CO2 Injection Pressure Research Articles

Laboratory measurement of deformation-induced hydro-mechanical properties of reservoir rock in deep saline aquifers: An experimental study of Hawkesbury formation

The long-term integrity of CO2 storage in deep saline aquifers has become uncertain due to the unsteady character of surrounding factors, and the time-dependent nature of the aquifer's overburden load (the vertical stress imposed on the aquifer by the weight of overlying materials (rock/soil layers), which may vary over time as a result of natural incidents such landslides and earthquakes) is critical. The aim of this study is to identify the influence of overburden load variations on the long-term integrity of the CO2 storage process in deep saline aquifers. High-pressure tri-axial strength and permeability tests, along with acoustic emission (AE) and scanning electron microscopy (SEM) analyses, were conducted on Hawkesbury sandstone obtained from the Gosford basin.According to the results, the injection of CO2 into the Hawkesbury formation may dissolve aquifer rock minerals, enhancing aquifer flow performance and reducing aquifer strength. Increasing the stress applied on the aquifer causes aquifer flow ability to reduce to some extent due to pore matrix compaction. Further increase of the overburden pressure may accelerate the aquifer's flow performance due to dilation-induced pore opening. This permeability transition point occurs earlier at greater CO2 injection pressures and overlaps with the crack formation point of the aquifer rock mass. Therefore, weakening of the rock mass after the transition point can be expected. Importantly, this permeability transition point occurs at lower overburden loads after longer interaction of CO2 with the saline aquifer. This exhibits the long-term risk associated with CO2 sequestration in saline aquifers. Permeability enhancement after the transition point may also produce environmental disasters, such as sudden leakages of injected CO2 from the reservoir to surrounding fresh water aquifers (Evans et al. 2004; Little and Robert 2010), exceeding the specific rates proposed by many regulatory frameworks. Therefore, it is essential to study the long-term integrity of the sequestration process in order to develop a regulatory structure to meet the demands of deep saline sequestration projects.

Coupled solid and fluid mechanics simulation for estimating optimum injection pressure during reservoir CO2-EOR

Reservoir geomechanics can play an important role in hydrocarbon recovery mechanism. In CO2-EOR process, reservoir geomechanics analysis is concerned with the simultaneous study of fluid flow and the mechanical response of the reservoir under CO2 injection. Accurate prediction of geomechanical effects during CO2 injection will assist in modeling the Carbon dioxide recovery process and making a better design of process and production equipment. This paper deals with the implementation of a program (FORTRAN 90 interface code), which was developed to couple conventional reservoir (ECLIPSE) and geomechanical (ABAQUS) simulators, using a partial coupling algorithm. A geomechanics reservoir partially coupled approach is presented that allows to iteratively take the impact of geomechanics into account in the fluid flow calculations and therefore performs a better prediction of the process. The proposed approach is illustrated on a realistic field case. The reservoir geomechanics coupled models show that in the case of lower maximum bottom hole injection pressure, the cumulative oil production is more than other scenarios. Moreover at the high injection pressures, the production rates will not change with the injection bottom hole pressure variations. Also the FEM analysis of the reservoir showed that at CO2 injection pressure of 11000 Psi the plastic strain has been occurred in the some parts of the reservoir and the related stress path show a critical behavior.

Simulation and analysis of lithology heterogeneity on CO2 geological sequestration in deep saline aquifer: a case study of the Ordos Basin

