. However, the research also identifies several challenges that must be addressed for the widespread adoption of nanotechnology in EOR. These include the high costs and scalability issues associated with nanoparticle production and deployment, potential environmental and health risks, and the need for customized solutions to cater to the unique conditions of different reservoirs. In conclusion, while nanotechnology presents promising advancements in EOR through various mechanisms, overcoming challenges related to cost, scalability, and environmental impact is crucial. As research progresses, nanotechnology is poised to play a vital role in enhancing oil recovery and meeting global energy demands.

Perbandingan Performa Antara Treatment Hydrochloric Acid dan Carboxylic Acid Terhadap Kenaikan Produksi pada Sumur Minyak Berat

Duri steam flood is the largest hot steam injection project in Indonesia, facing challenges in preventing production declines. Objective project is showed decrease in production due to crustal deposition (scale). The Stiff and Davis method shows a Stability Index of 1.43, with a tendency for scale formation, especially CaCO3, in accordance with the Ryznar method. Increasing the production of x, yz layer wells in the Duri field, designing acidification stimulation with a pumping pressure of 400 psi, an injection rate of 2 bbl/minute and an acid volume of 600 gallons, after that comparing the performance of hydrochloric acid and carboxylic acid. Analysis showed that hydrochloric stimulation resulted in a significant increase in production of 115 BFPD / 8 BOPD (42% increase), while carboxylate stimulation showed a slower increase of 40 BFPD / 3 BOPD (24% increase). An economic evaluation shows chloride acidification produces an annual NPV gain of $48,002, compared to carboxylate acidification with an annual NPV gain of $22,554. Thus, chloride acidification proved to be economically profitable for the x, yz layers in the Duri field. This study highlights optimal acid stimulation strategies to mitigate scale-related production challenges in steam flood projects.

Application of Flue Gas Foam-Assisted Steam Flooding in Complex and Difficult-to-Produce Heavy Oil Reservoirs.

In order to study the mechanism of improving recovery efficiency of complex difficult-to-recover heavy oil reservoirs and explain the interaction and migration law of flue gas, foam, and steam, this paper designed the experiment of flue gas influence on heavy oil flow and the experiment of flue gas foam displacement in complex difficult-to-recover heavy oil model. The results show that the flue gas has expansion and an energy enhancement effect. Moreover, the interfacial tension of heavy oil can be reduced, and the higher the CO2 content in flue gas, the more beneficial it is to reduce the interfacial tension. When there is an interlayer in the reservoir, the gas can form a "puncture" in the interlayer, which provides a channel for the subsequent upward expansion of steam, so that the upper part of the interlayer can be used to expand the steam sweep range. The main mechanism of improving heavy oil recovery with flue gas foam is that the foam regulates fluid mobility and improves the thermal sweep efficiency of steam. In addition, the injected foam can emulsify with heavy oil, reduce the viscosity of heavy oil, and improve the fluidity of heavy oil. Finally, the maximum oil production rate increased from 1.809 to 2.455 g/min, and the recovery rate increased from 44.3 to 68.8%.

Comparative Assessment of Conventionally and Locally Sourced Surfactants for Enhancing Steam Flooding Techniques for Heavy Oil Recovery in Niger Delta

The recovery of heavy oil reserves presents a significant challenge in the petroleum industry due to its high viscosity and poor mobility characteristics. Steam flooding, as a thermal Enhanced Oil Recovery (EOR) technique, has shown promise in mobilizing heavy oil deposits. However, the limited success of conventional steam flooding in heavy oil reservoirs necessitates innovative approaches. This study explores the utilization of conventional and locally sourced surfactants in surfactant-enhanced steam flooding (SESF) for heavy oil recovery in the Niger Delta region. The study examines the selection, formulation, and injection of surfactants specifically tailored for heavy oil reservoir conditions. Laboratory experiments, core flooding tests, and numerical simulations are conducted to evaluate the impact of surfactants on interfacial tension reduction, wettability alteration, and improved oil mobility in heavy oil reservoirs subjected to steam flooding. The project’s findings demonstrate the significant potential of (SESF) for heavy oil recovery. The synergistic effects of surfactants and steam, including the reduction of oil-water interfacial tension, lead to increased oil production rates, reduced steam consumption, and enhanced sweep efficiency. Furthermore, economic assessments are conducted to evaluate the feasibility of implementing this approach on a field scale, considering both technical and economic aspects. This study not only contributes valuable insights to the field of heavy oil recovery but also underscores the practicality of surfactant-enhanced steam flooding as an environmentally responsible solution for unlocking the vast heavy oil reserves worldwide. The research bridges the gap between laboratory findings and real-world applications, offering a promising path forward for the sustainable development of heavy oil resources.

