CO2 Injection Tests Research Articles

Flow visualization of CO2 in tight shale formations at reservoir conditions

AbstractThe flow of CO2 in porous media is fundamental to many engineering applications and geophysical processes. Yet detailed CO2 flow visualization remains challenging. We address this problem via positron emission tomography using 11C nuclides and apply it to tight formations—a difficult but relevant rock type to investigate. The results represent an important technical advancement for visualization and quantification of flow properties in ultratight rocks and allowed us to observe that local rock structure in a layered, reservoir shale (K = 0.74 µdarcy) sample dictated the CO2 flow path by the presence of high‐density layers. Diffusive transport of CO2 in a fractured sample (high‐permeable sandstone) was also visualized, and an effective diffusion coefficient (Di = 2.2 · 10−8 m2/s) was derived directly from the dynamic distribution of CO2. During CO2 injection tests for oil recovery from a reservoir shale sample we observed a recovery factor of RF = 55% of oil in place without fracturing the sample.

SECARB CO2 injection test in mature coalbed methane reservoirs of the Black Warrior Basin, Blue Creek Field, Alabama

The SECARB Black Warrior field verification test employed a diverse suite of well testing and monitoring procedures designed to determine the injectivity, capacity, heterogeneity, and performance of mature coalbed methane reservoirs. A total of 3250bbl of water and 252t of CO2 were injected into coal in a battery of slug tests. These tests demonstrate that significant injectivity exists in Black Warrior coalbed methane reservoirs and that reservoir heterogeneity is a critical factor to consider when implementing CO2 sequestration and CO2-enhanced recovery programs.The primary test well produces coalbed methane at wellhead pressures just above atmospheric, and yet desorption testing indicates that less than 20% of the original gas in place has been recovered by primary production. Injection of CO2 was conducted at sustained rates of about 90t/d of CO2. Reservoir pressure declined exponentially following the emplacement of each CO2 slug. Slug and pressure-buildup tests verify that permeability decreases exponentially with depth and also decreased during injection.Monitoring operations included multi-zone pressure logging and gas sampling in deep observation wells and groundwater sampling in a shallow observation well. Results indicate that significant permeability anisotropy exists in each coal group. In the Black Creek coal, pressure response was greatest in the dominant natural fracture direction. In the Pratt coal group, pressure response was dominated by hydrofractures. CO2 broke through to the observation wells only in the Pratt coal group and only along the major fracture directions. No significant flow of CO2 out of zone was detected, and no impact on shallow groundwater resources was identified.

Determination of Minimum Miscibility Pressure of Crude Oil–CO2 System by Oil Swelling/Extraction Test

AbstractThe minimum miscibility pressure (MMP) of crude oil–CO2 systems was determined through analyzing the experimental data of swelling/extraction tests. First, the oil swelling factor (SF) as a result of CO2 dissolution in a crude oil sample was determined at four different temperatures in the range of T=21–40 °C. In addition, three sets of swelling/extraction data of previous studies were collected and included so that more conclusive and satisfactory results can be obtained. The results demonstrated that the oil swelling factor increases with the equilibrium pressure (Peq), reaches the maximum value at light hydrocarbon extraction pressure (Pext), and then reduces with further increase in equilibrium pressure. It was found that the reduction behavior of oil swelling factor occurs in two distinct regions. In the upper extraction phase (UEP), the oil swelling factor decreased sharply at pressures just over extraction pressure and then declined gradually in what is called the lower extraction phase (LEP). Finally, the MMP of the crude oil–CO2 system at a specific temperature was estimated by finding the intersection of the linear regression correlation corresponding to each of the aforementioned regions (i.e., UEP and LEP). The crude oil–CO2 MMP was also determined by employing the vanishing interfacial tension (VIT) technique and a series of CO2 injection tests. Comparing the MMP values of the crude oil–CO2 systems determined by three methods revealed that the MMP values estimated by swelling/extraction data are in approximate agreement with those determined by the two other methods.