A simplified two-dimensional axisymmetric model was established based on a typical continental sedimentary basin in China to simulate the thermal evolution of wellbore and reservoir during the injection of CO2 by taking consideration of lithology heterogeneity of reservoir. By comparing with two simple one-dimensional theory models, the lithology heterogeneity influence on CO2 mass flow rate distribution along depth in the wellbore is identified. Results suggested that the interaction of multiple layers in the heterogeneous reservoir will influence the CO2 mass flow rate distribution along depth in the wellbore so as to impact the corresponding temperature and pressure evolution in the wellbore and reservoir. Layer burial depth (or relative location), porosity, permeability and thickness are all important factors that affect CO2 mass flow rate in wellbore. The variation of CO2 mass flow rate in the wellbore will change the CO2 temperature flowing into each layers through impact the heat extraction from rocks, compressibility of CO2 and potential energy loss, and by varying the CO2 hydrostatic pressure and pressure drop due to friction to determine the CO2 injection pressure. Layer burial depth, porosity, permeability and thickness are all important factors that affect the CO2 mass flow rate distribution in the wellbore. This study may help deepen our understanding of CO2 flow and thermal evolution in the actual heterogeneous reservoir and provide important knowledge supplement for the liquid injection (especially CO2) into underground, such as deep saline aquifer, depleted oil/gas reservoir and coal bed.

Numerical simulation and optimization of CO2 utilization for enhanced oil recovery from depleted reservoirs

Due to concerns about rising CO2 emissions from fossil fuel power plants, there is strong emphasis on the development of an economical method for Carbon Capture Utilization and Storage (CCUS). One area of current interest in CO2 utilization is the Enhanced Oil Recovery (EOR) from depleted reservoirs. The efficiency of the oil extraction is highly dependent on the CO2 injection rate and injection pressure. Before large scale deployment of this technology can occur, it is important to understand the mechanisms that can maximize the oil extraction efficiency as well as the CO2 sequestration capacity by optimizing these injection parameters. In this paper, numerical simulations of subsurface flow in an EOR system is conducted using the multiphase flow solver package COZView/COZSim developed by Nitec, LLC. The CO2 injection is optimized for both constant rate and pressure-limited injection scenarios using a genetic algorithm based optimizer integrated with COZSim, and the effect of recycled gas is investigated. Optimization of the EOR system results in an increased recovery factor with a more efficient utilization of injected CO2. The results of this study pave the way for future optimization of other systems such as Enhanced Gas Recovery, Enhanced Water Recovery, and Enhanced Geothermal Systems that are currently being considered for CCUS.

Characterization of Produced and Residual Oils in the CO2 Flooding Process

In immiscible CO2 flooding processes, the injected CO2 extracts light and intermediate components from reservoir hydrocarbons, changing the properties of both the produced and residual oils. CO2 injection also increases asphaltene precipitation, which further causes adverse effects on the oil effective permeability, operational facilities, and the oil recovery. In this study, six CO2 flooding followed by blowdown processes are carried out in the laboratory under four CO2 injection pressures and two temperatures, and the properties of produced and residual oils are further characterized. It is found that uneven residual oil distribution occurred due to the coupled effects of viscous fingering and oil properties changes during CO2 flooding process. Characterization of the produced oil shows that both the produced oil density and viscosity decrease when CO2 injection pressure increases. The asphaltenes content of the oil produced after CO2 breakthrough is found to be relatively lower than that of the oil sam...

CO2huff and puff for heavy oil recovery after primary production

In this study, micromodel tests were performed to investigate the microscopic flow behavior during primary production and the subsequent CO2 huff and puff. A series of 12 tests was conducted in sandpacks to evaluate the effects of the injection and production parameters on the displacement efficiency of the CO2 huff and puff. The micromodel tests and sandpack tests showed that the flow characteristics of CO2 huff-and-puff process was significantly affected by the pressure of converting the solution gas drive to the subsequent CO2 huff and puff. A foamy oil flow could be more easily formed in the production period of the CO2 huff and puff with a higher conversion pressure. Foamy oil can reduce the mobility of gas and provide tremendous energy to the system, thereby improving the performance of the CO2 huff and puff. The sandpack flood results show that the oil recovery of the solution gas drive decreased as the conversion pressure increased, whereas the oil recovery of the CO2 huff and puff increased as the conversion pressure increased. The highest total oil recovery was obtained at the pseudo-bubblepoint pressure. The oil recovery of the CO2 huff and puff increased as the CO2 injection pressure and pressure decline rate increased. The oil recovery of CO2 huff and puff increased with the soaking time, and it exhibits a significant change when the soaking time ranges from 10 h to 24 h; above this value, the increase become slight. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd

