Experimental investigation into the sealing capability of naturally fractured shale caprocks to supercritical carbon dioxide flow

Geological storage of CO₂ is considered a solution for reducing the excess CO₂ released into the atmosphere. Low permeability caprocks physically trap CO₂ injected into underlying porous reservoirs. Injection leads to increasing pore pressure and reduced effective stress, increasing the likelihood of exceeding the capillary entry pressure of the caprocks and of caprock fracturing. Assessing on how the different phases of CO₂ flow through caprock matrix and fractures is important for assessing CO₂ storage security. Fractures are considered to represent preferential flow paths in the caprock for the escape of CO₂. Here we present a new experimental rig which allows 38 mm diameter fractured caprock samples recovered from depths of up to 4 km to be exposed to supercritical CO₂ (scCO₂) under in situ conditions of pressure, temperature and geochemistry. In contrast to expectations, the results indicate that scCO₂ will not flow through tight natural caprock fractures, even with a differential pressure across the fractured sample in excess of 51 MPa. However, below the critical point where CO₂ enters its gas phase, the CO₂ flows readily through the caprock fractures. This indicates the possibility of a critical threshold of fracture aperture size which controls CO₂ flow along the fracture.     

Numerical simulation of carbon dioxide migration in a sandstone aquifer considering the fluid–solid coupling

Very limited investigations have been done on the numerical simulation of carbon dioxide (CO₂) migration in sandstone aquifers taking consideration of the interactions between fluid flow and rock stress. Based on the poroelasticity theory and multiphase flow theory, this study establishes a mathematical model to describe CO₂ migration, coupling the flow and stress fields. Both finite difference method (FDM) and finite element method (FEM) were used to discretize the mathematical model and generate a numerical model. A case study was carried out using the numerical model on the Jiangling sandstone aquifer in the Jianghan basin, China. The rock mechanics parameters of reservoir and overlying strata of Jiangling depression were obtained by triaxial tests. A two-dimensional model was then built to simulate carbon dioxide migration in the sandstone aquifer. The numerical simulation analyzes the carbon dioxide migration distribution rule with and without considering capillary pressure. Time-dependent migration of CO₂ in the sandstone aquifer was analyzed, and the result from the coupled model was compared with that from a traditional non-coupled model. The calculation result indicates a good consistency between the coupled model and the non-coupled model. At the injection point, the CO₂ saturation given by the coupled model is 15.39 % higher than that given by the non-coupled model; while the pore pressure given by the coupled model is 4.8 % lower than that given by the non-coupled model. Therefore, it is necessary to consider the coupling of flow and stress fields while simulating CO₂ migration for CO₂ disposal in sandstone aquifers. The result from the coupled model was also sensitized to several parameters including reservoir permeability, porosity, and CO₂ injection rate. Sensitivity analyses show that CO₂ saturation is increased non-linearly with CO₂ injection rate and decreased non-linearly with reservoir porosity. Pore pressure is decreased non-linearly with reservoir porosity and permeability, and increased non-linearly with CO₂ injection rate. When the capillary pressure was considered, the computed gas saturation of carbon dioxide was increased by 10.75 % and the pore pressure was reduced by 0.615 %.     

A sensitivity analysis of factors affecting in geologic CO2 storage in the Ordos Basin and its contribution to carbon neutrality

To accelerate the achievement of China’s carbon neutrality goal and to study the factors affecting the geologic CO₂ storage in the Ordos Basin, China’s National Key R&D Programs propose to select the Chang 6 oil reservoir of the Yanchang Formation in the Ordos Basin as the target reservoir to conduct the geologic carbon capture and storage (CCS) of 100000 t per year. By applying the basic theories of disciplines such as seepage mechanics, multiphase fluid mechanics, and computational fluid mechanics and quantifying the amounts of CO₂ captured in gas and dissolved forms, this study investigated the effects of seven factors that influence the CO₂ storage capacity of reservoirs, namely reservoir porosity, horizontal permeability, temperature, formation stress, the ratio of vertical to horizontal permeability, capillary pressure, and residual gas saturation. The results show that the sensitivity of the factors affecting the gas capture capacity of CO₂ decreases in the order of formation stress, temperature, residual gas saturation, horizontal permeability, and porosity. Meanwhile, the sensitivity of the factors affecting the dissolution capture capacity of CO₂ decreases in the order of formation stress, residual gas saturation, temperature, horizontal permeability, and porosity. The sensitivity of the influencing factors can serve as the basis for carrying out a reasonable assessment of sites for future CO₂ storage areas and for optimizing the design of existing CO₂ storage areas. The sensitivity analysis of the influencing factors will provide basic data and technical support for implementing geologic CO₂ storage and will assist in improving geologic CO₂ storage technologies to achieve China’s carbon neutralization goal.©2022 China Geology Editorial Office.     

