Carbon Dioxide Injection Research Articles

Corrosion Analysis and Prevention of Tubing Nipples in Four Wells

A high-temperature and high-pressure gas field in an oil field requires the use of super 13 chromium material due to corrosive environments. In the recent production process, there have been four consecutive cases of corrosion, fracture, and perforation of tubing nipples, which have brought enormous economic losses to the oilfield. This article analyzes the failure causes of these four tubing nipples and proposes preventive measures. In this paper, the macroscopic morphology, chemical composition, mechanical properties, metallography, and microscopic morphology of four failed tubing nipples have been analyzed. Combined with the field service conditions and string structure of the tubing nipples, it is believed that the failure of the tubing nipples is mainly due to the connection of carbon steel and stainless steel materials, forming a typical galvanic corrosion galvanic cell. The geometric and environmental factors of the materials exacerbate this corrosion. Eventually, severe galvanic corrosion occurred on the inner surface of the tubing nipple, resulting in severe wall thinning or partial perforation, and four tubing nipples failed. The failed tubing nipples in Wells A, B, and C have erosion marks, which are caused by the action of high pressure and high flow rate fluids in the well; The inner surface of the tubing nipple in Well D is rusty yellow, mainly due to the corrosion of its inner wall caused by the acid fracturing fluid injected earlier. At the same time, the string structure of four wells shows that the tubing nipple is located at the variable diameter node of the string. When the fluid in the well flows from the large hole into the smaller hole, the fluid in the well will change there, and its flow rate and pressure will also increase, further exacerbating the erosion in this area. With the development of deep wells containing carbon dioxide in oil fields and the application of carbon dioxide injection secondary oil recovery technology, the use of 13Cr martensitic stainless steel is also increasing. In order to avoid the occurrence of similar accidents that will bring huge economic losses to the oil field, it is recommended that the material of the pipe string (including accessories) of such wells be confirmed using a portable direct reading spectrometer before entering the well.

Application of Pulse Neutron Oxygen Activation Logging in Carbon Dioxide Injection Wells

Carbon dioxide injection to improve oil recovery is an important link in carbon capture, utilization, and storage (CCUS) and an important means of tertiary oil recovery. Conducting gas injection profile logging in injection wells can reflect the inter-and intra-layer suction differences in gas injection wells, reveal the contradictions between injection and production, and provide a basis for gas plugging and profile control; The integrity of the wellbore is an important part of the storage stage of CCUS, which directly determines the burial and storage effect, and wellbore leakage directly affects the gas injection and oil displacement effect; The inspiratory index test can evaluate the formation's gas absorption capacity and provide a reasonable injection pressure of the formation at this stage. Since carbon dioxide gas usually exists in a supercritical fluid state in the wellbore, traditional logging techniques have certain limitations. This paper focuses on the adaptability research of pulse neutron oxygen activation logging principle and construction technology, and combined with the application example of gas injection wells in CCUS block of Huang3 District in Changqing Oilfield, it is clarified that the pulse neutron oxygen activation logging can be used to carry out suction profiling, suction index testing and wellbore integrity evaluation in carbon dioxide injection wells, and it has good application effects.

A novel approach to accelerate carbon dioxide sequestration of ladle furnace slag using sodium bicarbonate solution

The annual output of ladle furnace (LF) slag exceeds 20 million tons. The slag pulverises easily and contains heavy metals, leading to severe environmental pollution during stacking. However, slag issuitableas a material for carbon dioxide sequestration owing to its high calcium oxide content. This study focuses on exploring a new scheme because the direct carbonation method requires strict operating conditions and the indirect carbonation method hinders the materialisation of ladle furnace slag. In this new scheme, a sodium bicarbonate solution acts as the treatment solution for the carbonate LF slag, and the treated solution regenerates by injecting carbon dioxide. The experimental results show that the sodium bicarbonate concentration, stirring speed, and liquid-to-solid ratio have minor effects on the CO2 uptake percentage. With increasing reaction time, the CO2 uptake percentage increases during the first 120 min and then remains constant. The rise in temperature has a negative impact on the CO2 uptake percentage. However, decreasing the particle size of the LF slag greatly improves the CO2 uptake. CO2 injection at a flow rate of 1 L/min for 100 min decreased the pH of the treated solution to 8.9, achieving regeneration of the treated solution. Thermodynamic analysis indicates that for the reactions between sodium bicarbonate solution and minerals, calcium oxide and calcium aluminate have a significant thermodynamic driving force, indicating that slag with high basicity and CaO-Al2O3 base slag is moresuitedfor sequestering CO2. The study provides a novel method for CO2 sequestration and ladle furnace slag stabilization.

