Carbon Dioxide Injection Research Articles

Strategy to improve the micropropagation of sugarcane plants using carbon dioxide injection

Objective: To develop a strategy for the improvement of micropropagation of sugarcane plants in the central region of Veracruz, using carbon dioxide injection. Design/methodology/approach: Intelligent control and micropropagation techniques are used in this development. Results: Improved micropropagation of sugarcane plants using carbon dioxide injection is demonstrated using intelligent control techniques. Findings/conclusions: With this controlled carbon dioxide injection system, research can be carried out to obtain the most approximate values to contribute to better growth and adaptability in sugarcane crops. This can guarantee shorter adaptation times and thus generate greater economic gains for the producers.

The effect of temperature on asphaltene transformation and agglomeration in oil pressure tank systems under injection of carbon dioxide in a porous structure: A molecular dynamics study

Asphaltene is a complex blend of high-molecular-weight hydrocarbons present in crude oil. It is a solid, insoluble component that precipitates from oil under certain circumstances, such as temperature (Temp), pressure, or composition changes. Despite its problems, asphaltene has potential uses in a variety of sectors, including the manufacture of carbon materials, asphalt, and pharmaceuticals. Specifically, this study investigated the changes in the asphaltene compaction process under carbon dioxide (CO2) injection by examining changes in initial temperature and analyzing influencing parameters such as radial distribution function, radius of gyration, and density changes. In this study, thermodynamic equilibrium in simulated asphaltene samples was achieved within 10 ns, with temperature and kinetic energy stabilizing at 310 K and 0.86 kcal/mol, respectively. The subsequent analysis focused on the agglomeration of asphaltene molecules under varying temperatures. The agglomeration process was completed within 10 ns, with the gyration radius stabilizing at 30.5 Å, providing insights into asphaltene behavior and its impact on petroleum fluid properties. At 300 K, asphaltene agglomeration increased viscosity to 23.3 Pa s by reducing molecular movement, illustrating the complex relationship between aggregation and fluid viscosity. The study also observed that asphaltene agglomeration increased viscosity to approximately 23.3 Pa s at 300 K due to reduced molecular movement. As the temperature was raised from 300 to 400 K, the maximum density profile decreased from 0.0225 to 0.0207 atom/Å3, while the gyration radius of asphaltene molecules decreased from 30.54 to 28.51 Å and viscosity increased from 23.3 to 23.92 Pa s. These results highlight the intricate effects of temperature on asphaltene dynamics and petroleum fluid properties.

Optimizing Carbon Dioxide Injection for Methane Hydrate Development and Carbon Sequestration: A Long-Term Numerical Simulation Study

Optimizing Carbon Dioxide Injection for Methane Hydrate Development and Carbon Sequestration: A Long-Term Numerical Simulation Study

Carbon dioxide injection into the Achimov formations using reinjection technology by the example of Ach3-4 formation in the Novo-Urengoy area of the Urengoy field

The prerequisites for the study are the calculation results for the cycling process, where carbon dioxide is proposed as the injection agent into the Achimov formations instead of dry gas, with the goal of increasing the condensate recovery factor. The work is focused on the efficiency assessment of carbon dioxide reinjection technology and reducing carbon footprint at a late stage of field development. The research object is the Аch3-4 formation within the Novo-Urengoy license area of the Urengoy field. The leading method to identify this problem is the results of the full-scale composite dynamic model in the ECLIPSE 300 format. The model takes into account the history of field development on depletion. The articles deals with two schemes for injecting carbon dioxide into the formation. In the first scheme, pure carbon dioxide is injected in a closed-loop system, but carbon neutrality through storage is not achieved. In the second scheme, carbon dioxide is injected using reinjection technology. Once injection begins, gas production stops. Only the condensate separated from the formation gas during low-temperature separation is sold and sent for further processing. After allocation of the condensate, the mixture of natural gas and carbon dioxide, in a specific proportion, is sent to the compressor station for reinjection into the formation in a gaseous state. Injecting pure carbon dioxide achieves a condensate recovery factor similar to that of gas injection with a 30 % carbon dioxide mixture. However, this option is less economically viable compared to the base and other scenarios due to high capital costs for upgrading the existing gas processing equipment (requiring the construction of an amine treatment unit). With carbon dioxide injection using reinjection technology, in addition to recovering extra condensate that had condensed during natural depletion, a reduction in the carbon footprint is also achieved. To maximize the condensate recovery factor, the optimal concentration of carbon dioxide in the injection mixture has been determined. The optimal timing for the start of injection was identified to maximize gas recovery. Economic efficiency is expected from the additional recovery of condensate trapped in the reservoir and from achieving carbon neutrality through the monetization and storage of carbon dioxide.