Molecular simulation studies of hydrocarbon and carbon dioxide adsorption on coal

Sorption isotherms of hydrocarbon and carbon dioxide (CO2) provide crucial information for designing processes to sequester CO2 and recover natural gas from unmineable coal beds. Methane (CH4), ethane (C2H6), and CO2 adsorption isotherms on dry coal and the temperature effect on their maximum sorption capacity have been studied by performing combined Monte Carlo (MC) and molecular dynamics (MD) simulations at temperatures of 308 and 370 K (35 and 97 °C) and at pressures up to 10 MPa. Simulation results demonstrate that absolute sorption (expressed as a mass basis) divided by bulk gas density has negligible temperature effect on CH4, C2H6, and CO2 sorption on dry coal when pressure is over 6 MPa. CO2 is more closely packed due to stronger interaction with coal and the stronger interaction between CO2 molecules compared, respectively, with the interactions between hydrocarbons and coal and between hydrocarbons. The results of this work suggest that the “a” constant (proportional to T 2 /P c ) in the Peng–Robinson equation of state is an important factor affecting the sorption behavior of hydrocarbons. CO2 injection pressures of lower than 8 MPa may be desirable for CH4 recovery and CO2 sequestration. This study provides a quantitative understanding of the effects of temperature on coal sorption capacity for CH4, C2H6, and CO2 from a microscopic perspective.

A Laboratory Investigation of Permeability of Coal to Supercritical CO2

The kinetics of gas–coal interaction during coalbed methane (CBM) recovery and/or carbon dioxide sequestration in coal has been subject of investigation over past few years. Swelling of coal matrix due to gaseous phase CO2 injection is now well established through laboratory experiments and field validations. Further, fluid exchange or flow in coal alters effective stresses in the underground environment. These significantly affect the permeability characteristics of coal and therefore influence the gas recovery/injection projects. Most research works on coal seam sequestration have been carried out for gas or liquid phase CO2. Considering the pressure–temperature conditions of deep seated coal, studies are now being done on supercritical CO2 flow and adsorption in coal. A newly developed experimental set up was utilized to replicate the underground conditions in laboratory to investigate the (1) initial N2 permeability of coal, (2) supercritical CO2 permeability of coal, (3) effects of CO2 sorption on N2 permeability of coal. The temperature of the set up was maintained at 33 °C while CO2 injection pressures were varied between 11 and 15 MPa at a range of 16–24 MPa confinements, and N2 was used as a relatively neutral medium to estimate the loss in permeability due to supercritical CO2 flow. The results indicate that high adsorption of supercritical CO2 in coal led to significant reduction in permeability. On increasing the confining pressure, further decline in the permeability was recorded. CO2 becomes liquid-like with increasing confining pressures and the coal–fluid interactions change, causing high sorption and matrix swelling, leading to reduced permeability in coal. This explains why substantial decline in the injection rate of CO2 was observed progressively in most CO2 sinks.

Optimization of enhanced coal-bed methane recovery using numerical simulation

Although the enhanced coal-bed methane (ECBM) recovery process is one of the potential coal bed methane production enhancement techniques, the effectiveness of the process is greatly dependent on the seam and the injecting gas properties. This study has therefore aimed to obtain a comprehensive knowledge of all possible major ECBM process-enhancing techniques by developing a novel 3D numerical model by considering a typical coal seam using the COMET 3 reservoir simulator. Interestingly, according to the results of the model, the generally accepted concept that there is greater CBM (coal-bed methane) production enhancement from CO2 injection, compared to the traditional water removal technique, is true only for high CO2 injection pressures. Generally, the ECBM process can be accelerated by using increased CO2 injection pressures and reduced temperatures, which are mainly related to the coal seam pore space expansion and reduced CO2 adsorption capacity, respectively. The model shows the negative influences of increased coal seam depth and moisture content on ECBM process optimization due to the reduced pore space under these conditions. However, the injection pressure plays a dominant role in the process optimization. Although the addition of a small amount of N2 into the injecting CO2 can greatly enhance the methane production process, the safe N2 percentage in the injection gas should be carefully predetermined as it causes early breakthroughs in CO2 and N2 in the methane production well. An increased number of production wells may not have a significant influence on long-term CH4 production (50 years for the selected coal seam), although it significantly enhances short-term CH4 production (10 years for the selected coal seam). Interestingly, increasing the number of injection and production wells may have a negative influence on CBM production due to the coincidence of pressure contours created by each well and the mixing of injected CO2 with CH4.

