Injection Of Supercritical Carbon Dioxide Research Articles

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.

Explaining breakthrough behaviour in shale rock: influence of capillary effects and geomechanics

Abstract Shale rock, being a common caprock for carbon dioxide reservoirs, is subject to extensive research. One of the topics is breakthrough phenomena during injection of supercritical carbon dioxide in shale, the nature of which is still to be fully understood. In the present paper, a two-phase flow model, which may possibly be used to explain the breakthrough behaviour is examined. Capillary effects and geomechanics are included in the model, and influential model parameters are determined.

The effect of original and initial saturation on residual nonwetting phase capillary trapping efficiency

Injection of supercritical carbon dioxide (CO2) into geological formations is a strategy for both atmospheric greenhouse gas reduction (climate change mitigation) and enhanced oil recovery. To understand CO2 trapping efficiency, the capillary trapping behaviors that immobilize subsurface fluids were analyzed at the pore-scale using pairs of proxy fluids representing the range of in situ nonwetting and wetting fluid properties encountered in geologic storage reservoirs. The pairs of fluids were cycled through imbibition and drainage processes using a flow cell apparatus containing a sintered glass bead column. Computed x-ray microtomography (microCT) was used to identify immobilized nonwetting fluid after imbibition and drainage events. From microCT images, the trapped residual (post-secondary imbibition) nonwetting phase was spatially correlated to both the original (post-primary imbibition) and the initial (post-primary drainage) nonwetting phase; this relationship is referred to here as the original saturation dependence (SO-dependence) and initial saturation dependence (SI-dependence), respectively. Significant trends of decreasing SO- and SI-dependence with increasing wetting and nonwetting fluid phase viscosities were observed. This finding implies that the amount of CO2 injected and ultimately trapped is dependent on the nonwetting phase (e.g. oil or gas) already present in the formation, as well as on the manner in which supercritical CO2 is initially injected, which are factors not considered in current trapping models. To explore the potential effect that varying viscosity and interfacial tension (IFT) might have on this process, we report on a variety of fluid pairs with different viscosities and IFT.

Induced seismicity potential based on probabilistic geomechanics for the San Juan Basin CarbonSAFE project

Although geologic carbon sequestration projects have yet to induce — or may never induce — a damaging earthquake, experiences from other deep injection industries such as hydraulic fracturing, enhanced geothermal systems, and saltwater disposal suggest that effective quantitative seismic risk assessment is necessary for deep saline carbon capture and sequestration (CCS) projects. One such imminent CCS project is the San Juan Basin CarbonSAFE Phase III program. We use Monte Carlo probabilistic geomechanical analyses combined with observations of the geologic and operational parameters of the San Juan Basin site and suggest that this project is of low-induced seismic risk. The primary analysis is split into four sections. First, we assess the literature for faults and past seismicity, and at least five faulting scenarios are directly relevant. Second, we develop and calibrate an integrated earth model for the project site. Third, we perform Monte Carlo simulations that consider reasonable uncertainties of the geomechanical parameters. Of five tested faulting scenarios, only one presents high Coulomb failure functions, but fourth, we determine the risk to be low based on the combined lack of historical seismicity, the geologic framework of the faulting scenario, and the presence of saltwater injection at the same depth as the proposed supercritical carbon dioxide injection. The most sensitive parameters in the geomechanical calculations are the fault dip and the coefficient of friction. The least sensitive are the fault strike and the orientation of the maximum horizontal principal stress.

Geochemical and physical alteration of clay-rich shales under supercritical CO2 conditions