Injection of carbon dioxide instead of iodinated contrast to display the common bile duct during endoscopic retrograde cholangiopancreatography.

Common bile duct (CBD) stones are usually caused by biliary tract infection, biliary stricture, duodenal peripapillary diverticulum, Oddis sphincter dysfunction, and so on. Treatment is preferably with endoscopic retrograde cholangiopancreatography (ERCP), where an iodine-containing contrast agent is injected into the CBD to display the stone under fluoroscopy and then to confirm complete removal of the stone(s). We described a 65-year-old woman with CBD stones who had undergone cardiac pacemaker implantation and was allergic to iodinated contrast media. We performed ERCP + lithotomy + stent implantation under local anesthesia, with injection of carbon dioxide instead of iodinated contrast into the CBD, and successfully visualized the stones under fluoroscopy and then confirmed complete removal of them. The patient was generally in good condition without complications. Thus, we have demonstrated in this case report that carbon dioxide can be used as a safe, economical, and effective alternative to iodinated contrast agent during ERCP.

STUDY OF THE POTENTIAL ANALGESIC PROPERTIES OF CARBON DIOXIDE FOR THE TREATMENT OF PAIN SYNDROME IN CASE OF OSTEOARTHRITIS

Pain syndrome is a serious global problem that causes and complicates a number of diseases, the main symptom of which is joint pain. One of them is osteoarthritis (OA). Traditional methods of treating OA often have limited efficacy and can cause side effects, so it is important to study new approaches, such as carboxytherapy (use of carbon dioxide). Objective. To investigate the analgesic effect of carbon dioxide (CO2) and its combined use with other agents. Methods. The efficacy of carbon dioxide injections used alone and in combination with other drugs was studied in a formalin model of inflammation in rats. Results. The latent periods of phases I and II increased significantly in the experimental groups, especially in groups V, VI and VII (p < 0.001), indicating a delay in pain reactions. The duration of pain phase I was significantly shorter in the groups receiving CO2 compared to the control group (p < 0.001). The shortest duration was observed in group V, where it decreased by 1.77 minutes. The duration of pain phase II was also significantly shorter in groups V, VI, and VII treated with CO2 compared to group II (p < 0.001). The difference ranged from 7.49 to 12.54 minutes. The number of pain reactions after phase I decreased by 13.25– 16.1 points in the groups receiving CO2 compared to the control group. The data obtained indicate that CO2 significantly increases the duration of latent periods of pain (by 55–65 %), reduces the duration of its phases (by 40–50 %) and reduces the intensity of pain reactions (by 40–50 %) in rats compared to control pathology. The most pronounced effect was observed with the combined use of CO2 with sodium diclofenac or chondroitin sulfate. Conclusions. The results of the study expand the understanding of the analgesic effect of CO2 on the formalin model of inflammation. The use of CO2 significantly reduced the duration of both phases of the pain reaction and reduced the number of painful manifestations, which confirms the prospects of its use as an additional, and in some cases the main means of reducing pain and inflammation.

Study on Adaptability of Progressing Cavity Pump for Huff-n-Puff Liquid Extraction Well

Abstract According to the deployment of “profile control, water shut-off, liquid extraction and liquid control” of the fault block, the development requirements of edge coordinated huff-n-puff and local liquid extraction, some oil wells in this fault block need to implement liquid extraction with large pumps. However, as the amount of carbon dioxide injection and the number of huff-n-puff rounds continue to increase, new problems are brought to the liquid extraction. The rotor, drive rod and oil pipe of the progressing cavity pump are prone to corrosion and even well lying. Secondly, the properties of the formation produced fluid change, and the produced fluid is mismatched with the progressing cavity pump stator, causing the progressing cavity pump stator rubber to swelling, degumm, and cause the pump to jam. With the gradual expansion of the application field of progressing cavity pump oil production technology, the continuous adjustment of oil field development technology policies, coupled with the changes in complex well conditions and production characteristics, Higher requirements have been put forward for its adaptability, and research work combining theory and practice needs to be continuously improved.