Effect of Salinity on Effective CO2 Permeability in Reservoir Rock Determined by Pressure Transient Methods: an Experimental Study on Hawkesbury Sandstone

The determination of effective carbon dioxide (CO2) permeability in reservoir rock and its variation is of great interest in the process of CO2 sequestration in deep saline aquifers, as CO2 sequestration-induced permeability alternations appear to create major problems during the CO2 injection process. The main objective of this study is to investigate the effect of salinity on the effective CO2 permeability of reservoir rock under different injection pressures. A series of high-pressure tri-axial experiments was, therefore, performed to investigate the effect of salinity on effective CO2 permeability in Hawkesbury sandstone under various brine concentrations. The selected brine concentrations were 0, 10, 20, and 30 % sodium chloride (NaCl) by weight and the experiments were conducted for a range of CO2 injection pressures (2, 4, 6, 8, 10, and 12 MPa) at a constant confinement of 20 MPa and a temperature of 35 °C, respectively. According to the results, the degree of salinity of the aquifer’s pore fluid plays a vital role in the effective CO2 permeability variation which occurs with CO2 injection, and the effective permeability decreases with increasing salinity in the range of 0–30 % of NaCl. Interestingly, in dry reservoir rock samples, the phase transition of the injection of CO2 from gas to super-critical condition caused a sudden reduction of CO2 permeability, related to the slip flow effect which occurs in gas CO2. Transfer into vapor or super-critical CO2 causes this slip flow to be largely reduced, reducing the reservoir permeability for CO2 movement in dry reservoir rock samples. However, this behavior was not observed for water- and brine-saturated samples, and an increasing trend of effective CO2 permeability was observed with increasing injection pressure. A detailed chemical analysis was then conducted to understand the physical phenomenon causing the salinity effect on effective CO2 permeability using scanning electron microscopy analyses. Such analyses explain the reason for the observed permeability variations by giving detailed images of the rock sample’s microstructure. There were clear depositions of NaCl crystals in the rock’s pore space, and the amount increased with increasing brine concentration.

Effect of CO2 injection on heterogeneously permeable coalbed reservoirs

Enhanced coalbed methane (ECBM) can be recovered by injecting a gas such as carbon dioxide into the reservoir to displace methane. The contrast between density, viscosity, and permeability of the resident and displacing fluids affects the efficiency of ECBM recovery. The prediction of earlier breakthrough becomes complex as the permeability may vary by orders of magnitude during gas injection and methane recovery. Predominantly, the reservoir permeability is modulated by the pore pressure of the sorptive gas (CH4 and CO2) and effective stresses. Here we explore the possibility of early breakthrough and its implications for managing coalbed reservoirs during CO2 assisted ECBM. A coupled finite element (FE) model of binary gas flow, diffusion, competitive sorption and permeability change is used to explore the effect of CO2 injection on net recovery, permeability evolution and injectivity in uniform and homogeneously permeable reservoirs. This effect is evaluated in terms of dimensionless pressure (pD), permeability (kD) and fracture spacing (xD) on the recovery of methane and permeability evolution for ECBM and non-ECBM scenarios. We have considered two scenarios (4MPa and 8MPa) of constant pressure injection of CO2 for ECBM. The increase in production rate of CH4 is proportional to kD but inversely proportional to xD.Further, a reservoir with initial permeability heterogeneity was considered to explore the effect of CO2 injection on the evolution of permeability heterogeneity – whether heterogeneity increases or decreases. The evolution of permeability heterogeneity is investigated for the same two CO2 injection scenarios. For the specific parameters selected, the model results demonstrate that: (1) The injection of CO2 in coalbed reservoirs increases the production nearly 10-fold. (2) At higher injection pressures the recovery is rapid and the production increases dramatically – the production increases 2-fold on increasing the CO2 injection pressure from 4MPa to 8MPa. (3) However, CO2 breakthrough occurs earlier at higher injection pressures. (4) The permeability heterogeneity in the reservoir is reduced after a threshold time (∼500days) although the overall heterogeneity is increased relative to the initial condition and is overall increased for both non-CO2 and CO2 injection scenarios. This indicates that the homogenizing influence of CO2-sorption-swelling is outpaced by CH4-desorption-shrinkage and effective stress influences. This leaves the reservoir open to short-circuiting and earlier breakthrough of CO2 rather than having this effect damped-out by the homogenizing influence of swelling. (5) The cumulative volume of CO2 produced and stored in the reservoir is proportional to the injection pressure.