Study on Enhanced oil recovery by steam flooding in heavy oil reservoirs

With the development of social economy, the demand for energy is increasing day by day. Under this background, the development of conventional petroleum resources has been unable to meet the needs of social development, and the importance and necessity of exploitation of heavy oil reservoirs has become increasingly prominent. However, the viscosity of heavy oil is larger, the fluidity is worse than that of conventional crude oil, and it is more difficult to exploit. In this regard, in order to further improve the exploitation level of heavy oil reservoir, relevant enterprises and technicians need to strengthen the research on steam flooding exploitation technology, and improve the recovery efficiency of heavy oil reservoir by using the technical advantages of steam flooding. In view of this, this paper first briefly analyzes the mechanism of steam flooding to improve the recovery efficiency of heavy oil reservoirs, and then expounds the main factors affecting the recovery efficiency of steam flooding. On this basis, combined with specific cases, the feasibility of steam flooding to improve the recovery efficiency of heavy oil reservoirs is verified for reference.

Experimental Study on Enhanced Oil Recovery Effect of Profile Control System-Assisted Steam Flooding.

Steam flooding is an effective development method for heavy oil reservoirs, and the steam flooding assisted by the profile control system can plug the dominant channels and further improve the recovery factor. High-temperature-resistant foam as a profile control system is a hot research topic, and the key lies in the optimal design of the foam system. In this paper, lignin was modified by sulfonation to obtain a high-temperature-resistant modified lignin named CRF; the foaming agent CX-5 was confirmed to have good high-temperature foaming ability by reducing the surface tension; the formula of the profile control system (A compound system of CRF and CX-5, abbreviated as PCS) and the best application parameters were optimized by the foam resistance factor. Finally, the effect of PCS-assisted steam flooding in enhanced oil recovery was evaluated by single sand packing tube flooding, three parallel tube flooding, and large-scale sand packing model flooding experiments. The results show that CX-5 has a good high-temperature foaming performance; the foam volume can reach more than 180 mL at 300 °C, and the half-life is more than 300 s. The optimal PCS formulation is 0.3 wt% CRF as an oil displacement agent + 0.5 wt% CX-5 as a foaming agent. The optimal gas-liquid ratio range is 1:2 to 2:1, and the high pressure and permeability are more conducive to the generation and stability of the foam. Compared with steam flooding, PCS-assisted steam flooding can improve oil recovery by 9% and 7.9% at 200 °C and 270 °C, respectively. PCS can effectively improve the heterogeneity of the reservoir, and increase the oil recovery of the three-parallel tube flooding experiment by 28.7%. Finally, the displacement results of the sand-packing model with large dimensions show that PCS can also expand the swept volume of the homogeneous model, but the effect is 9.46% worse than that of the heterogeneous model.