The injection of Carbon Dioxide (CO2) into shale gas formations is a promising approach that not only reduces the impact of greenhouse gas on climate change but also enhances the gas recovery due to geochemical interactions between CO2 and clay minerals. However, these geochemical interactions have not been fully explored and changes in the petrophysical properties of shales have been reported over time. This paper evaluates the geochemical reactions and physical changes caused by the injection of supercritical carbon dioxide (ScCO2) on the properties of clay-rich shales. Samples from the Eagle Ford formation were collected and exposed to ScCO2 at different pressures ranging from 10 to 24 MPa at 70 °C. Analytical methods such as X-ray diffraction (XRD), Fourier transform infrared spectroscopy (FTIR) and thin-section microscopy were used to characterize the ScCO2-treated samples. The results showed dissolution of clays and precipitation of quartz with increasing ScCO2 treatment pressure. The content of carbonate minerals was also reduced at high pressure, which can be attributed to the reactions of the dolomite with H+ to form magnesium carbonate. The percentage of absorption of aromatic hydrocarbons and oxygenated groups gradually increased with increasing pressure, which can be attributed to the increase in CO2 adsorption. On the other hand, the absorption of aliphatic and hydroxyl groups decreased after treatment. ScCO2 treatment pressure is an important factor to evaluate the CO2 adsorption capacity of clay-rich shales. The presented results enrich the understanding of the interactions between CO2 and shale under different pressures, which may be helpful to determine the feasibility of long-term injection and storage in shale.

Utilization of supercritical carbon dioxide for mechanical degradation of organic matters contained in shales

Supercritical carbon dioxide has been recently adopted to induce the initiation and propagation of hydraulic fractures. A rock matrix initially under reservoir conditions is subjected to high pressure by injected fluids, altering its stress state. A positive impact has been reported from the injection of supercritical carbon dioxide on the productivity of reservoirs, including in unconventional areas such as shale formations. However, the mechanisms by which supercritical carbon dioxide enhances fracture stimulation remain uncertain. Shale, which is a complex clastic sedimentary rock consisting of clay, quartz, calcite, and organic matter, responds to applied stresses based on the specific ratio of their constituents. The organic matter known as kerogen, composed of aromatic and aliphatic chains of carbon, is characteristically different from other inorganic minerals. Kerogen is scattered uniformly within a shale matrix. It is anticipated to exhibit a behavior similar to that of a polymer, and is capable of absorbing stresses without failure during fracturing jobs. Supercritical carbon dioxide injection is believed to alter the elasticity of kerogen, favoring fracture initiation. The objective of this work is to study the impact of supercritical carbon dioxide injection on kerogen’s geomechanics. At supercritical conditions, carbon dioxide interacts with kerogen, resulting in adsorption and, hence, swelling. Consequently, kerogen becomes more vulnerable to deformation under a given applied stress. The results of this research revealed a drastic change in mechanical behavior when carbon dioxide was used. The kerogen exhibited an inverse relationship between the degree of ductility and injection pressure of the carbon dioxide. The findings of this work provide nano-scale insights into the advantages of using supercritical carbon dioxide to degrade the mechanical integrity of organic matters contained in shales. These findings substantiate the value of carbon dioxide sequestration in shales. The outlined process has the benefits of both reducing greenhouse gas emissions and enhances the productivity of shales.

Progress and Prospects of Supercritical CO2 Application in the Exploitation of Shale Gas Reservoirs

The breakthrough of clean and efficient shale gas stimulation technology and reduction of global carbon emissions is in a critical period. The injection of supercritical carbon dioxide (SCCO2) into...

A Laboratory Approach to Measure Enhanced Gas Recovery from a Tight Gas Reservoir during Supercritical Carbon Dioxide Injection

Supercritical carbon dioxide injection in tight reservoirs is an efficient and prominent enhanced gas recovery method, as it can be more mobilized in low-permeable reservoirs due to its molecular size. This paper aimed to perform a set of laboratory experiments to evaluate the impacts of permeability and water saturation on enhanced gas recovery, carbon dioxide storage capacity, and carbon dioxide content during supercritical carbon dioxide injection. It is observed that supercritical carbon dioxide provides a higher gas recovery increase after the gas depletion drive mechanism is carried out in low permeable core samples. This corresponds to the feasible mobilization of the supercritical carbon dioxide phase through smaller pores. The maximum gas recovery increase for core samples with 0.1 mD is about 22.5%, while gas recovery increase has lower values with the increase in permeability. It is about 19.8%, 15.3%, 12.1%, and 10.9% for core samples with 0.22, 0.36, 0.54, and 0.78 mD permeability, respectively. Moreover, higher water saturations would be a crucial factor in the gas recovery enhancement, especially in the final pore volume injection, as it can increase the supercritical carbon dioxide dissolving in water, leading to more displacement efficiency. The minimum carbon dioxide storage for 0.1 mD core samples is about 50%, while it is about 38% for tight core samples with the permeability of 0.78 mD. By decreasing water saturation from 0.65 to 0.15, less volume of supercritical carbon dioxide is involved in water, and therefore, carbon dioxide storage capacity increases. This is indicative of a proper gas displacement front in lower water saturation and higher gas recovery factor. The findings of this study can help for a better understanding of the gas production mechanism and crucial parameters that affect gas recovery from tight reservoirs.