The Sensitivity Analysis of Wellbore Heat Transfer during the CO<sub>2</sub> Injection Process

The sensitivity analysis of wellbore heat transfer during the CO2injection process is of vital importance to Carbon dioxide utilization and sequestration (CCUS). A numerical simulation method is developed to simulate the process of wellbore heat transfer during injecting carbon dioxide by amending the classical heat transfer modelRamey models. It analyses how the selected parameters affect the distribution of the wellbore temperature and pressure, which include CO2injection temperature, pressure and density, the injection flow rate and Joule Thomson coefficient. The results show that, CO2injection temperature has greater impact on the initial level of the temperature distribution; higher injection pressure raises the temperature mainly because of the effect of Joule Thomson coefficient; also, when the injection process lasts a longer time, the distribution is much more stable. When the injection flow rate is higher, the strata temperature has less influence on the flow temperature. The injection pressure and density has very appreciable effect on the pressure distribution. However, the other parameters have less influence on it. The modified simulation method was applied in Jiangsu Caoshe oil field and the simulation results coincided with the measuring data well.

N2-CO2 co-injection field test at the Ketzin pilot CO2 storage site

In summer 2013, a four week N2-CO2 co-injection field test was conducted at the Ketzin pilot site. Major objectives were (i) demonstrating the technical feasibility of a continuous N2-CO2 co-injection scenario, (ii) monitoring wellhead and reservoir pressure, (iii) monitoring spreading and behavior of the CO2-N2 gas mixture in the reservoir, and (iv) analyzing potential chromatographic effects within the reservoir. 10,000 L (10 Nm3) of krypton (Kr) were injected as an additional conservative chemical tracer prior to injection of the N2-CO2 gas mixture. For the field test CO2 from a natural CO2 source with a much heavier carbon isotope composition (δ13C=-3.4±0.2‰) was injected instead of the previously used industrial CO2 (δ13C=-30.6±0.4‰) from a refinery process to allow for examination of isotopic effects. Vital parameters during monitoring include N2 and CO2 injection rates, pressure and temperature at injection and observation wells, and reservoir pressure, respectively. A capillary riser tube was used to collect reservoir fluid and gas samples. These were analyzed for gas and carbon isotope compositions. Preliminary results show successful realization of the N2-CO2 co-injection field test next to effective and permanent monitoring of the injected gases (N2, CO2 and Kr) and vital storage parameters (wellhead pressures, reservoir pressure and reservoir temperature). During the field test, 32 t of N2 and 613 t of CO2 were co-injected in total to ensure a CO2:N2 volume ratio of approximately 95:5. Despite some variation of both N2 and CO2 injection rates, wellhead pressure and reservoir pressure were well controlled during the entire field test, and thereafter. Based on δ13C data, the gas mixture arrived after about 17 days at the first observation well (Ktzi 203) located at about 25 m distance to the injection well (Ktzi 201). Increasing Kr concentrations at Ktzi 203 positively correlate with both increasing N2 concentrations and δ13C values. Additionally, the δ13C data also indicate mixing between natural and industrial CO2 within the reservoir.