Well-based hydraulic and geochemical monitoring of the above zone of the CO2 reservoir at Ketzin, Germany

In order to detect hydraulic and geochemical impact on the groundwater directly above the CO₂ storage reservoir at the Ketzin pilot site continuous monitoring using an observation well is carried out. The target depth (446 m below ground level, bgl.) of the well is the Exter formation (Upper Triassic, Rhaetian) which is the closest permeable stratigraphic overlying formation to the CO₂ storage reservoir (630–636 m bgl. at well location). The monitoring concept comprises evaluation of hydraulic conditions, temperature, water chemistry, gas geochemistry and δ¹³C values. This is achieved by a tubing inserted inside the well with installed pressure sensors and a U-tube sampling system so that pumping tests or additional wireline logging can be carried out simultaneously with monitoring. The aquifer was examined using a pump test. The observation well is hydraulically connected to the regional aquifer system and the permeability of about 1.8 D is comparatively high. Between Sept. 2011 and Oct. 2012, a pressure increase of 7.4 kPa is observed during monitoring under environmental conditions. Drilling was carried out with drilling mud on carbonate basis. The concentration of residual drilling mud decreases during the pump test, but all samples show a residual concentration of drilling mud. The formation fluid composition is recalculated with PHREEQC and is comparable to the literature values for the Exter formation. The gas partial pressure is below saturation at standard conditions and the composition is dominated by N₂ similar to the underlying storage reservoir prior to CO₂ injection. The impact of residual drilling mud on dissolved inorganic carbon and the respective δ¹³C values decreases during the monitoring period. The pristine isotopic composition cannot be determined due to calcite precipitation. No conclusive results indicate a leakage from the underlying CO₂ storage reservoir.     

Effect of injected CO2 on geochemical alteration of the Altmark gas reservoir in Germany

Capturing CO₂ from point sources and storing it in geologic formations is a potential option for allaying the CO₂ level in the atmosphere. In order to evaluate the effect of geological storage of CO₂ on rock-water interaction, batch experiments were performed on sandstone samples taken from the Altmark reservoir, Germany, under in situ conditions of 125 °C and 50 bar CO₂ partial pressure. Two sets of experiments were performed on pulverized sample material placed inside a closed batch reactor in (a) CO₂ saturated and (b) CO₂ free environment for 5, 9 and 14 days. A 3M NaCl brine was used in both cases to mimic the reservoir formation water. For the “CO₂ free” environment, Ar was used as a pressure medium. The sandstone was mainly composed of quartz, feldspars, anhydrite, calcite, illite and chlorite minerals. Chemical analyses of the liquid phase suggested dissolution of both calcite and anhydrite in both cases. However, dissolution of calcite was more pronounced in the presence of CO₂. In addition, the presence of CO₂ enhanced dissolution of feldspar minerals. Solid phase analysis by X-ray diffraction and Mössbauer spectroscopy did not show any secondary mineral precipitation. Moreover, Mössbauer analysis did not show any evidence of significant changes in redox conditions. Calculations of total dissolved solids’ concentrations indicated that the extent of mineral dissolution was enhanced by a factor of approximately 1.5 during the injection of CO₂, which might improve the injectivity and storage capacity of the targeted reservoir. The experimental data provide a basis for numerical simulations to evaluate the effect of injected CO₂ on long-term geochemical alteration at reservoir scale.     