Hydrate prevention based on convection and diffusion in alternate injection wells of carbon dioxide and water

To prevent the formation of frozen hydrate blocks with the alternative injection of supercritical carbon dioxide and water after shut-in, the upper and lower interfaces of the frozen block sections in the injection well bore are calculated based on the temperature–pressure curves of the injection well and the hydrate phase equilibrium. The results show that for wells in which water and carbon dioxide are injected alternately, hydrate will be produced in the well bore after shut-in. the lower interfaces of the hydrate freeze plug in the well bore is above 141.36 m. Hydrate inhibitors can effectively prevent hydrate formation in wellbores, and the limit concentrations of methanol, ethanol, and ethylene glycol to inhibit hydrate freezing and blockage are 40%, 60%, 60%, respectively. In the initial state, there is a interface between the inhibitor and the formation water. The two-phase interface is blurred, and the inhibitor concentration in the upper part decreases when the wells have been shut for days. As the close-in time increased, the effective distance of action of the inhibitor decreased. The range of shut-in was 50–300 days, and the safety distance of the inhibitor should be controlled from 54 to 127 m below the frozen and blocked sections.

Time-Dependence of Mechanical Property Alterations on Anthracite Coals Treated by Supercritical Carbon Dioxide

The injection of supercritical carbon dioxide (Sc-CO2) into coal seams remarkably changes the physical-chemical structures of coal mass and thereby improves coal mechanical properties. In this study, a series of unconfined and triaxial compressive strength tests were performed on anthracite coal samples under the pressure of 8 MPa at the temperature of 35°C for 24 h and 48 h, respectively. Besides, experiments with longer Sc-CO2 treatment time were carried out on coal mass without stress constraint to observe the damage mode of coal. The results show that Sc-CO2 treatment obviously alters time-dependent mechanical properties of anthracite coal. The coal samples treated with Sc-CO2 for 240 h and 960 h show different damage modes from limited fractures to a complicated fracture network. The time-dependence of the mechanical weakening model on Sc-CO2-treated coal was proposed to explain the link between CO2 flow and mechanical weakening effect by means of physical-chemical effects on time scales.

A multiscale algorithm for the mineralization process during supercritical carbon dioxide injection into a deep saline aquifer

PurposeIn this work, it is presented a locally conservative multiscale algorithm accounting the mineralization process during the supercritical carbon dioxide injection into a deep saline aquifer. The purpose of this study is to address numerically the geological storage ofCO2in a highly heterogeneous reservoir, leading with interactions among several phenomena in multiple scales.Design/methodology/approachThis algorithm have features that distinguish it from the presently available solvers which are: (i) an appropriate combination of a coupled transport system solver using a high-order non-oscillatory central-scheme finite volume method and, elliptic numerical approach applying a locally conservative finite element method for Darcy’s law and, (ii) the capability of leading with interactions among several phenomena in multiple scales.FindingsAs a result, this approach was able to quantify the precipitation of the carbonate crystals at the solid interface.

Use of hot supercritical CO2 produced from a geothermal reservoir to generate electric power in a gas turbine power generation system

CO2 capture and sequestration in deep saline aquifers is widely considered to be a leading option for controlling greenhouse gas emissions. One such possibility involves injection of supercritical carbon dioxide into a high-permeability geothermal reservoir. In addition to the benefit of sequestering the CO2 in the reservoir, the CO2 can be used to mine geothermal heat for utilization above ground. This paper describes one of the options for generating power from hot supercritical CO2 obtained from CO2 production wells connected to a geothermal reservoir, where the original source of the CO2 is CO2 captured from fossil-fired power plants or industrial processes. The cost of power generated using CO2 produced from a geothermal reservoir with a gas turbine generation system is compared to the cost of generating power from a conventional geothermal steam power plant.