Effect of temperature on permeability of geopolymer: A primary well sealant for carbon capture and storage wells

Geological sequestration of carbon dioxide has been found to be the most promising solution to reduce anthropogenic greenhouse gas emissions without affecting the usage of fossil fuel. Wellbore integrity needs to be maintained for leak-free storage and well cement plays a major role in wellbore integrity as it provides the required zonal isolation. Ordinary Portland cement (OPC)-based sealant has been used in injection wells and it has been found that it experiences cement degradation and is unstable under CO2-rich down-hole conditions. Therefore, an experimental program was conducted to study the suitability of geopolymer as well cement and the apparent CO2 permeability of geopolymer was tested under the following test conditions using a high pressure triaxial experiment: (a) temperatures of 23–70°C; (b) CO2 injection pressures of 6–17MPa; and (c) confining pressures of 12–20MPa. From the preliminary experimental results, it was noted that the apparent CO2 permeability of geopolymer increases with the curing temperature and increment rates are as high as 200–1000%. However, the maximum permeability (0.04μD) value obtained for any temperature studied is approximately 5000 times lower than the permeability value (200μD) recommended by the American petroleum industry (API) for a typical well sealant. The increase in permeability is related to increased pore diameter and highly heterogeneous pore structure at elevated temperatures for longer curing periods. Even though the permeability of geopolymer increases with the temperature, the values are well below those of traditional OPC cement and API recommended limits. Therefore, geopolymers have potential as primary sealant material in a typical wellbore. An attempt is made to develop an empirical formulation to predict the permeability of geopolymer at different temperatures under various confining pressures.

Investigation of CO2 Sequestration during Cold Heavy Oil Production

CO2 sequestration during cold heavy oil production using captured carbon dioxide was investigated using REVEAL of Petroleum Experts. The results indicated that the CO2 release was influenced by the production phases. The prediction showed high CO2 retention in the first few years post start-up, followed by a gradual decline toward 16.5% post peak production. The recovery rate was strongly influenced by the reservoir characteristics, such as fluid properties, permeability, aquifer, and well completion. Horizontal wells provided better performance than vertical wells. The CO2 utilization and retention per barrel of heavy oil increased as the CO2 injection pressure increased.

Role of Geomechanics in Assessing the Feasibility of CO2 Sequestration in Depleted Hydrocarbon Sandstone Reservoirs

Carbon dioxide (CO2) sequestration in depleted sandstone hydrocarbon reservoirs could be complicated by a number of geomechanical problems associated with well drilling, completions, and CO2 injection. The initial production of hydrocarbons (gas or oil) and the resulting pressure depletion as well as associated reduction in horizontal stresses (e.g., fracture gradient) narrow the operational drilling mud weight window, which could exacerbate wellbore instabilities while infill drilling. Well completions (casing, liners, etc.) may experience solids flowback to the injector wells when injection is interrupted due to CO2 supply or during required system maintenance. CO2 injection alters the pressure and temperature in the near wellbore region, which could cause fault reactivation or thermal fracturing. In addition, the injection pressure may exceed the maximum sustainable storage pressure, and cause fracturing and fault reactivation within the reservoirs or bounding formations. A systematic approach has been developed for geomechanical assessments for CO2 storage in depleted reservoirs. The approach requires a robust field geomechanical model with its components derived from drilling and production data as well as from wireline logs of historical wells. This approach is described in detail in this paper together with a recent study on a depleted gas field in the North Sea considered for CO2 sequestration. The particular case study shows that there is a limitation on maximum allowable well inclinations, 45° if aligning with the maximum horizontal stress direction and 65° if aligning with the minimum horizontal stress direction, beyond which wellbore failure would become critical while drilling. Evaluation of sanding risks indicates no sand control installations would be needed for injector wells. Fracturing and faulting assessments confirm that the fracturing pressure of caprock is significantly higher than the planned CO2 injection and storage pressures for an ideal case, in which the total field horizontal stresses increase with the reservoir re-pressurization in a manner opposite to their reduction with the reservoir depletion. However, as the most pessimistic case of assuming the total horizontal stresses staying the same over the CO2 injection, faulting could be reactivated on a fault with the least favorable geometry once the reservoir pressure reaches approximately 7.7 MPa. In addition, the initial CO2 injection could lead to a high risk that a fault with a cohesion of less than 5.1 MPa could be activated due to the significant effect of reduced temperature on the field stresses around the injection site.