Enhancing shale gas recovery by carbon dioxide injection: A method of carbon capture, utilization and storage (CCUS)

CO2 injection in shale gas reservoir can not only increase the production of shale gas, but also realize carbon dioxide capture, utilization and storage. At present, most experimental studies of CO2 injection in shale are carried out by conventional core experiments. However, it is difficult to analyze the process of CO2 replacing shale gas and adsorption in shale pores on microscopic scale. In this study, nuclear magnetic resonance (NMR) technology is used to analyze the migration and conversion of CH4 in process of CO2 injection and depressurization production. Based on above experiments, microscopic mechanism of competitive adsorption of CH4 and CO2 during CO2 injection is clarified, and the stimulation mechanism of CO2 injection to improve shale gas recovery is further proposed. The results show that CH4 preferentially exists in form of adsorption state in shale. When CH4 adsorption amount reaches a certain degree, CH4 gas in form of free state gradually appears. During depressurization stage, further depressurization failed to promote the desorption of adsorbed gas when pressure reduced to 3 MPa. Therefore, adsorbed CH4 gas still exists after depressurization production. Shale has stronger adsorption capacity for CO2 than CH4. CO2 can replace CH4 adsorbed on the pore surface, and promote the desorption of adsorbed CH4 gas to free state. CO2 has the best displacement effect on adsorbed CH4 in pores with diameter of 15.04–21.62 nm, but it fails to replace CH4 in pores with diameter less than 1.08 nm. The competitive adsorption of CO2 and CH4 can effectively promote the further desorption of residual adsorbed CH4 gas after depressurization, and significantly improve the cumulative shale gas production.

Chemical dissolution of minerals in anthracite after supercritical carbon dioxide immersion: Considering mechanical damage and enhanced porosity

Carbon dioxide injection into in-situ coal seams can effectively enhance coalbed methane recovery and promote carbon sequestration, increasing energy production while reducing greenhouse gas emissions. CO2 is prone to exist in a supercritical state in deep coal seams, so it is of great significance to quantitatively describe the mechanical properties damage of coal caused by supercritical carbon dioxide (SC–CO2). Based on the non-equilibrium thermodynamic framework, a nonlinear model of SC–CO2–coal interaction is developed using the special forms of Helmholtz free energy and energy dissipation. Two damage variables are employed to quantify the irreversible degradation induced by chemical reactions and mechanical loads, respectively. The results indicate that the long-term effect of SC-CO2 can increase the porosity of anthracite by approximately 5.49%, but reduce the elastic modulus and strength by about 58% and 56% respectively. The experimental data confirms that the damage model facilitates an analysis of the interplay among SC-CO2 absorption, porosity, elastic modulus and tensile strength of anthracite. The degradation of anthracite mechanical properties is time-dependent, which means that the risk of coal-rock dynamic disasters increases with the passage of CO2 injection time. This work is expected to study the complex multi-field coupling mechanism of SC-CO2 on in-situ coal seams, providing a theoretical basis for guiding CO2 geological sequestration and CO2 enhanced coalbed methane recovery.