Numerical simulation to quantify the leakage risk in a multi-layer aquifer system of pure brine recovery and CO<Subscript>2</Subscript>-enhanced brine recovery: a case study of potassium-rich brine recovery in Jianghan Basin of China

Deep brine recovery enhanced by supercritical CO₂ injection is proposed to be a win–win method for the enhancement of brine production and CO₂ storage capacity and security. However, the cross-flow through interlayers under different permeability conditions is not well investigated for a multi-layer aquifer system. In this work, a multi-layer aquifer system with different permeability conditions was built up to quantify the brine production yield and the leakage risk under both schemes of pure brine recovery and enhanced by supercritical CO₂. Numerical simulation results show that the permeability conditions of the interlayers have a significant effect on the brine production and the leakage risk as well as the regional pressure. Brine recovery enhanced by supercritical CO₂ injection can improve the brine production yield by a factor of 2–3.5 compared to the pure brine recovery. For the pure brine recovery, strong cross-flow through interlayers occurs due to the drastic and extensive pressure drop, even for the relative low permeability (k = 10^?20 m²) mudstone interlayers. Brine recovery enhanced by supercritical CO₂ can successfully manage the regional pressure and decrease the leakage risk, even for the relative high permeability (k = 10^?17 m²) mudstone interlayers. In addition, since the leakage of brine mainly occurs in the early stage of brine production, it is possible to minimize the leakage risk by gradually decreasing the brine production pressure at the early stage. Since the leakage of CO₂ occurs in the whole production period and is significantly influenced by the buoyancy force, it may be more effective by adopting horizontal wells and optimizing well placement to reduce the CO₂ leakage risk.     

Characterization of deep saline aquifers in the Bécancour area,St. Lawrence Lowlands,Québec,Canada: implications for CO2 geological storage

The present paper provides a case study of the assessment of the potential for CO₂ storage in the deep saline aquifers of the Bécancour region in southern Québec. This assessment was based on a hydrogeological and petrophysical characterization using existing and newly acquired core and well log data from hydrocarbon exploration wells. Analyses of data obtained from different sources provide a good understanding of the reservoir hydrogeology and petrophysics. Profiles of formation pressure, temperature, density, viscosity, porosity, permeability, and net pay were established for Lower Paleozoic sedimentary aquifers. Lateral hydraulic continuity is dominant at the regional scale, whereas vertical discontinuities are apparent for most physical and chemical properties. The Covey Hill sandstone appears as the most suitable saline aquifer for CO₂ injection/storage. This unit is found at a depth of more than 1 km and has the following properties: fluid pressures exceed 14 MPa, temperature is above 35 °C, salinity is about 108,500 mg/l, matrix permeability is in the order of 3 × 10^?16 m² (0.3 mDarcy) with expected higher values of formation-scale permeability due to the presence of natural fractures, mean porosity is 6 %, net pay reaches 282 m, available pore volume per surface area is 17 m³/m², rock compressibility is 2 × 10^?9 Pa^?1 and capillary displacement pressure of brine by CO₂ is about 0.4 MPa. While the containment for CO₂ storage in the Bécancour saline aquifers can be ensured by appropriate reservoir characteristics, the injectivity of CO₂ and the storage capacity could be limiting factors due to the overall low permeability of aquifers. This characterization offers a solid basis for the subsequent development of a numerical hydrogeological model, which will be used for CO₂ injection capacity estimation, CO₂ injection scenarios and risk assessment.     

Numerical simulation of carbon dioxide injection for enhanced gas recovery (CO2-EGR) in Altmark natural gas field

This paper studied the CO₂-EGR in Altmark natural gas field with numerical simulations. The hydro-mechanical coupled simulations were run using a linked simulator TOUGH2MP-FLAC3D. In order to consider the gas mixing process, EOS7C was implemented in TOUGH2MP. A multi-layered 3D model (4.4 km × 2 km × 1 km) which consists of the whole reservoir, caprock and base rock was generated based on a history-matched PETREL model, originally built by GDF SUEZ E&P Deutschland GmbH for Altmark natural gas field. The model is heterogeneous and discretized into 26,015 grid blocks. In the simulation, 100,000 t CO₂ was injected in the reservoir through well S13 within 2 years, while gas was produced from the well S14. Some sensitivity analyses were also carried out. Simulation results show that CO₂ tends to migrate toward the production well S14 along a NW–SE fault. It reached the observation wells S1 and S16 after 2 years, but no breakthrough occurred in the production well. After 2 years of CO₂ injection, the reservoir pressure increased by 2.5 bar, which is beneficial for gas recovery. The largest uplift (1 mm) occurred at the bottom of the caprock. The deformation was small (elastic) and caprock integrity was not affected. With the injection rate doubled the average pressure increased by 5.3 bar. Even then the CO₂ did not reach the production well S14 after 2 years of injection. It could be concluded that the previous flow field was established during the primary gas production history. This former flow field, including CO₂ injection/CH₄ production rate during CO₂-EGR and fault directions and intensity are the most important factors affecting the CO₂ transport.     