Research Progress of the Interfacial Tension in Supercritical CO2-water/oil System

Carbon dioxide (CO2) is considered as one of major greenhouse gases, which has a significant contribution to global warming and has attracted more and more attention in recent years. So it s necessary to develop more efficient technologies to reduce CO2 emission. Carbon dioxide capture and sequestration (CCS) is one promising option to reduce CO2. CO2 flooding technique can enhance the oil recovery and achieve the storage of CO2 simultaneously. Therefore it is an important technology to support common development in terms of energy and environment. Under the high pressure, the interfacial tension (IFT) can affect fluid flow during the process of CO2 flooding greatly. Accordingly, there is an important significance to research miscible slug process and improve displacement efficiency. Hence the study of the IFT on supercritical CO2-water/oil system is indispensable.In order to understand the characteristic of IFT in-depth, this paper summarizes the IFT of CO2-water/oil system from the aspect of measuring methods, influencing factors and theoretical models. Currently there are less experimental data of IFT under the high pressures because of measuring difficulties in supercritical CO2-water/oil system. As one of the most effective measurement methods, the pendant drop method is developed gradually. This paper introduces the fundamental principles of several methods including selected plane method (SP), drop shape analysis (DSA) and axisymmetric drop shape analysis (ADSA). The relationships between pressure, temperature, concentration of CO2, salinity and IFT are summarized. Generally speaking, the IFT increases with the increasing pressure and salinity, while decreases with the increasing molar fraction of CO2. The effect of temperature on IFT is controversial in different researches. At the same time, this paper also presents the theoretical models of IFT in supercritical CO2-water/oil system. The work shows clearly the basic principles and applicable scopes of the statistical thermodynamics theories including density gradient theory (DGT) and density function theory (DFT). Finally, the directions should be strengthened concerning the study of IFT as follows: In terms of experiment, it is necessary to find out a method to measure the practical density difference by tracing system; Besides, a more accurate equation of state (EOS) should be constructed to calculate IFT. Therefore the proper measurement method, accurate injection pressure and concentration of CO2, rigorous theory and reliable mathematical model can be considered as research directions in future works.

A parametric study of coal mass and cap rock behaviour and carbon dioxide flow during and after carbon dioxide injection

In recent years, scientists have focused on processes which can be used to reduce greenhouse gas emissions, and CO2 sequestration in deep coal seams and saline aquifers has been identified as a potential method. However, there is a fundamental lack of understanding concerning the flow and mechanical phenomena that occur when CO2 is injected into coal seams. The main objective of this parametric study is to model the effect of CO2 injection pressure on cap rock deformation and investigate the possibility of leakage or back-migration of CO2 to the atmosphere through the cap rock. The COMSOL Multiphysics numerical simulator was used to investigate the effect of CO2 injection on coal and other adjacent rock strata. For the purpose of the model, a 200m long and 5m thick coal seam was assumed to be lying below a 200m long and 3m thick cap rock layer 1000m below the surface. According to the model’s results, the cap rock deforms considerably just after injection in an upward direction due to the CO2 movement, and the amount of deformation greatly depends on the injecting gas pressure. When the injecting gas pressure is increased from 10.2MPa to 30MPa, the cap rock is raised from 0.2mm to 15mm during the injecting period. Moreover, CO2 first spreads and is stored in the coal mass and then after about 3–4years it starts to move towards the cap rock layer. In the second stage of the study, a small rock fracture was inserted between the cap rock and the coal layer and a sudden increase in leakage of CO2 to the cap rock through the fracture was observed. The existence of a rock fracture is highly possible, and may happen naturally in coal seams. This model shows that this kind of fracture greatly increases the risk of back-migration of CO2 into the atmosphere. The model can be used to study general coal mass and cap rock behaviour and the back-movement of CO2 flow to the atmosphere.