Experimental study on flue gas foam-assisted steam flooding: investigating characteristics of enhanced oil recovery and gas storage

Experimental study on flue gas foam-assisted steam flooding: investigating characteristics of enhanced oil recovery and gas storage

Optimization Study of Injection and Production Parameters for Shallow- and Thin-Layer Heavy Oil Reservoirs with Nitrogen Foam-Assisted Steam Flooding

Shallow- and thin-layer heavy oil reservoirs are characterized by their shallow burial, thin thickness, high viscosity, and scattered distribution. After years of steam injection development, several issues have emerged, including a highly comprehensive water cut in the reservoir and serious steam channeling. Therefore, there is an urgent need to change the development approach to enhance crude oil recovery. It has been discovered that developing heavy oil reservoirs through nitrogen foam-assisted steam flooding can effectively address the challenges encountered in pure steam development. This paper takes H Oilfield Block A as a case study, analyzes the geological characteristics and development status of the reservoir in this block, and predicts the recovery of steam injection development in this block using the injection-production characteristic curve method. Furthermore, by establishing a reservoir geological model and fitting it to the historical behavior of the target reservoir, the nitrogen foam-assisted steam flooding injection and production parameters were optimized. The optimal parameters are as follows: optimal steam injection intensity of 2.0 t/(d·ha·m), optimal production/injection ratio of 1.2:1, optimal nitrogen foam slug injection volume of 0.15 PV, optimal nitrogen/steam ratio of 2:1, and intermittent injection between 3 and 4 foam slugs. It is anticipated that this optimized scheme will result in a predicted increase in final recovery of 13.55%. The findings of this study hold significant importance in guiding the application of nitrogen foam-assisted steam flooding in shallow and thin heavy oil reservoirs.

Experimental investigation on supercritical multi-thermal fluid flooding using a novel 2-dimensional model

Supercritical multi-thermal fluid (SCMTF) is a promising alternative to traditional thermal agents for deep heavy oil recovery. However, no 2-dimensional experimental investigation on SCMTF flooding has been conducted due to the limitations of existing apparatuses. Therefore, the primary objective of this study is to develop a novel assembly for investigating the performance of SCMTF flooding. Subsequently, the SCMTF chamber evolution is characterized using newly developed equipment, and enhanced oil recovery (EOR) mechanisms are proposed. Finally, the effects of the injection temperature, injection pressure, scN2/scCO2 mixture, and heavy oil viscosity on SCMTF are comprehensively studied. The results show that the SCMTF chamber displays an inverted trapezoidal shape with a uniform front. SCMTF flooding can enhance heavy oil recovery by 13.36% relative to steam flooding by sweep area expansion, oil mobility improvement, and miscible flooding. Increasing the injection temperature, injection pressure or scN2/scCO2 mixture to SCW molar ratio can facilitate the production of heavy oil, while using SCMTF in an extra-heavy oil cannot maximize the EOR effect of SCMTF. Notably, the high yield of coke produced at elevated temperatures may lead to potential formation damage.

Reducing CO2 emissions and improving oil recovery through silica aerogel for heavy oil thermal production

Heavy oil reserves comprise more than 60% of global crude oil resources, and thermal oil recovery techniques, especially steam injection, are widely utilized for extracting heavy oil. However, these thermal production processes are characterized by high energy consumption and carbon emissions, which pose significant challenges in reducing CO2 emissions. In response to these challenges, this study presents a novel approach that combines silica aerogel with CO2-assisted thermal recovery technology. Our findings demonstrate that the incorporation of aerogel nanoparticles enhances the adsorption capacity of CO2 in the aqueous phase. The adsorption behavior of CO2 in silica aerogel aligns with the Langmuir model. When silica aerogel nanoparticles are employed in steam flooding, a notable improvement is observed in both oil recovery and CO2 sequestration rate. Molecular dynamics simulations reveal that the porous structure of aerogel enables the adsorption of light saturates molecules from crude oil, promoting their diffusion into the aqueous phase and ultimately enhancing oil recovery. The steam condensation experiments clearly demonstrate that the presence of aerogel and CO2 exerts a substantial influence on the condensation heat transfer of steam, resulting in a reduction in the condensation heat transfer rate between the steam and the cooling wall. Additionally, molecular dynamics simulations reveal that silica aerogel nanoparticles exhibit an affinity for adsorbing onto hydrophobic quartz surfaces, forming an insulating layer between steam and quartz, thereby facilitating CO2 sequestration. The introduction of silica aerogel nanoparticles expands the swept volume of steam heat. This study provides valuable insights into the underlying mechanisms responsible for improved CO2 sequestration and increased oil recovery through the implementation of silica aerogel nanoparticles, offering fresh perspectives on heavy oil recovery.