Injection of Supercritical Carbon Dioxide into Granitic Rock and its Acoustic Emission Monitoring

We injected carbon dioxide (CO2) into a hole drilled around 8 m long in a granitic hot rock from the floor of the tunnel. We drilled four AE (acoustic emission) monitoring holes parallel 1 m far away from the injection hole and monitored AE events induced with hydraulic fracturing (HF). When the breakdown (BD) pressure was recorded, the pressure and the temperature satisfied the supercritical condition of CO2. The AE source distribution showed that two vertical cracks were initiated from the injection hole with BD. After 75seconds from the occurrence of BD with no pressure increase, the AE sources started to distribute along the direction almost normal to that of the initial crack from the position around 0.7 m far away from the injection hole. It is most likely that the cracks initiated in intact rock with BD by HF and one of them bended and extended along pre-existing crack. These results suggest that CO2 migrates easily and enhances AE occurrence in a pre-existing joint.

Novel Dispersant for Formation Damage Prevention in CO2: A Molecular Dynamics Study

The injection of supercritical carbon dioxide (sc-CO2) into depleted or overproduced oil reservoirs has become a popular practice for enhancing oil recovery over the last several decades, because of the favorable mobility characteristics of miscible CO2 floods. Unfortunately, dissolved CO2 often causes mass precipitation of heavy-end hydrocarbon fractions such as asphaltenes, leading to formation damage. The prevention of formation damage ensuing from asphaltene deposition in porous rocks often requires the use of chemical additives such as solvents or inhibitors. Effective additives are able to disperse asphaltene aggregates by curbing their growth in the bulk phase. In particular, CO2-soluble polymers represent a promising type of asphaltene dispersants, since they can eliminate the need for large amounts of hydrocarbon solvent additives to injection mixtures. However, most of these polymers have been relatively untested and their interactions with asphaltenes in sc-CO2 are still unclear. In this study,...

Investigation of hydrodynamic instability of CO2 injection into an aquifer

The two-dimensional problem of supercritical carbon dioxide injection into an aquifer is solved. Shocks and rarefaction waves propagating in a sequence from an injection well into the formation are described within the framework of a complete nonisothermal model of flows in a porous medium. In the approximation of isothermal immiscible water and carbon dioxide flow the hydrodynamic stability of the leading displacement front is investigated for various reservoir pressures and temperatures. The parameters of unstable fronts are determined using a sufficient instability condition formulated in analytic form. The approximate analytic results are supported by the direct numerical simulation of CO2 injection using the complete model in which thermal effects and phase transitions are taken into account.

Heat mining assessment for geothermal reservoirs in Mexico using supercritical CO2 injection

A study was conducted to assess the feasibility of using supercritical carbon dioxide injection for heat mining from geothermal reservoirs in Mexico. Traditional water-based geothermal systems require significant amounts of water, a high permeability and porous formation, and sufficiently high subsurface temperatures. sCO2 (Supercritical CO2) is recognized to have good mobility and flow properties for heat recovery from geothermal reservoirs. Estimations of heat mining potential using sCO2 were performed using the TOUGH2 computer software. Simulations for three representative reservoirs in Mexico, Acoculco (Hot Dry Rock-HDR), Puruándiro (Deep Saline Aquifer-DSA) and Agua Caliente Comondú (Low Enthalpy Reservoir-LER), indicate that CO2-based systems have better heat mining potential than H2O-based systems. Results show enhanced heat extraction rates with sCO2 as high as 160 percent with respect to the H2O-based systems, with the heat mining benefit by sCO2 increasing in inverse proportion to the site subsurface temperature. Additional simulations for twenty-one geothermal sites estimate a total power generation potential with sCO2 of 1161 MWe. This represents a 51.4 percent additional power generation in comparison to water. Moreover, sCO2-based geothermal systems would be able to sequester in these twenty-one geothermal reservoirs (expected 30-year life of the reservoir) approximately 72 million tons of CO2.