A Case of Air Embolism during Transoral Vestibular Endoscopic Thyroidectomy

Background: Carbon dioxide (CO2) embolism is a rare but potentially life-threatening complication of endoscopic surgery. While endoscopic thyroidectomy is superior to traditional open thyroidectomy in terms of cosmetic results, it may lead to venous or fatal paradoxical CO2 embolism. CO2 embolism involves the inadvertent injection of carbon dioxide into a large vein, artery, or solid organ. The clinical manifestations of CO2 embolism can vary from asymptomatic to neurological damage, cardiac failure, and even death, depending on the rate and volume of CO2 entry and the patient’s general condition. This case can enhance our understanding of CO2 embolization during endoscopic surgery. Case Presentation: This case report describes an incident in which a gas embolism occurred during endoscopic right lobe and isthmus thyroidectomy, resulting in arrhythmia and dramatic fluctuations in circulation and oxygen levels. The operation was halted, and CO2 injection was stopped. The surgical wound was covered with saline gauze, and the patient inhaled 100% pure oxygen while undergoing aggressive repeated manual pulmonary recruitment maneuvers. Additionally, vasoactive drugs such as m-hydroxyamine and ephedrine were administered to aid in treating the condition. The patient’s position was adjusted using the Durant maneuver (partial left lateral and Trendelenburg position). Following the aforementioned treatments, the patient’s ventricular arrhythmia transitioned back to a normal and regular sinus rhythm, and both circulation and oxygen levels stabilized. Conclusions: Carbon dioxide embolism is an uncommon yet potentially severe complication of laparoscopic procedures. We anticipate that this particular case will enhance our comprehension of carbon dioxide embolism during endoscopic surgery.

Microscopic and macroscopic assessment of carbonate dissolution for geologic {{hbox {CO}}_{2}} storage

Carbon capture and storage in underground formations might be considered as a relevant technology to curb anthropogenic climate gas emissions. However, carbon dioxide ({{hbox {CO}}_{2}}) injection can lead to severe rock-fluid interactions depending on the thermodynamic conditions, rock and fluids composition. The progressive dissolution of {{hbox {CO}}_{2}} in the formation brine results in mineral dissolution/precipitation processes that may drastically change the properties of the reservoir. This study is an attempt to get a deeper understanding of the dissolution/precipitation processes in a heterogeneous limestone at microscopic and macroscopic levels by a synergy between Isothermal Titration Calorimetry (ITC) and core flooding experiments with in-situ imaging to quantify uneven displacement fronts and understand the influence of reactions on a larger scale. Rock-fluid and fluid-fluid interactions, evaluated by ITC experiments, indicate that the carbonate dissolution is unfavorable with respect to enthalpy change but thermodynamically favorable with respect to entropy change (cations and hydrogen carbonate increase in the brine). Core flooding experiments with in-situ imaging by PET/CT show that complex pore structures cause a variation in the availability and ratio of the reactive fluid throughout the porous medium, hence, non-uniform dissolution was confirmed at core scale. The synergy between microcalorimetry and core flooding provides relevant insights into the dissolution of heterogeneous carbonate rocks at both microscopic and macroscopic scales.

ANALYSIS OF THE EFFICIENCY OF CARBON DIOXIDE INJECTION INTO CARBONATE FORMATIONS

This article raises the issue of development of deposits whose formations are composed of carbonate rocks. The low porosity and permeability of carbonate strata result in low oil production from these reservoirs. Therefore, these fields need to use enhanced recovery methods. A number of methods that have been relevant in the past do not achieve the desired result, so it is necessary to study in more detail new methods for increasing oil recovery. This paper discusses one of these methods for optimizing production, namely injection of carbon dioxide into the formation in order to increase the oil production of the formations. As you know, when injecting gas into the formation, in particular carbon dioxide, there are two main modes of oil displacement: the immiscible displacement mode, in which the gas is in a gaseous form and acts as a displacing agent, and the mixed displacement mode, in which the gas dissolves in oil, changes its properties, contributing to improving the conditions of its displacement. In the course of the work, a comparison of mixed and unmixed injection of carbon dioxide into the formation was made. The dissolution of the gas in the oil occurs at a certain pressure, which is called the miscibility pressure. During the work, the main factors affecting the mixing pressure were identified. The analysis of the effectiveness of the method was carried out by using a digital model. It was found that with mixed carbon dioxide injection, the recovery factor is greater. Shows the impact of carbon dioxide on the reservoir and reservoir fluid during injection. It has been established that carbon dioxide is capable of chemical reactions with rock. These chemical reactions have both positive and negative effects, increasing or decreasing porosity and permeability factors of the formations. The most optimal method of carbon dioxide injection has been determined. The dependence was obtained to determine the efficiency factor of oil production during carbon dioxide injection.