Dynamic wetting mechanism of coal under different CO2 pressure: A new analytical basis through T2 cutoff

The technology of injecting carbon dioxide into coal seams to reduce greenhouse gas emissions and has brought attraction on the wettability of coal. As a fast and non-destructive method, nuclear magnetic resonance (NMR) is widely used in the evaluation of coal wettability, but the inconsistency of analytical basis makes the quantitative evaluation of coal wettability changes uncertain. In this study, based on NMR combined with centrifugal experiments, a novel analytical basis using irreducible water defined by T2 cutoff value was proposed to quantitatively analyze the dynamic wetting mechanism under different CO2 pressures. The results show that when T2 < 72.32 ms, the water in coal is irreducible water; when T2 > 72.32 ms, the water in coal is movable water. CO2 pressure hindered free water conversion to adsorbed and capillary water, but impacted adsorbed water more. Increased CO2 pressure caused the wetting porosity of coal to decrease from 1.62 % to 1.08 %, and coal gradually changed from water-wet to CO2-wet. The increase in CO2 pressure enlarged the CO2 aggregations in the seepage channel, thus weakening the wetting rate of water to coal. CO2 preferentially occupied small pores, which will hinder the migration of water into small pore spaces. Molecular diffusion controls water to achieve wetting equilibrium more than gravity/pressure difference and capillary force. As CO2 pressure increases, the wetting equilibrium time decreases.

Analysis of Carbon Dioxide Injectivity and Dynamic Storage Capacity in Shale Reservoirs

Abstract Carbon dioxide could be stored in unconventional shale reservoirs in supercritical state due to available pore volume, infrastructure, and injectivity. However, there is a lack of knowledge about the injectivity and storage capacity in shale reservoirs. In this manuscript, a two-dimensional dual-porosity, dual-permeability model was built to investigate CO2 injectivity and dynamic storage capacity spatially and temporally. Parametric studies are conducted to evaluate the effect of matrix permeability, fracture conductivity, fracture half length, operating conditions, and near-wellbore connectivity on storage factors. Systematic and comprehensive numerical experiments are carried out using random sampling to generate a probability distribution of CO2 storage factors and replacement ratio. Results showed the parameters with most impact to least impact on injectivity and storage factor: matrix permeability, near-wellbore connectivity, bottomhole pressure, fracture half length, and fracture conductivity. The methodology in this study provides a foundation to examine how CO2 storage factors change spatially and temporally in and outside the SRV. The new understanding can be applied to optimize field development, well spacing, and infill drilling to increase economic storage.

A comprehensive mathematical model considering multiple mechanisms for CO2 displacement of methane in shale nanopores

With the rise in energy demand, shale gas exploitation has gained prominence, particularly through the use of carbon dioxide (CO2) injection for enhanced gas recovery. However, the intricate gas flow mechanisms within this process in shale nano-pores remain poorly understood, which greatly limited the accurate numerical simulation of shale gas production by CO2 injection. This study investigates the flow mechanisms of CH4 and CO2 gases in shale nano-pores, developing an improved apparent relative permeability model for the two-component CH4–CO2 gas, incorporating multiple transport mechanisms. Sensitivity analysis includes factors such as pressure, pore radius, viscosity correction effects, flow mechanisms, and composition fractions. Key findings from this study are as follows: (1) Increasing pore radius or decreasing pressure enhances the apparent permeability of CH4–CO2 gas, with pressure effects becoming negligible above 20 MPa. (2) The impact of viscosity correction on gas permeability diminishes with higher pressure or larger pore radius, becoming negligible for pore radii over 10 nm. (3) Larger pore radii increase slip flow and Knudsen diffusion, while molecular and surface diffusion proportions decrease; surface diffusion and slip flow dominate at high pressures. (4) A higher CH4–CO2 component ratio increases CH4 permeability and decreases CO2 permeability, with minimal influence from pressure and pore radius. These results can improve numerical simulations for shale gas production by using CO2 injection.