Generation of CO2-rich melts during basalt magma ascent and degassing

To test mechanisms of basaltic magma degassing, continuous decompressions of volatile-bearing (2.7–3.8 wt% H₂O, 600–1,300 ppm CO₂) Stromboli melts were performed from 250–200 to 50–25 MPa at 1,180–1,140 °C. Ascent rates were varied from 0.25 to ~1.5 m/s. Glasses after decompression show a wide range of textures, from totally bubble-free to bubble-rich, the latter with bubble number densities from 10⁴ to 10⁶ cm^?3, similar to Stromboli pumices. Vesicularities range from 0 to ~20 vol%. Final melt H₂O concentrations are homogeneous and always close to solubilities. In contrast, the rate of vesiculation controls the final melt CO₂ concentration. High vesicularity charges have glass CO₂ concentrations that follow theoretical equilibrium degassing paths, whereas glasses from low vesicularity charges show marked deviations from equilibrium, with CO₂ concentrations up to one order of magnitude higher than solubilities. FTIR profiles and maps reveal glass CO₂ concentration gradients near the gas–melt interface. Our results stress the importance of bubble nucleation and growth, and of volatile diffusivities, for basaltic melt degassing. Two characteristic distances, the gas interface distance (distance either between bubbles or to gas–melt interfaces) and the volatile diffusion distance, control the degassing process. Melts containing numerous and large bubbles have gas interface distances shorter than volatile diffusion distances, and degassing proceeds by equilibrium partitioning of CO₂ and H₂O between melt and gas bubbles. For melts where either bubble nucleation is inhibited or bubble growth is limited, gas interface distances are longer than volatile diffusion distances. Degassing proceeds by diffusive volatile transfer at the gas–melt interface and is kinetically limited by the diffusivities of volatiles in the melt. Our experiments show that CO₂-oversaturated melts can be generated as a result of magma decompression. They provide a new explanation for the occurrence of CO₂-rich natural basaltic glasses and open new perspectives for understanding explosive basaltic volcanism.     

Sabatier-based CO2-methanation by catalytic conversion

The catalytic conversion of CO₂ is an important component for the reintegration of secondary products like CO₂ or H₂ into the energy supply. An example is the “power to gas” concept with a conversion of CO₂ into CH₄. The CO₂ is transferred into a carrier of chemical energy, with the possibility to feed the produced CH₄ into the existing network of natural gas. At temperatures of around 350 °C, hydrogenation of CO₂ to CH₄ is possible by the Sabatier reaction CO₂ + 4H₂ → CH₄ + 2H₂O. One prerequisite for efficient kinetics of the Sabatier reaction is the application and optimization of catalysts. The focus of catalyst development is given to their performance under the conditions to be expected in the special application. As a part of the project Geoenergy-Research (GeoEn), we address questions related to the catalytic utilization of CO₂ produced in the course of the oxyfuel combustion of lignite. In this contribution, we report on the experimental setup in laboratory scale, which enables an advanced characterization of the catalytic performance, including thermodesorption measurements at atmospheric pressure in order to determine the amount of adsorbed CO₂ under real conditions. We also show data for activation energies, the catalytic performance as function of temperature and the long time stability of a commercial Ru-based catalyst.     