Experimental study of coal rank effect on carbon dioxide injection to enhance CBM recovery

Coal seam gas extraction is an important part of green mining. At the same time gas injection for enhanced coalbed methane recovery (ECBM) has been proposed as an environmentally friendly, low-carbon and effective technology to increase methane production. To study the influence of coal rank on carbon dioxide (CO2)-ECBM efficiency, lignite, bituminous coal, and anthracite were tested using the Gas Flow and Displacement Testing Apparatus (GFDTA). Data indicated that: (1) in lignite and anthracite, outflow CO2 and CH4 fractions changed at higher rates as compared with bituminous coal. At the end of the experiments, lignite and anthracite displayed CH4 outflow fractions of 0.19% and 7.73%, respectively; (2) at the initial stage of the experiments, permeability rapidly decreased. Later, a fast increase was followed by a stable phase. In lignite and anthracite, the increment in permeability during the rapid increase stage was significantly larger than that of bituminous coal. (3) The CH4 flow rate of the three coal ranks showed a decreasing trend. Before the breakthrough, CH4 flow rate decreased rapidly and slowed down. After the breakthrough, CO2 flow displayed a linear increasing trend and later reached stability. (4) In general, CH4 production increased with the increase in coal rank. The variation of CH4 production is manifested in two phases with different dominant factors. In the first stage, CH4 production was mainly affected by permeability, and followed the order lignite > anthracite > bituminous. In the second stage, CH4 production was mainly controlled by the displacement effect, following the order anthracite > bituminous coal > lignite.

Tremor signals during fluid injection are generated by fault slip.

Seismic tremor signals, also known as long-period, long-duration signals, have been reported in several locations where fluid injection for enhanced oil and gas exploration is taking place. However, the origin of these signals remains poorly constrained. We studied seismic tremor signals in Wellington Field, Kansas, using a seismic array during a carbon dioxide injection program. We show that these signals are generated below the surface during the time of carbon dioxide injection. They have a distinct spectral signature, similar to those observed in glacial and volcanic environments. The tremor sources are located near the injection site and aligned with preexisting faults. Modeling results imply that such tremors are generated by frictional slip on fault. These observations may reveal an important deformation mode, which is useful for studying associated stress, seismicity, and triggering, as well as for tracking fault activities during injection operations of all fluids, including supercritical carbon dioxide.

Low-Emission Waste-to-Energy Method of Liquid Fuel Combustion with a Mixture of Superheated Steam and Carbon Dioxide

Waste-to-energy approaches, aimed at using cheap energy carriers (oil production and refining waste, etc.), require the creation of new technologies with high energy efficiency and low emissions. One of the environmentally friendly methods is a superheated steam injection (SIM) into the combustion zone. At the same time, trends in CO2 reduction and recycling make carbon dioxide more attractive to use together with, or instead of, steam. This paper experimentally investigated the possibility of upgrading SIM to steam and the carbon dioxide injection method (SCIM) or the carbon dioxide injection method (CIM), where superheated steam and carbon dioxide are supplied together or completely replaced by CO2. In the example of diesel fuel, the characteristics of the combustion of liquid hydrocarbons in the presence of a mixture of superheated steam with CO2 in a spray burner are obtained and compared. It shows that a high completeness of fuel combustion is observed for all the studied modes. The analysis of combustion product composition demonstrates that when replacing the superheated steam with carbon dioxide, the levels of CO and NOx in the combustion products increase by 25%. All the investigated regimes comply with the EN:267 standard. The results obtained show that it is possible to realize SCIM and CIM approaches for waste-to-energy with the use of CO2.

A simulation and thermodynamic improvement of the methanol production process with economic analysis: natural gas vapor reforming and utilization of carbon capture

Abstract The current investigation proposes an efficient process to produce methanol through the natural gas vapor reforming and direct hydrogenating of CO2 that reduces CO2 emission. The proposed process includes methanol synthesis in the catalytic reactor with an injection of carbon dioxide recovered from the plant’s flue and separation of methanol by distillation. An Aspen HYSYS code analyzes the proposed plant to assess the energy, exergy, economic, and environmental performances. Also, the effect of captured CO2 flow on the methanol production, carbon efficiency, stoichiometric number of synthesized gas, and reboiler and condenser duties are investigated as a sensitivity analysis. The results indicate that the methanol production rate of 82,040 kg/h provides carbon, energy and exergy efficiencies of 85 %, 77.26 % and 77.32 %, which are higher than the similar proposed plants. Regarding exergy analysis, the total exergy destruction rate is about 238,468.21 kW, in which the reforming and burner sections contribute to the highest portions of about 47 % and 30 %. The global warming potential of the process is obtained at about 0.26 k g C O 2 , e q / k g M e O H ${\mathrm{k}\mathrm{g}}_{{\mathrm{C}\mathrm{O}}_{2,\mathrm{e}\mathrm{q}}}/{\mathrm{k}\mathrm{g}}_{\mathrm{M}\mathrm{e}\mathrm{O}\mathrm{H}}$ , which is reduced by captured CO2. The annual costs of investment and income are about 416,772,399 $ and 236,292,429 $, yielding 1.72 years payback period.