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

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

Dynamic wetting of a CO2-H2O-montmorillonite system using molecular dynamics

Injecting carbon dioxide into shale reservoirs achieves geological carbon sequestration (GCS), effectively reducing atmospheric carbon dioxide levels. Rock wetting characterizes the strength of the interaction between fluids and rocks, thereby determining fluid distribution, which is crucial for GCS trapping efficiency. In this study, the dynamic wetting of H2O-montmorillonite and CO2-H2O-montmorillonite systems was studied using molecular dynamics (MD) simulations. Montmorillonites with different lattice substitution arrangements based on pyrophyllite are strongly water-wet, and a precursor film forms at the leading edge of the bulk water. Na+ controls precursor film formation, which is rapidly spreading forward at a constant speed along the lattice substitution site lines based on Na+ distribution. The lower the proportion of Al3+/Si4+ lattice substitution in the Si-O tetrahedral layer on the fluid side, the higher the degree of water-wetness. The competitive adsorption of carbon dioxide and water molecules reduces the degree of spreading, resulting in a decrease in the degree of water-wetness. However, compared to the H2O-montmorillonite system, the spreading behavior remained unchanged. High carbon dioxide pressure caused the wetting to change from strongly water-wet to weakly water-wet, however no wetting reversal was exhibited. The wetting changes were particularly prominent near the supercritical carbon dioxide pressure, with a limit of 18 MPa. For the first time, this study distinguished the dynamic behaviors of bulk water and precursor films, revealed the formation mechanism of precursor films, and revealed the control mechanism of carbon dioxide pressure on dynamic wetting from a molecular perspective. The quantitative relationship between the contact angle and flow velocity at different carbon dioxide pressures presented in this study could effectively guide the establishment of a fluid force equation for infiltrating flow, providing theoretical support for GCS numerical simulation research.

Emerging advances in CO2 storativity and trappability within shale reservoirs

AbstractGeological carbon storage and utilization is widely regarded as the most realistic method of reducing carbon emissions throughout the energy transition era. In recent times, the implementation of carbon dioxide (CO2) injection has emerged as a potential method for increasing the recovery of hydrocarbon and facilitating the interaction of CO2 in shale reservoirs. This methodology enables the mitigation of total carbon emissions released into the earth's atmosphere. The concept of using CO2 geological sequestration in unconventional shale formations seems to be a prudent approach in responding to both the growing energy demand and mandating environmental requirements simultaneously. Shale reservoirs have received significant interest in the global context because to their substantial reserves and widespread distribution. This research offers a comprehensive analysis of the essential components involved in the sequestration of CO2 in shales, therefore improving the trapping and long‐term storage of CO2. In addition, it explores the extraction of hydrocarbons in this context. Gaining a comprehensive understanding of the fundamental factors that contribute to the storativity and trappability of CO2 is crucial for improving the displacement of methane gas (CH4) during shale gas recovery. This is particularly relevant in depleted the reservoirs of shale gas, where the aim is to enhance the effectiveness of in situ CO2 sequestration while reducing the leakage risk.

Leakage monitoring of carbon dioxide injection well string using distributed optical fiber sensor