Impacts of mineralogical compositions on different trapping mechanisms during long-term CO<Subscript>2</Subscript> storage in deep saline aquifers

Deep saline aquifers in sedimentary basins are considered to have the greatest potential for CO₂ geological storage in order to reduce carbon emissions. CO₂ injected into a saline sandstone aquifer tends to migrate upwards toward the caprock because the density of the supercritical CO₂ phase is lower than that of formation water. The accumulated CO₂ in the upper portions of the reservoir gradually dissolves into brine, lowers pH and changes the aqueous complexation, whereby induces mineral alteration. In turn, the mineralogical composition could impose significant effects on the evolution of solution, further on the mineralized CO₂. The high density of aqueous phase will then move downward due to gravity, give rise to “convective mixing,” which facilitate the transformation of CO₂ from the supercritical phase to the aqueous phase and then to the solid phase. In order to determine the impacts of mineralogical compositions on trapping amounts in different mechanisms for CO₂ geological storage, a 2D radial model was developed. The mineralogical composition for the base case was taken from a deep saline formation of the Ordos Basin, China. Three additional models with varying mineralogical compositions were carried out. Results indicate that the mineralogical composition had very obvious effects on different CO₂ trapping mechanisms. Specific to our cases, the dissolution of chlorite provided Mg²⁺ and Fe²⁺ for the formation of secondary carbonate minerals (ankerite, siderite and magnesite). When chlorite was absent in the saline aquifer, the dominant secondary carbon sequestration mineral was dawsonite, and the amount of CO₂ mineral trapping increased with an increase in the concentration of chlorite. After 3000 years, 69.08, 76.93, 83.52 and 87.24 % of the injected CO₂ can be trapped in the solid (mineral) phase, 16.05, 11.86, 8.82 and 6.99 % in the aqueous phase, and 14.87, 11.21, 7.66 and 5.77 % in the gas phase for Case 1 through 4, respectively.     

A review of coal properties pertinent to carbon dioxide sequestration in coal seams: with special reference to Victorian brown coals

This paper presents reviews of studies on properties of coal pertinent to carbon dioxide (CO₂) sequestration in coal with specific reference to Victorian brown coals. The coal basins in Victoria, Australia have been identified as one of the largest brown coal resources in the world and so far few studies have been conducted on CO₂ sequestration in this particular type of coals. The feasibility of CO₂ sequestration depends on three main factors: (1) coal mass properties (chemical, physical and microscopic properties), (2) seam permeability, and (3) gas sorption properties of the coal. Firstly, the coal mass properties of Victorian brown coal are presented, and then the general variations of the coal mass properties with rank, for all types of coal, are discussed. Subsequently, coal gas permeability and gas sorption are considered, and the physical factors which affect them are examined. In addition, existing models for coal gas permeability and gas sorption in coal are reviewed and the possibilities of further development of these models are discussed. According to the previous studies, coal mass properties and permeability and gas sorption characteristics of coals are different for different ranks: lignite to medium volatile bituminous coals and medium volatile bituminous to anthracite coals. This is important for the development of mathematical models for gas permeability and sorption behavior. Furthermore, the models have to take into account volume effect which can be significant under high pressure and temperature conditions. Also, the viscosity and density of supercritical CO₂ close to the critical point can undergo large and rapid changes. To date, few studies have been conducted on CO₂ sequestration in Victorian brown coal, and for all types of coal, very few studies have been conducted on CO₂ sequestration under high pressure and temperature conditions.     

Effects of in-situ conditions on relative permeability characteristics of CO2-brine systems

Carbon dioxide capture and geological storage (CCGS) is an emerging technology that is increasingly being considered for reducing greenhouse gas emissions to the atmosphere. Deep saline aquifers provide a very large capacity for CO₂ storage and, unlike hydrocarbon reservoirs and coal beds, are immediately accessible and are found in all sedimentary basins. Proper understanding of the displacement character of CO₂-brine systems at in-situ conditions is essential in ascertaining CO₂ injectivity, migration and trapping in the pore space as a residual gas or supercritical fluid, and in assessing the suitability and safety of prospective CO₂ storage sites. Because of lack of published data, the authors conducted a program of measuring the relative permeability and other displacement characteristics of CO₂-brine systems for sandstone, carbonate and shale formations in central Alberta in western Canada. The tested formations are representative of the in-situ characteristics of deep saline aquifers in compacted on-shore North American sedimentary basins. The results show that the capillary pressure, interfacial tension, relative permeability and other displacements characteristics of CO₂-brine systems depend on the in-situ conditions of pressure, temperature and water salinity, and on the pore size distribution of the sedimentary rock. This paper presents a synthesis and interpretation of the results.     