Intermittent injection of carbon dioxide to control the risk of coal spontaneous combustion and methane explosion: A case study in U-type ventilation

The compound risk of coal spontaneous combustion (CSC) and methane (CH4) explosion poses a serious threat to mining safety. Green resource utilization of carbon dioxide (CO2) can help achieve carbon neutrality. Therefore, CO2 is seen as a means to prevent compound risk of CSC and CH4 explosion. To address the situation at the 4209 working face, a multi-physical field coupling model was established to simulate the CSC and CH4 explosion in the gob of a U-type ventilation system. The accuracy of the model was verified against measured data from the gob. Following the injection of CO2 into the gob, the volume of the compound risk area was significantly reduced. The effects of intermittent CO2 injection were compared to those of continuous injection, and it was determined that intermittent injection was the preferred method, taking injection cost into account. Three injection frequencies were tested, with F= 1/2 d showing the optimal effect. When the injection frequency was set to F= 1/2 d, and three CO2 injection flow rates were tested, it was demonstrated that a flow rate of 141.3 m3/h provided the most effective risk reduction while meeting the required CO2 concentration in the working face.

The Effects of Cooling on Fine-Grained Sandstone in Relation to Wellbore Injection of Carbon Dioxide

AbstractIn Carbon Capture and Storage (CCS) procedures, it is important to determine the stability of the wellbore during carbon dioxide (CO2) injection and part of this involves assessing stresses on the rock near the wellbore due to changes in temperature and pressure. To address this, this study investigated the influence of cooling on the mechanical properties of a sandstone typical of those found in the central and southern North Sea. A series of uniaxial and triaxial compression tests was conducted on dry and saturated sandstone samples to determine the effects of cooling on the strength and stiffness under different confining pressures. The elastic modulus, shear modulus, bulk modulus and Poisson’s ratio were determined for three temperature conditions and three pressures representing different depths in a wellbore. Two methods, the International Society of Rock Mechanics (ISRM) and Wood’s (Soil behaviour and critical state soil mechanics. Cambridge University Press, Cambridge, 1990), were used to determine the mechanical properties of the rock during the Uniaxial Compressive Strength (UCS) tests. For the triaxial test, only Wood’s (1990) method was applied due to the existence of confining pressure. Microstructural analysis on thin sections of the sandstones under plane and crossed polarised light conditions in the deformed and undeformed state was conducted to elucidate deformation mechanisms and aid interpretation of experimental results. It was identified that both an increase in confinement and a reduction in temperature, increased the strength of the sandstone and reduced the Poisson’s ratio. Additionally, by decreasing the temperature, especially in the UCS test the material dilated less. This is an important outcome as expanding the results to a wellbore stability problem, brittle behaviour may be more apparent and damage may occur when sub-zero injection temperatures are applied, especially at the wellbore head, where confinement is low.

CO2 Injection for Enhanced Gas Recovery and Geo-Storage in Complex Tight Sandstone Gas Reservoirs