On the CO2 storage potential of cyclic CO2 injection process for enhanced oil recovery

In this study, the potential of cyclic CO2 injection process was examined for CO2 storage and enhanced oil recovery. For this purpose, a detailed phase behavior study on the light crude oil–CO2 and brine–CO2 systems was conducted. CO2 solubility in the oil and brine samples as well as oil swelling factor as a result of CO2 dissolution were experimentally measured. The equilibrium interfacial tension of the crude oil–CO2 system was also determined by applying the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case. Furthermore, the minimum miscibility pressure (MMP) of CO2 with crude oil was calculated by means of vanishing interfacial tension (VIT) technique and found to be MMP=9.18MPa. Thereafter, series of cyclic CO2 injection tests were designed and carried out at constant temperature of T=30°C and various operating pressures in the range of Pop=5.38–10.34MPa to cover immiscible and miscible conditions. The results showed that 40–50% of the injected CO2 was stored in the porous medium mainly through residual and solubility trappings’ mechanisms. It was found that during immiscible injection condition (i.e., Pop<MMP), higher amount of CO2 can be stored in the porous medium at higher operating pressures. The results also revealed that optimum potential of CO2 storage is almost at operating pressures near the MMP, while beyond that pressure, the CO2 storage capacity was not substantially increased. From the enhanced oil recovery point of view, the oil recovery factor was significantly improved when operating pressure increased and reached its maximum value at miscible condition (i.e., Pop⩾MMP). During the immiscible injection scenario, mechanisms involved in oil production were mainly oil swelling and reduction of interfacial tension. However, the light component extraction was the major production mechanism contributing to the oil recovery during miscible injection process.

Model complexity in carbon sequestration: A design of experiment and response surface uncertainty analysis

Geologic carbon sequestration (GCS) is considered a promising means of reducing atmospheric carbon dioxide (CO2). In Wyoming, GCS is proposed for the Nugget Sandstone in Moxa Arch, a deep, regional-scale saline aquifer with a large CO2 storage potential. For a proposed storage site, this study builds a suite of increasingly complex conceptual geologic model families, using subsets of the site characterization data: a homogeneous model family (FAM1), a stationary petrophysical model family (FAM2), a stationary facies model family with sub-facies petrophysical variability (FAM3), and a non-stationary facies model family (with sub-facies variability) conditioned to soft data (FAM4). These families, representing alternative conceptual site models built with increasing data, were simulated with the same CO2 injection test (50 years at 1/10Mt (1.0×108kg) per year), followed by 2950 years of monitoring. Using the design of experiment, an efficient sensitivity analysis (SA) is conducted for all families, systematically varying uncertain aquifer parameters, while assuming identical well configuration, injection rate, bottomhole pressure constraint, and boundary conditions, i.e., the model is considered a part of a larger, semi-infinite system, where both the injected CO2 and the formation brine can flow out. The SA results are compared among the families to identify parameters that have 1st order impact on predicting CO2 storage ratio (SR) at two different time scales, i.e., end of injection and end of monitoring. This comparison indicates that, for this deep aquifer with a gentle incline, geologic modeling factors do not significantly influence the short-term prediction of the CO2 storage ratio. However, these factors become more important over the monitoring time, but only for those families where such factors are accounted for (in other words, their long-term importance cannot be revealed by the relatively simple conceptual models). Based on the SA results, a response surface analysis is conducted to generate prediction envelopes of the storage ratio, which are also compared among the families, and at both time scales. Results suggest a large uncertainty in the predicted storage ratio, given the uncertainties in model parameters and modeling choices: the SR varies from 5–60% (end of injection) to 18–100% (end of monitoring), although its variation among the model families due to different modeling choices is relatively minor. Moreover, long-term leakage risk is considered small at the proposed site. This is because, in the lowest-SR scenarios, all model families predict gravity-stable supercritical CO2 migrating toward the bottom of the aquifer. In the highest-SR scenarios, supercritical CO2 footprints are relatively insignificant by the end of monitoring.

What Have We Learned from Small-scale Injection Projects?