A study of safe CO2storage capacity in saline aquifers: a numerical study

An effective way of reducing greenhouse gas content in the atmosphere is carbon dioxide (CO2) geo-sequestration in saline aquifers. The main objective of this study is to develop a 3-D numerical model to identify the optimum CO2 storage capacity in saline aquifers by studying the factors affecting it and the possibility of the injected CO2 back-migrating into the atmosphere. A 1000m×1000m×184 m saline aquifer, lying 800 m below the ground surface, was therefore considered to develop a model using the COMET 3 reservoir simulator. The effects of injecting CO2 properties (injection pressure) and the aquifer's properties (depth, temperatures and salinity) on the CO2 storage capacity were examined first. According to the results of the model, CO2 storage capacity increases with increasing injection pressure and salinity and decreasing depth and temperature, and 100% variations in injection pressure, depth, temperature and salinity levels cause the CO2 storage capacity to be changed by 54%, 36%, 18% and 1.8%, respectively. The next stage of the study involved the determination of cap rock failure due to CO2 injection pressure and the identification of the factors influencing it. A detailed parametric study was conducted, with changes to the depth, temperature and salinity with respect to injection pressure, to detect the effects of these factors on the optimum CO2 injection pressure. According to the results, optimum CO2 injection pressure clearly depends on the aquifer depth and the effects of salinity and temperature are negligible. An increment of 0.8 to 1.4 km in aquifer depth causes the optimum injection pressure to be increased from 19.55 to 42 MPa, which is about 105 and 107 higher than the effects of temperature (20 to 110 °C increment) and salinity level (100,000 to 160,000 ppm increment), respectively. The model can be used effectively in field studies to safely enhance CO2 storage capacity in saline aquifers. Copyright © 2012 John Wiley & Sons, Ltd.

The critical role of monitoring, verification, and accounting for geologic carbon dioxide storage projects

A growing concern that increasing levels of greenhouse gases in the atmosphere are contributing to global climate change has led to a search for economical and environmentally sound ways to reduce carbon dioxide (CO2) emissions. One promising approach is CO2 capture and permanent storage in deep geologic formations, such as depleted oil and gas reservoirs, unminable coal seams, and deep brine-containing (saline) formations. However, successful implementation of geologic storage projects will require robust monitoring, verification, and accounting (MVA) tools. This article deals with all aspects of MVA activities associated with such geologic CO2 storage projects, including site characterization, CO2 plume tracking, CO2 flow rate and injection pressure monitoring, leak detection, cap-rock integrity analysis, and long-term postinjection monitoring. Improved detailed decision tree diagrams are presented covering the five stages of a geologic storage project. These diagrams provide guidance from the point of site selection through construction and operations to closure and postclosure monitoring. Monitoring, verification, and accounting techniques (both well-established and promising new developments) appropriate for various project stages are discussed. Accomplishments of the Department of Energy (DOE) Regional Carbon Sequestration Partnerships field projects serve as examples of the development and application to geologic storage of MVA tools, such as two-dimensional and three-dimensional seismic and microseismic, as well as the testing of new cost-effective monitoring technologies. Although it is important that MVA and computer simulation efforts be carefully integrated to ensure long-term success of geologic storage projects, this article is limited to a discussion of MVA activities. This article is an extension of a report published in 2009 by the DOE National Energy Technology Laboratory titled, “Best Practices for Monitoring, Verification, and Accounting of CO2 Stored in Deep Geologic Formations,” to which interested readers are referred for more details on MVA tools. Ultimately, a robust MVA program will be critical for establishing carbon capture and storage as a viable greenhouse gas mitigation strategy.