With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China’s oil and gas exploration and development is constantly improving, and the country is paying more and more attention to the exploitation and utilization of natural gas. The Upper Paleozoic tight sandstone in the Ordos Basin is characterized by low porosity, low permeability and a large area of concealed gas reservoirs. By injecting carbon dioxide into the formation, the recovery rate of natural gas can be improved, and carbon neutrality can be realized by carbon sequestration. Injecting greenhouse gases into gas reservoirs for storage and improving recovery has also become a hot research issue. In order to improve the recovery efficiency of tight sandstone gas reservoirs, this paper takes the complex tight sandstone of the Upper Paleozoic in the Ordos Basin as the research object; through indoor physical simulation experiments, carried out the influence of displacement rate, fracture dip angle, core permeability, core dryness and wetness on CO2 gas displacement efficiency and storage efficiency; and analyzed the influence of different factors on gas displacement efficiency and storage efficiency to improve the recovery and storage efficiency. The research results show that under different conditions, when the injection pore volume is less than 1 PV, the relationship between the CH4 recovery rate and the CO2 injection pore volume is linear, and the tilt angle is 45°. When the injection pore volume exceeds 1 PV, the CH4 recovery rate increases slightly with the increase in displacement speed, the recovery rate of CO2 displacement CH4 is between 87–97% and the CO2 breakthrough time is 0.7 PV–0.9 PV. In low-permeability and low-speed displacement cores, the diffusion of carbon dioxide molecules is more significant. The lower the displacement speed is, the earlier the breakthrough time is, and the final recovery of CH4 slightly decreases. Gravity has a great impact on carbon sequestration and enhanced recovery. The breakthrough of high injection and low recovery is earlier, and the recovery of CH4 is about 3.3% lower than that of low injection and high recovery. The bound water causes the displacement phase CO2 to be partially dissolved in the formation water, and the breakthrough lags about 0.1 PV. Ultimately, the CH4 recovery factor and CO2 storage rate are higher than those of dry-core displacement. The research results provide theoretical data support for CO2 injection to improve recovery and storage efficiency in complex tight sandstone gas reservoirs.

Innovative and sustainable cultivation strategy for the production of Spirulina platensis using anaerobic digestates diluted with residual geothermal water

The following study investigates the possibility of growing the Spirulina platensis (S. platensis) cyanobacteria on two agro-industrial anaerobic digestion (AD) digestates diluted with geothermal water. The two digestates (FAWD: Food and Agricultural Wastes Digestate and CDD: Cheese Diary Digestate) were selected based on their different chemical characteristics, attributed to the type of feedstock and the operating conditions used during the AD process. In the first part of the study, a screening experiment was performed in 200 mL glass tubes to evaluate the appropriate dilution factor to generate the maximum S. platensis growth using both AD digestates individually and geothermal water as sustainable alternative dilution agent. Based on the different growth parameters measured, dilution rates of 5x and 40x were chosen for CDD and FAWD respectively, as a trade-off between growth performances and quantity of water to use. Volumetric productivities of 33 ± 1 mg/L/d and 56 ± 8 mg/L/d combined with maximal concentrations of 0.52 ± 0.02 g/L and 0.69 ± 0.02 g/L were achieved when cultivating S. platensis on CDD and FAWD, respectively. In the second part, the selected experimental results were scaled-up to 6 L flat panels bioreactors and S. platensis biomass productivities of 71 and 101 mg/L/d were obtained for CDD and FAWD, respectively using sodium bicarbonate as inorganic carbon source. When regulating the pH to 8.5 with carbon dioxide (CO2) injection, cultures were able to produce up to 1.13 g/L and 0.79 g/L of S. platensis corresponding to biomass productivities of 81 and 136 mg/L/d for CDD and FAWD, respectively. In addition, S. platensis properly assimilated the ammonium present in the digestate-based culture media, with removal efficiency up to 98% in the case of the CDD substrate. The characterization of the final S. platensis biomass revealed the presence of high concentration of carbohydrates (48.6–70.3 % of dry weight) in the culture supplemented with both AD digestates. The experimental findings show the potential of reusing liquid digestate, CO2 as well as geothermal water for the sustainable production of carbohydrate-rich S. platensis biomass.

Waterflooding, water-gas method and generation of carbon dioxide in the reservoir – methods of enhanced oil recovery and technology development

This article discusses reservoir pressure maintenance methods: flooding and SWAG technology. The accumulated experience of waterflooding technology introduction described in literature sources is analyzed. Identified such disadvantages of waterflooding as reservoir watering due to significantly low viscosity compared to the viscosity of reservoir oils and low oil recovery factor. A method for detecting and preventing the instability of the front of displacement of residual reserves by injected water is indicated. Particular attention is paid to the innovative method of reservoir stimulation, which consists in the generation of carbon dioxide in reservoir conditions. The essence of the technology, method of implementation, advantages compared to gas injection through injection wells are described. Water-gas methods are investigated. The advantage of SWAG technology with the use of pump-ejector systems in comparison with other modifications is proved and the results of the latest research are presented, which cover data on the characteristics of pump-ejector systems, the topical issue of the technology for obtaining water-gas mixtures and the processes of interaction of gas bubbles when pumping mixtures through wells into the reservoir, as well as ways to implement the technology, taking into account the geological and field conditions of potential targets for implementation. This analysis will allow you to correctly choose the method of stimulation of the reservoir and operate the facilities as efficiently as possible. It should be noted that the considered gas and water-gas methods involve the injection of carbon dioxide, associated, exhaust, flue gases into the reservoir, which makes these technologies the most attractive from an environmental point of view.