Abstract A review has been undertaken of small scale injection projects of less than 100,000 tonnes (t) of CO2 from around the world, with the objective of assisting countries or organisations wishing to embark on their first CO2 injection test, in a cost effective, time efficient and safe manner. The mean amount of CO2 injected per project was approximately 1,000 t; only 9 out of the 45 projects had injected more than 10,000 t. Costs varied greatly from less than $1 million to $100 million, with the mean total cost in the range of $10-20 million. Half of the projects were based on injection into sandstone reservoirs, although a significant number (28%) involved injection into coals. The source of the CO2 was quite variable; the majority of the CO2 was transported by truck to the site. The depth of injection ranged from approximately 300m to over 4,000m but averaged around 1,200m. The time taken from making the preliminary decision to undertake a project to injection of the first molecule of CO2 was variable but averaged approximately three years. Generally, small scale projects are opportunistic, typically initiated by research organisations; they rely on an alliance with industrial partners for operational expertise and access to suitable locations. In most small scale projects, pre-drill reservoir characterisation consists of the integration of pre-existing geological and hydrological data. Saline reservoir sites are usually data deficient. Reservoir simulations are performed routinely, using a variety of codes, to assess CO2 injection tests and provide valuable information for system design, permitting, and monitoring. The simulations are also useful for providing a systematic framework for integrating site characterisation data, visualisation of model results provide a valuable communication tool. Documentation of storage risk assessment by projects was limited. Monitoring programs for the test injection projects were opportunistic to some degree, utilising existing data to help in establishing a baseline and commonly utilising existing wells for down-hole observations and monitoring-based sampling. Nearly all projects undertook pressure and temperature monitoring as a standard. These small scale projects offer a cost effective way of demonstrating storage technologies in CCS, assisting the progression towards large scale injections.

Injectivity of carbon dioxide in the St. Lawrence Platform, Quebec (Canada): A sensitivity study

AbstractInjectivity of CO2 in the Bécancour deep saline aquifers, St. Lawrence Platform (Québec), was investigated using 2D radial numerical simulations with TOUGH2/ECO2N. In order to have an appropriate choice for the CO2 injection rate and the duration of injection, sensitivity analyses were carried out, considering different values of hydrodynamic, chemical‐petrophysical, and geometric parameters affecting CO2 injection in a brine reservoir. The parameterization analysis for capillary pressure and relative permeability models indicated large uncertainty for this case study. Simulations took into account Bécancour reservoir conditions in which the maximum pressure was limited to the fracturing pressure. The sensitivity analysis provides guidance on potential injection scenarios. To remain below fracturing pressure, intermittent 5‐year injection periods can be used, with a mass injection rate up to ∼ 20 kg/s, alternating with half‐year periods without injection. This scenario could give maximum CO2 storage in the aquifer. CO2 storage capacities in different phases were calculated versus time. This study shows that the northeastern reservoir block of the Bécancour area could host about 10 Mt CO2, which represents 15% to 50% of regional yearly CO2 emissions during about 60 and 20 years for the case of the injection formation permeability of 0.89 × 10−15 m2 and 4.17 × 10−15 m2, respectively. Finally, this modeling study will also be the basis for the design of a pilot CO2 injection test at the study site. © 2013 Society of Chemical Industry and John Wiley &amp; Sons, Ltd

Parametric Study of the Cyclic CO2 Injection Process in Light Oil Systems

Performance of cyclic CO2 injection as an enhanced oil recovery (EOR) technique in a light crude oil system was experimentally investigated. Series of cyclic CO2 injection tests were designed and c...

Modeling CO2–brine–rock interactions in the Knox Group: Implications of a deep carbon storage field test in western Kentucky

The Cambrian–Ordovician Knox Group, a thick sequence of dolostone and minor dolomitic sandstone, is a prospective CO2 sequestration target in the southern Illinois Basin, USA. Thorough evaluation of the Knox Group is critical because the main sequestration target elsewhere in the Illinois Basin, the Cambrian Mount Simon Sandstone, is thin or absent throughout most of Kentucky. A 2477-m-deep carbon storage test well in Hancock County, Kentucky, was drilled, and 626metric tons of CO2 was injected into the Knox saline reservoirs. To understand the long-term fate of CO2 injected into the Knox reservoirs, geochemical reactions between CO2, brine and rock-forming minerals were modeled using TOUGHREACT. The modeling benefited from a robust data set collected from the test well, including core porosity and permeability, petrographic and X-ray powder diffraction mineralogy, brine chemistry, temperature and pressure measurements. Kinetic batch models and 2-D radial reactive transport models were used to evaluate the migration of the injected CO2, changes in brine chemistry, and mineral dissolution and precipitation. Results from the kinetic models suggest that sections of the Knox dominated by dolomite have very limited mineral-trapping capacity for CO2, whereas thin sections of dolomitic sandstone with aluminosilicate minerals such as K-feldspar facilitate mineral trapping. The 2-D model for the CO2 injection test suggests that, because of the presence of thick permeable intervals in the Knox and the small volume of injected CO2 in the test, the radius of influence is less than 11m from the well. The hypothetical long-term injection model indicates, on the other hand, that commercial-scale injection would influence a much larger area and part of the injected CO2 remains in the supercritical/gas phase for a long time. Because of the buoyancy effect, most supercritical/gas-phase CO2 migrates upward and stays in the top of the reservoirs dominated by dolomite with small mineral-trapping capacity.