A brief review of steam flooding and its applications in fractured oil shale reservoirs

Steam flooding is an important thermal recovery method for heavy oil reservoirs, and convective heating technology is used to fracture oil shale reservoirs with good results. This paper reviews the main prediction methods, optimization approaches for steam flooding performance, and its application in fractured oil shale reservoirs. The prediction methods include experimental, numerical simulation, and statistical models. These provide insights into steam override, heat transfer, and production dynamics. To optimize steam flooding, parameters like quality, temperature, injection rate, and allocation need to be coordinated based on reservoir conditions and monitoring data. Real-time injection control, economic analysis, and sweep efficiency improvements should also be considered in optimization workflows. Although progress has been made, more field studies are needed to establish systematic optimization practices utilizing advanced technologies. This review summarizes the key developments in steam flooding modeling and optimization, providing a reference for further research and field applications.

Chemicals-CO2 mechanisms of inhibiting steam heat transfer and enhancing oil film strip: Steam flow through the wall-adhering oil film surface in porous medium

The CO2 and Sodium Dodecyl Sulfate (SDS) assisted steam flooding technology was an effective approach addressed the persistent issues that have hindered the stable development of high-viscosity cold oil through steam injection. However, in the process of steam flow through porous media, the synergistic influence of the oil film adsorbed in near wellbore porous media, and the CO2-SDS on steam heat transfer has not been investigated. Steam heat transfer is the key factors affecting heavy oil recovery. The primary objective of this study was to research the effect of CO2-SDS on steam heat transfer and oil film stripping by designing experiments. The study results demonstrated that in the initial stage of displacement, the heat transfer resistance between the steam and the porous medium was increased by the oil film adsorbed in near wellbore area. In additional, the condensation mode of the steam was altered from bead condensing to film condensing by the composite thermal fluid flooding, preventing the steam heat dissipation near wellbore area and transferring more thermal to the long-distance area. At the later stage of displacement, the interfacial tension between oil-water and oil-gas was reduced by CO2-SDS, improving the fluidity of oil and providing the seepage channel for steam, and increasing the steam thermal sweep range. Compared to the sandpack experiment of steam flooding, the temperature at the output end of the sandpack model increased from 69.8 °C to 88.7 °C, indicating an expansion of the steam heat sweep range and successful long-distance heat transfer during composite thermal fluid flooding. In the process of composite thermal fluid flooding, the maximum displacement pressure difference increased from 2.28 MPa to 3.07 MPa, and the maximum oil recovery rate increased from 2.48 g/mL to 2.81 g/mL. The peak of the high production period was raised, resulting in a 40.97% to 51.86% increase in recovery rates.

Performance of high temperature steam injection in horizontal wells of heavy oil reservoirs

Steam huff and puff and steam flooding are important development methods for heavy oil reservoirs. At present, there are certain deficiencies in the research on the timing and methods of steam stimulation, steam flooding, and subsequent steam flooding. In addition, the research on the mass and heat transfer characteristics of high temperature steam injection in heavy oil reservoirs is still in the initiation stage. This article first studies the high temperature steam flow model in the horizontal wellbore of the SAGD process. On this basis, a horizontal well pattern model was established through numerical simulation software to analyze the heat and mass transfer characteristics of high temperature steam huff and puff and high temperature steam flooding. Results show that: (a) for heavy oil reservoirs with high temperature steam injection huff and puff, the first cycle of steam injection ends (day 22): the temperature near the well pattern of the horizontal well pattern is higher. In the area between the horizontal well patterns, the temperature rise is not obvious; (b) when the high temperature steam injection huff and puff phase of the heavy oil reservoir ends (900 days), most of the heat energy is recovered, and the formation residual heat is less; (c) After the huff and puff transfer, the thermal connectivity between the horizontal well patterns is better.