Effect of damage zone around borehole on carbon dioxide injection promoted gas extraction in soft and low-permeability coal seam

Effect of damage zone around borehole on carbon dioxide injection promoted gas extraction in soft and low-permeability coal seam

Nanocomposite of binary colloids in effective CO2 utilization in porous media for enhanced oil production and wettability alteration

Carbon dioxide injection is a renowned enhanced oil recovery method, where the inclusion of a novel material is appreciated via mobility control of injected CO2 during flow through porous and permeable oil reservoirs. Therefore, the combination of nanoparticles and their associated additives is recommended for foam flooding schemes. Thus, this study reports the use of nanocomposites of SiO2 (0.1 – 2 wt%) and TiO2 (0.1 wt%) in promoting CO2 utilization in oil recovery projects. The assessment of a foam emulsion is a crucial and interesting task to understand the basic fundamental of three-phase interactions viz., Crude oil (oil phase), nanocomposites (aqueous phase), and CO2 (gas phase) in the context of foam-emulsion, and was examined via microscopic and rheological characterization. CO2 foam showed temperature tolerance capability and a shear-thinning viscoelastic nature due to the inclusion of nanocomposites. Furthermore, wettability alteration was understood via contact angle measurements between CO2 and nanocomposite. Interestingly, the contact angle was reduced to 39° after the inclusion of 0.1 wt% TiO2 and CO2 in the system. Finally, nanocomposite stabilized CO2 foam demonstrated a total cumulative oil recovery of 78 % at (40 °C), higher than the cumulative oil recovery (70 %) associated with nanocomposite without CO2. The results of this study suggest that CO2 utilization for oil recovery can be enhanced by developing its viscous foam, stabilized by a nanocomposite of SiO2 and TiO2 nanoparticles.

Implications of chemical agents and nanofluids coupled with carbon dioxide to improve oil recovery factor

In this study, we experimentally investigated the effects of chemically enhanced oil recovery methods containing hydrolyzed polyacrylamide (HPAM), surfactant–hydrolyzed polyacrylamide (SHPAM), surfactant nanofluids (SNF), that is, coupled with carbon dioxide (CO2) and water chase injection to measure enhanced oil recovery methods in a sandstone reservoir. To proceed with the experiments, we performed four flooding tests at the simulated reservoir temperature of 70 °C. The sand packs were saturated with oil to establish the irreducible water saturation (Swr). Then, the fluid flow in sand packs remained undistributed for about 5 days to obtain the 1.5 pore volume (PV). We observed that the pressure drop had small fluctuations when there was waterflooding (until 1.5 PV), and after injecting the chemical agents, the pressure drop had a sharp rise. It is indicated that the chemical solution has implemented higher pressure drops (significant energy efficiency) to displace the oil instead of water. The maximum oil recovery factor was about 53% and 59% when HPAM and SHPAM solution displaced oil after waterflooding, respectively; however, it is observed that water chase flooding recovered about 8% and 14% of remaining oil in place while CO2 has increased only 3% and 5%, respectively. SNF solution can provide more oil recovery factors. It is about 72% (SNF with 0.5 wt%) and 67% (SNF with 1 wt%). We observed that water chase flooding recovered about 20% of oil in place while CO2 increased by only 8%. It was concluded that the SNF solution with 0.5 wt% tends to adhere to the water–CO2 and causes to improve oil recovery factor after SNF injection. Therefore, SNF is the optimum enhanced oil recovery method among other chemical agents. On the other hand, with the decrease in CO2 flow rate and increase in silica nanoparticles slug size, pressure drop has started to decrease in higher pore volume injections, indicating that larger volumes of CO2 can be stored in sand packs. However, by increasing the CO2 flow rate and decreasing silica nanoparticles slug size, CO2 can escape easily from the sand pack.