Erratum to: Investigation of the geochemical impact of CO2 on shallow groundwater: design and implementation of a CO2 injection test in Northeast Germany

Erratum to: Investigation of the geochemical impact of CO2 on shallow groundwater: design and implementation of a CO2 injection test in Northeast Germany

Laboratory seismic monitoring of supercritical CO2 flooding in sandstone cores using the Split Hopkinson Resonant Bar technique with concurrent x‐ray Computed Tomography imaging

ABSTRACTAccurate estimation of CO2 saturation in a saline aquifer is essential for the monitoring of supercritical CO2 injected for geological sequestration. Because of strong contrasts in density and elastic properties between brine and CO2 at reservoir conditions, seismic methods are among the most commonly employed techniques for this purpose. However the relationship between seismic (P‐wave) velocity and CO2 saturation is not unique because the velocity depends on both wave frequency and the CO2 distribution in rock. In the laboratory, we conducted measurements of seismic properties of sandstones during supercritical CO2 injection. Seismic responses of small sandstone cores were measured at frequencies near 1 kHz, using a modified resonant bar technique (Split Hopkinson Resonant Bar method). Concurrently, saturation and distribution of supercritical CO2 in the rock cores were determined via x‐ray CT scans. Changes in the determined velocities generally agreed with the Gassmann model. However, both the velocity and attenuation of the extension wave (Young's modulus or ‘bar’ wave) for the same CO2 saturation exhibited differences between the CO2 injection test and the subsequent brine re‐injection test, which was consistent with the differences in the CO2 distribution within the cores. Also, a comparison to ultrasonic velocity measurements on a bedded reservoir rock sample revealed that both compressional and shear velocities (and moduli) were strongly dispersive when the rock was saturated with brine. Further, large decreases in the velocities of saturated samples indicated strong sensitivity of the rock's frame stiffness to pore fluid.

An Experimental and Modeling Study of Asphaltene Deposition Due to CO2 Miscible Injection

The authors studied deposition and entrainment of asphaltene particles as major mechanisms that occur in porous media. Deposition mechanisms that contribute to permeability reduction and entrainment of deposited particle improve the damaged permeability value. While in most previous works the effects of entrainment mechanism are considered negligible, in this study miscible CO2 injection tests were conducted by core flood apparatus to investigate the effect of asphaltene deposition on permeability and porosity alterations. Results indicated that proposed model for entrainment mechanism is affected by deposition mechanism. The asphaltene deposition core's characteristics have undeniable roles in core impairment.

Anionic Surfactant Adsorption through Porous Media in Carbonate Cores: An Experimental Study

The phenomenon of surfactant adsorption at solid/liquid interface is of major importance in the process of enhanced oil recovery. The basic objective of this study is to calculate adsorption density and also to model the kinetics of adsorption processes on carbonate rocks. The kinetics adsorption was calculated by examining adsorption behavior in a system of a solid phase (carbonate rock) and an aqueous phase of surfactant with 5,000 ppm synthetic/field brine. The surfactant adsorption on reservoir carbonate rocks was measured to determine the amount of excess surfactant that must be added into the injection stream in the surfactant alternating CO2 injection tests. The adsorption densities were measured by using circulation tests through core samples. The range of initial surfactant concentrations were 500, 1,000, 2,000, and 5,000 ppm in a circulating system. The applied commercial surfactant is sodium lauryl sulphate, which is an anionic surfactant. Finally, the Langmuir adsorption isotherm was used to characterize the equilibria between the amount of adsorbate that accumulates on the adsorbent and the concentration of the dissolved adsorbate. The adsorption process showed that the rate of adsorption is dependent on availability of surfactant in the system. It was found that the adsorption of surfactant increased with increasing surfactant concentration. Also, for the flow-through tests, the necessary equilibrium time was approximately 4 days.