Supercritical CO2 and brine displacement in geological carbon sequestration: Micromodel and pore network simulation studies

The competence of geological carbon sequestration to a large extent relies on the short-term injection efficiency and the long-term capillary trapping and geological stability. This study uses a high-pressure micromodel and pore network simulation to investigate pore-scale displacement phenomena during the injection of supercritical carbon dioxide (scCO2) into brine-saturated reservoirs. Results show that the brine displacement can be enhanced by increasing the scCO2 injection rate, but hindered by brine salinity which alters the interfacial contact properties and displacement patterns. The scCO2–brine displacement ratio increases with the capillary number Nc, increasing which by adding viscosifiers or surfactants would enhance the overall scCO2 injection efficiency in microscopic flows. Results also suggest that better injection efficiency and capillary trapping capacity can be achieved in reservoirs with more widely-distributed pore sizes. It is not evident that mutual solubility and upscaling using the Leverett-J function readily allow to expand the injection efficiency results of microscopic flows to reservoirs; yet, the effects of salinity and pore size distribution on the scCO2–brine displacement process remain pertinent in both microscopic and macroscopic flows through porous media.

An integrated site characterization-to-optimization study for commercial-scale carbon dioxide storage

Injection of supercritical carbon dioxide (scCO2) into deep saline aquifers is considered a promising option to mitigate global climate change. At a storage site, the main objectives of carbon dioxide sequestration are to maximize the volume of scCO2 injected and minimize the leakage risk, while effectively managing formation fluid pressure buildup and the brine displaced by scCO2. An integrated characterization-to-optimization study is carried out for potential commercial-scale deep saline aquifer carbon dioxide storage proposed in western Wyoming. A three-dimensional heterogeneous reservoir model is built for which petrophysical and fluid flow parameters are populated using field characterization data and state-of-the-art laboratory measurements. The measured scCO2 relative permeability end point is low compared to previous measurements on similar sandstones, which poses a challenge for CO2 flow, formation pressure control, and storage efficiency. By carefully selecting a set of optimal well locations, perforation intervals, and bottomhole pressure constraints that lead to maximum CO2-in-place and minimal CO2 breakthrough at the producers, an injection rate ranging from 10.8 to 15.1Mt/year is achieved for a duration of 50 years. After scCO2 injection ceases, up to 62% of the total injected scCO2 can be immobilized as residual scCO2 in 1000 years. Because of the low scCO2 relative permeability end point, post-scCO2-injection chase brine operation is not found to be an effective means of enhancing residual trapping. Instead, by modulating reservoir fluid pressure, boundary conditions of the reservoir exert a more significant impact on flow. Given the same well configuration and bottomhole pressure constraints, an open reservoir with lateral background flow allows 40% additional scCO2 injection compared to a compartmentalized system without background flow. However, background flow leads to a lower trapping efficiency – after 1000 years post-scCO2-injection, only 54% of the total injected scCO2 is immobilized as residual scCO2. This research suggests that a careful engineering design can contribute to significant CO2 storage at commercial scales while enhancing storage security. Site-specific multi-phase flow data should be measured for such a design, since for the study site, chase-brine operation is not effective when scCO2 relative permeability is low.

CO2 storage by sorption on organic matter and clay in gas shale

In the work described in this paper, we developed simulations of methane production and supercritical carbon dioxide injection that consider competitive sorption of methane (CH4) and carbon dioxide (CO2) on both organic matter and the clay mineral montmorillonite. We used the results of these simulations to assess the potential for storage of CO2 in a hydraulically fractured shale gas reservoir and for enhanced recovery of CH4. Assuming equal volume fractions of organic matter and montmorillonite, amounts of CO2 adsorbed on both materials were comparable, while methane desorption from clays was greater than desorption from organic material. CO2 injection simultaneous to CH4 production in two separate wells enhanced the contribution of methane desorption from 3535 to 6401metrictons, while storing 82metrickilotons of CO2.

Stress from NaCl crystallisation by carbon dioxide injection in aquifers

The goal of this paper is to identify the mechanical impact of water evaporation and salt crystallisation during supercritical carbon dioxide injection (drying-out process) in aquifer rocks. The precipitation of salt and the resulting crystallisation pressure are inferred from the chemical equilibrium of the carbon dioxide-rich gas phase, the in-pore brine and the crystal. The induced rock strain and equivalent tensile stress are then estimated within the framework of isotropic linear poroelasticity. A one-dimensional numerical simulation is conducted to illustrate the ability of the model to estimate the poromechanical behaviour of a structure submitted to a constant flow of nearly dry supercritical carbon dioxide.