OpenGeoSys-ChemApp: a coupled simulator for reactive transport in multiphase systems and application to CO2 storage formation in Northern Germany

Sequestration of CO₂ into a deep geological reservoir causes a complex interaction of different processes such as multiphase flow, phase transition, multicomponent transport, and geochemical reactions between dissolved CO₂ and the mineral matrix of the porous medium. A prognosis of the reservoir behaviour and the feedback from large-scale geochemical alterations require efficient process-based numerical models. For this purpose, the multiphase flow and multicomponent transport code OpenGeoSys-Eclipse have been coupled to the geochemical model ChemApp. The newly developed coupled simulator was successfully verified for correctness and accuracy of the implemented reaction module by benchmarking tests. The code was then applied to assess the impact of geochemical reactions during CO₂ sequestration at a hypothetical but typical Bunter sandstone formation in the Northern German Basin. Injection and spreading of 1.48 × 10⁷ t of CO₂ in an anticline structure of the reservoir were simulated over a period of 20 years of injection plus 80 years of post-injection time. Equilibrium geochemical calculations performed by ChemApp show only a low reactivity to the geochemical system. The increased acidity of the aqueous solution results in dissolution of small amounts of calcite, anhydrite, and quartz. Geochemical alterations of the mineral phase composition result in slight increases in porosity and permeability, which locally may reach up to +0.02 and 0.1 %, respectively.     

A modified rock physics model for analysis of seismic signatures of low gas-saturated rocks

In seismic applications, the bulk modulus of porous media saturated with liquid and gas phases is often estimated using Gassmann's fluid substitution formula, in which the effective bulk modulus of the two-phase fluid is the Reuss average of the gas and liquid bulk moduli. This averaging procedure, referred to as Wood's approximation, holds if the liquid and gas phases are homogeneously distributed within the pore space down to sizes well below the seismic wavelength and if the phase transfer processes between liquid and gas domains induced by the pressure variations of the seismic wave are negligible over the timescale of the wave period. Using existing theoretical results and low-frequency acoustic measurements in bubbly liquids, we argue that the latter assumption of “frozen” phases, valid for large enough frequencies, is likely to fail in the seismic frequency range where lower effective bulk modulus and velocity, together with dispersion and attenuation effects, are expected. We provide a simple method, which extends to reservoir fluids a classical result by Landau and Lifshitz valid for pure fluids, to compute the effective bulk modulus of thermodynamically equilibrated liquid and gas phases. For low gas saturation, this modulus is significantly lower than its Wood's counterpart, especially at the crossing of bubble point conditions. A seismic reflector associated to a phase transition between a monophasic and a two-phase fluid thus will appear. We discuss the consequences of these results for various seismic applications including fizz water discrimination and hydrocarbon reservoir depletion and CO₂ geological storage monitoring.     

Thermo-hydro-mechanical modeling of carbon dioxide injection for enhanced gas-recovery (CO2-EGR): a benchmarking study for code comparison

The objective of this paper was to investigate the THM-coupled responses of the storage formation and caprock, induced by gas production, CO₂-EGR (enhanced gas recovery), and CO₂-storage. A generic 3D planer model (20,000?×?3,000?×?100?m, consisting of 1,200?m overburden, 100?m caprock, 200?m gas reservoir, and 1,500?m base rock) is adopted for the simulation process using the integrated code TOUGH2/EOS7C-FLAC3D and the multi-purpose simulator OpenGeoSys. Both simulators agree that the CO₂-EGR phase under a balanced injection rate (31,500?tons/year) will cause almost no change in the reservoir pressure. The gas recovery rate increases 1.4?% in the 5-year CO₂-EGR phase, and a better EGR effect could be achieved by increasing the distance between injection and production wells (e.g., 5.83?% for 5?km distance, instead of 1.2?km in this study). Under the considered conditions there is no evidence of plastic deformation and both reservoir and caprock behave elastically at all operation stages. The stress path could be predicted analytically and the results show that the isotropic and extensional stress regime will switch to the compressional stress regime, when the pore pressure rises to a specific level. Both simulators agree regarding modification of the reservoir stress state. With further CO₂-injection tension failure in reservoir could occur, but shear failure will never happen under these conditions. Using TOUGH-FLAC, a scenario case is also analyzed with the assumption that the reservoir is naturally fractured. The specific analysis shows that the maximal storage pressure is 13.6?MPa which is determined by the penetration criterion of the caprock.     