Developing CCS into a Realistic Option in a Country's Energy Strategy

The CARMA project investigated the potential of Carbon dioxide capture and storage (CCS) in Switzerland and the country-specific difficulties on the way to implementation. CCS may play a major role in the future Swiss energy scenario as a bridging technology between the phase out of nuclear energy and the establishment of an entirely renewable energy system. The key findings of the CARMA project with respect to CCS implementation are summarized. A pilot CO2-injection test on a small scale is proposed to prove the suitability of the considered geological formations for durable and safe CO2 storage, and to gain information about the deep Swiss subsurface. Furthermore, such a field test would support the development of the legal framework needed for CCS and initiate knowledge transfer to the Swiss public. The successful test site in Ketzin, Germany adapted to the Swiss context can serve as a role model.

Investigation of the geochemical impact of CO2 on shallow groundwater: design and implementation of a CO2 injection test in Northeast Germany

A small scale and temporally limited CO2 injection test was performed in a shallow aquifer to investigate the geochemical impact of CO2 upon such aquifers and to apply and verify different monitoring methods. Detailed site investigation coupled with multiphase simulations were necessary to design the injection experiment and to set up the monitoring network, before CO2 was injected over a ten-day period at three injection wells, at a depth of 18 m below surface level into a quaternary sand aquifer located close to the town of Wittstock in Northeast Germany. Monitoring methods comprised groundwater sampling and standard analyses, as well as trace element analyses and isotope analyses; geoelectrical borehole monitoring; passive samplers to analyse temporally integrated for cations and multi-parameter probes that can measure continuously for dissolved CO2, pH and electrical conductivity. Due to CO2 injection, total inorganic carbon concentrations increased and pH decreased down to a level of 5.1. Associated reactions comprised the release of major cations and trace elements. Geoelectrical monitoring, as well as isotope analyses and multi-parameter probes proved to be suitable methods for monitoring injected CO2 and/or the alteration of groundwater.

Development of a multi-mechanistic, dual-porosity, dual-permeability, numerical flow model for coalbed methane reservoirs

Most existing coalbed methane (CBM) simulators usually treat coal seams as dual-porosity, single-permeability systems ignoring the effects of water presence in the coal matrix. In this study, a compositional dual-porosity, dual-permeability CBM simulator has been developed. The CBM reservoir is treated as a dual-porosity, dual-permeability system consisting of coal matrix and fracture network. The development of the proposed numerical model incorporates the effects of water presence in the coal matrix and the phenomena of coal shrinkage and swelling. The transport of gas follows a multi-mechanistic flow mechanism triggered by pressure and concentration gradients. In addition, the proposed simulator is able to collapse to simpler coal seam representations and was successfully tested against the existing commercial and research CBM simulators for CO2-enhanced CBM recovery process. Successful history matching exercises were performed on pure CO2 injection and flue gas injection tests using the actual field data.

Small-Scale CO2 Injection into a Deep Geological Formation at Heletz, Israel

This paper presents the experimental plans and designs as well as examples of predictive modeling of a pilot-scale CO2 injection experiment at the Heletz site (Israel). The overall objective of the experiment is to find optimal ways to characterize CO2 -relevant in-situ medium properties, including field-scale residual and dissolution trapping, to explore ways of characterizing heterogeneity through joint analysis of different types of data, and to detect leakage. The experiment will involve two wells, an injection well and a monitoring well. Prior to the actual CO2 injection, hydraulic, thermal and tracer tests will be carried out for standard site characterization. The actual CO2 injection experiments will include (i) a single well injection-withdrawal experiment, with the main objective to estimate in-situ residual trapping and (ii) a two-well injection-withdrawal test with injection of CO2 in a dipole mode (injection of CO2 in one well with simultaneous withdrawal of water in the monitoring well), with the objective to understand the CO2 transport in heterogeneous geology as well as the associated dissolution and residual trapping. Tracers will be introduced in both experiments to further aid in detecting the development of the phase composition during CO2 transport. Geophysical monitoring will also be implemented. By means of modeling, different experimental sequences and injection/withdrawal patterns have been analyzed, as have parameter uncertainties. The objectives have been to (i) evaluate key aspects of the experimental design, (ii) to identify key parameters affecting the fate of the CO2 and (iii) to evaluate the relationships between measurable quantities and parameters of interest.