Whether the oil and gas fields in the Carbon Capture, Utilization, and Storage (CCUS) project use underground storage or energy supplementation to enhance oil recovery, they must be injected or monitored through the wellbore. Thus, the foundation and requirement for the safety of carbon dioxide (CO2) storage is the wellbore's integrity. When CO2 is dissolved in water, carbonic acid is created, and this acid strongly corrodes underground pipes. Therefore, the integrity issue with CO2 injection wells is more noticeable than with other wellbores. An annular pressure during gas injection is the primary symptom of gas injection string leakage in CO2 injection wells. This study aims to provide real-time pipe string monitoring using a distributed optical fiber temperature sensing system (DTS) and a distributed optical fiber acoustic sensing system (DAS). Variations in temperature and vibration are caused by annulus pressure relief or gas injection. Optical fiber logging, in contrast to traditional logging, has better performance indicators for optical fiber sensing apparatus. To adapt to complex wellbore conditions, it is necessary to enhance the temperature accuracy of DTS and the sensitivity and signal-to-noise ratio of DAS in CO2 drive injection wells based on the features of the gas injection string. To differentiate the leakage signal from the regular fluid flow signal, the energy calculation in the frequency band is done for DAS based on noise reduction, and the signal processing in the frequency band is done by the spectrum characteristics of the CO2 wellbore signal. The translation invariant wavelet algorithm is the primary denoising method for DTS, overcoming the shortcomings of traditional wavelet threshold algorithms such as excessive smoothing and the pseudo-Gibbs phenomenon. Furthermore, the depth correction during the optical cable lowering process is also examined in this paper. A CO2 gas injection well field experiment was conducted using this technology. A 1671m well was dug, and 1631m of optical cable were installed in the tubing. The tubing leakage position was successfully identified through gas injection, annulus pressure relief, and a comparison of DAS and DTS data. The field results demonstrate the accuracy with which the gas injection string integrity can be accurately monitored in real-time using distributed optical fiber sensing technology for CO2 injection wells.

Analysis of intermediate cooling systems for CO2 compression trains of offshore oil wells

A multi-stage compression train with intermediate cooling used to inject carbon dioxide (CO2) in a well is modeled using two distinct configurations, direct and assisted cooling. The main difference between these configurations is that, in the latter, the process water responsible for the intermediate cooling is cooled down by a refrigeration cycle. These configurations are thermodynamically modeled while aiming to investigate the effect of key parameters on two main variables: (i) the overall global conductance and (ii) the overall power consumed by the compressors and auxiliary cooling systems. The results for direct cooling indicate that the power consumed by the compression train is inversely related to the global conductance, while an increase in the number of intermediate compression stages also reduces the global conductance. The assisted cooling, which considered 20 different working fluids for the refrigeration cycle, presented a minimal value for the global conductance for a given value of the overall power consumed by the compressors (train and refrigeration cycle). Finally, a comparison between both configurations reveals that while direct cooling offers a better compromise solution between global conductance and power consumption, assisted cooling can produce a significant reduction of global conductance.

Enhanced Oil Recovery through Carbon Dioxide Injection: A Compositional Simulation Approach

Enhanced Oil Recovery through Carbon Dioxide Injection: A Compositional Simulation Approach

Assessment of carbon dioxide transcritical cycles for electrothermal energy storage with geological storage in salt cavities

Carbon capture, utilisation, and storage (CCUS) technologies are envisaged as critical actors in the energy transition and climate change mitigation framework. Despite the recent advances in CCUS implementation, there is still significant scope for their growth and improvement. On the other hand, developing new large-scale energy storage systems is a key factor for the massive deployment of renewable energy systems. Technologies such as the electrothermal energy storage system based on carbon dioxide transcritical cycles incorporating geological storage (CEEGS) can contribute to both fields. Preliminary studies have shown that the integrated storage system can operate with roundtrip efficiencies exceeding 50%, injecting over 1 million tons of captured carbon dioxide (CO2) annually. It is an early-stage technology with open challenges for successful development, such as an adequate balance between the high- and low-temperature thermal storage reservoirs or the operation definition between the electrothermal system and the carbon dioxide injection and recovery. Underground pressures will oscillate with the charge/discharge process, with operational implications and constraints. Advancing in the concept requires the definition of optimised operation. This work presents a novel analysis of the adaptation of CO2 transcritical cycles to include injection and production processes with the specific scenario of salt cavities. It considers new modifications to adapt the transcritical cycles in closed-mode operation to the conditions required by the salt cavities injection and production processes. Different case studies are evaluated, evaluating the impact of injection and geological storage, production and surface storage, and reinjection into the geological formation. The analyses show roundtrip efficiencies within the range of 49.1–73.0% when the injection, production, and reinjection processes are executed.