Influence of CO2on the long-term chemomechanical behavior of an oolitic limestone

[1] In order to study the long-term mechanical and petrographical evolutions of a carbonate rock (oolitic limestone) during storage of CO2, CO2 injection tests were performed in triaxial cells at temperature and mechanical stresses (isotropic and deviatoric) corresponding to the depth of the Dogger carbonate reservoirs of the Paris basin (∼800 m). We used a specific “flow-through” triaxial cell which allowed us to measure very low strain rates in both axial and lateral directions, while ensuring the sealing of the samples during the injection of CO2. Under isotropic loading, neither the dynamic percolation (i.e., flow-through tests) of dry supercritical/gaseous CO2, nor the diffusion of CO2, into initially saturated samples was shown to produce significant axial compaction and calcite dissolution. Indeed, even though the interstitial aqueous fluid becomes acidic, the progressive increase in dissolved species induces the H2O-CO2-calcite re-equilibrium. The dynamic injection of CO2-saturated solution induced significant axial compaction due to the dissolution of calcite at the sample/piston interface only under open flow conditions (i.e., the injected acidic solution is continuously renewed). Under closed flow conditions (i.e., acidic solution recirculation or no-flow conditions) which reproduce the physicochemical conditions of CO2 storage at the field scale better, the rapid H2O-CO2-calcite re-equilibrium inhibits calcite dissolution. Under deviatoric loading and closed conditions, the diffusion of CO2 induced a very small increase in the PSC (pressure solution creep) process which was stopped by the H2O-CO2-calcite re-equilibrium inside the sample. Therefore, a significant compaction of limestone samples was obtained only under open conditions and is mainly due to a purely chemical mechanism (calcite dissolution), while the contribution of the chemo-mechanical mechanism (PSC) was found to not be of any great importance. In the context of massive injection of CO2 at the field scale, if the reservoir can be considered as a closed system from a hydrodynamic point of view (i.e., the brine circulates in the aquifer but is not renewed by any groundwater), CO2 will not play a significant role in the chemistry of carbonate reservoirs due to the H2O-CO2-calcite re-equilibrium and will not induce reservoir compaction and affect its long-term storage capacity, whatever the stress state (isotropic or deviatoric).

The CarbFix Pilot Project–Storing carbon dioxide in basalt

In situ mineral carbonation is facilitated by aqueous-phase chemical reactions with dissolved CO2. Evidence from the laboratory and the field shows that the limiting factors for in situ mineral carbonation are the dissolution rate of CO2 into the aqueous phase and the release rate of divalent cations from basic silicate minerals. Up to now, pilot CO2 storage projects and commercial operations have focused on the injection and storage of anthropogenic CO2 as a supercritical phase in depleted oil and gas reservoirs or deep saline aquifers with limited potential for CO2 mineralization. The CarbFix Pilot Project will test the feasibility of in situ mineral carbonation in basaltic rocks as a way to permanently and safely store CO2. The test includes the capture of CO2 flue gas from the Hellisheidi geothermal power plant and the injection of 2200 tons of CO2 per year, fully dissolved in water, at the CarbFix pilot injection site in SW Iceland. This paper describes the design of the CO2 injection test and the novel approach for monitoring and verification of CO2 mineralization in the subsurface by tagging the injected CO2 with radiocarbon (14C), and using SF5CF3 and amidorhodamine G as conservative tracers to monitor the transport of the injected CO2 charged water.

CO2-ECBM field tests in the Ishikari Coal Basin of Japan

Abstract The feasibility of extracting gas from coal seam while storing carbon dioxide underground was evaluated in Japan. A CO2-ECBM project had begun near the town of Yubari on the island of Hokkaido in northern Japan. The primary coal seam of interest was a 5–6 m thick Yubari coal seam located at the depth of 900 m. A micro-pilot test with a single well and multi-well CO2 injection tests, involving an injection and production wells, were carried out in the period between May 2004 and October 2007. There were a variety of tests conducted in the injection well, including an initial water injection fall-off test and a series of CO2 injection and fall-off tests. Although gas production rate was obviously enhanced by CO2 injection, water production rate was not clearly affected by CO2 injection. Several injection tests suggested that injectivity of CO2 into the virgin coal seam saturated with water was eventually increased as the water saturation near the injector was decreased by the injected CO2. It was estimated that low injectivity of CO2 was caused by the reduction in permeability induced by coal swelling. N2 flooding test was performed in 2006 to evaluate the effectiveness of N2 injection on improving well injectivity. The N2 flooding test showed that daily CO2 injection rate was boosted, but only temporarily. Moreover, the permeability did not return to the initial value after CO2 and N2 were repeatedly injected. It was also indicated that the coal matrix swelling might create a high stress zone near to the injection well.