EXPERIMENTAL RESEARCH OF THE PHARMACOLOGICAL EFFECT OF CARBON DIOXIDE IN THE CORRECTION OF INFLAMMATION

Osteoarthritis is considered one of the leading causes of chronic disability and is a significant problem on human health and the economy. Chronic pain is the dominant symptom that prompts patients to seek medical attention. Pain mechanisms in osteoarthritis remained unknown for a long time. However, it is known that chronic inflammation of the joint can be a key factor in the occurrence and exacerbation of pain or changes in the perception of pain. Pharmacological therapy is often based on the use of steroidal and non-steroidal anti-inflammatory drugs, but their long-term use or large doses can cause side effects. That is why the development of new methods of treatment of inflammatory processes is the object of active research, as they can affect various mechanisms. In this context, carboxytherapy is an interesting alternative or addition to existing treatment regimens aimed at reducing pain in patients with osteoarthritis. This method involves the administration of medical carbon dioxide (CO2) to improve blood supply to tissues, which can contribute to humoral, biochemical and tissue mechanisms. Studying the effects of carboxytherapy in animal models of inflammation is important for understanding its potential benefits and mechanisms of action. Objective. Study of anti-inflammatory properties of carboxytherapy both in monotherapy and in its combined use. Methods. Carboxytherapy is the injection of carbon dioxide in monotherapy and when used in combination on the formalin model of inflammation in animals. Results. The obtained research results prove the anti-inflammatory properties of carbon dioxide on the model of formalin inflammationin animals. Conclusions. The combined use of carboxytherapy enhanced the effect of conventional drugs on the formalin model of inflammation in animals. The establishment of an anti-inflammatory effect of carboxytherapy indicates the therapeutic value of CO2, while emphasizing the need for further in-depth studies to explore its mechanisms and confirm the efficacy for clinical use.

An Experimental Investigation of Surfactant-Stabilized CO2 Foam Flooding in Carbonate Cores in Reservoir Conditions

Carbon dioxide (CO2) injection for enhanced oil recovery (EOR) has attracted great attention due to its potential to increase ultimate recovery from mature oil reservoirs. Despite the reported efficiency of CO2 in enhancing oil recovery, the high mobility of CO2 in porous media is one of the major issues faced during CO2 EOR projects. Foam injection is a proven approach to overcome CO2 mobility problems such as early gas breakthrough and low sweep efficiency. In this experimental study, we investigated the foam performance of a commercial anionic surfactant, alpha olefin sulfonate (AOS), in carbonate core samples for gas mobility control and oil recovery. Bulk foam screening tests demonstrated that varying surfactant concentrations above a threshold value had an insignificant effect on foam volume and half-life. Moreover, foam stability and capacity decreased with increasing temperature, while variations in salinity over the tested range had a negligible influence on foam properties. The pressure drop across a brine-saturated core sample increased with an increasing concentration of surfactant in the injected brine during foam flooding experiments. Co-injection of CO2 and AOS solution at an optimum concentration and gas fractional flow enhanced oil recovery by 6–10% of the original oil in place (OOIP).

Understanding the phase behavior during CO2 flooding by dissipative particle dynamics

Understanding the phase behavior of a CO2-oil–water surfactant system is critical for carbon dioxide flooding engineering. Using dissipative particle dynamics, we investigate how the alkanes in crude oil are extracted after the injection of supercritical carbon dioxide into the formation, and what effect this extraction has on the miscible and immiscible displacement of carbon dioxide and crude oil. The images of the extraction are exhibited at the molecular level, and the effects of temperature and pressure on the extraction are investigated. The phase distribution of carbon dioxide, oil, and water under immiscible phase is simulated using actual reservoir fluid data based on a comprehensive understanding of extraction. Oil tends to be spread at the interface of carbon dioxide and water when it is immiscible. The miscible pictures were generated under conditions of reduced CO2-oil–water miscible pressure by adding surfactants to the CO2-oil–water system, and the fluid distribution characteristics under immiscible and miscible phases were examined. dissipative particle dynamics (DPD) simulation demonstrates that when the molar proportion of carbon dioxide is less than 0.4, the solid phase surface can always create a water film of varied thickness, regardless of whether the surface charge of the solid phase is positive or negative. As the molar fraction of carbon dioxide increases, the water film’s thickness decreases.