Experimental and numerical investigations on CO2 injection and enhanced gas recovery effects in Altmark gas field (Central Germany)

The feasibility of CO₂ storage and enhanced gas recovery (EGR) effects in the mature Altmark natural gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO₂ as well as reservoir simulation studies to evaluate the CO₂ wellbore injectivity and displacement efficiency of the residual gas by the injected CO₂. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO₂ has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO₂ injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO₂ gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO₂ volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO₂ will be maximized. The migration/extension of CO₂ varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO₂ extension and pressure propagation suggested no breakthrough of CO₂ at the prospective production well during the 3-year injection period studied.     

Modeling of the solubility of a one-component H2O or CO2 fluid in silicate liquids

The modeling of the solubility of water and carbon dioxide in silicate liquids (flash problem) is performed by assuming mechanical, thermal, and chemical equilibrium between the liquid magma and the gas phase. The liquid phase is treated as a mixture of ten silicate components + H₂O or CO₂, and the gas phase as a pure H₂O or CO₂. A general model for the solubility of a volatile component in a liquid is adopted. This requires the definition of a mixing equation for the excess Gibbs free energy of the liquid phase and an appropriate reference state for the dissolved volatile. To constrain the model parameters and identify the most appropriate form of the solubility equations for each dissolved volatile, a large number of experimental solubility determinations (640 for H₂O and 263 for CO₂) have been used. These determinations cover a large region of the P-T-composition space of interest. The resultant water and carbon dioxide solubility models differ in that the water model is regular and isometric, and the carbon dioxide model is regular and non-isometric. This difference is consistent with the different speciation modalities of the two volatiles in the silicate liquids, producing a composition-independent partial molar volume of dissolved water and a composition-dependent partial molar volume of dissolved carbon dioxide. The H₂O solubility model may be applied to natural magmas of virtually any composition in the P-T range 0.1 MPa–1 GPa and > 1000 K, whereas the CO₂ solubility model may be applied to several GPa pressures. The general consistency of the water solubility data and their relatively large number as compared to the calibrated model parameters (11) contrast with the large inconsistencies of the carbon dioxide solubility determinations and their low number with respect to the CO₂ model parameters (22). As a result, most of the solubility data in the database are reproduced within 10% of approximation in the case of water, and 30% in the case of carbon dioxide. When compared with the experimental data, the H₂O and CO₂ solubility models correctly predict many features of the saturation surface in the P-T-composition space, including the change from retrograde to prograde H₂O solubility in albitic liquids with increasing pressure, the so-called alkali effect, the increasing CO₂ solubility with increasing degree of silica undersaturation, the Henrian behavior of CO₂ in most silicate liquids up to about 30–50 MPa, and the proportionality between the fugacity in the gas phase, or the saturation activity in the liquid phase, and the square of the mole fraction of the dissolved volatile found in some unrelated silicate liquid compositions. Received: 21 August 1995 / Accepted: 8 July 1996     

Increased hydrocarbon recovery and CO2 management, a Croatian example

Enhanced oil recovery based on CO₂ injection is expected to increase recovery from Croatian oil fields. Large quantities of CO₂ are generated during hydrocarbon processing produced from gas and gas condensate fields situated in the north-western part of Croatia. First CO₂ injection project will be implemented on the Ivani? Oil Field. Numerical modelling based on Upper Miocene sandstone core samples testing results have shown the decrease of oil viscosity during CO₂ injection. Some of the characteristics of the testing samples are porosity 21.5–23.6 %, permeability 14–80 × 10^?15 m² and initial water saturation 28–38.5 %. Water alternating foam (WAF) and water alternating gas (WAG) simulations have provided satisfactory results. The WAF injection process has provided better results, but due to the process sensitivity and costs WAG is recommended for future application. During the pilot project 16 × 10⁶ m³ CO₂ and 5 × 10⁴ m³ of water were injected. Additional amounts of hydrocarbons (4,440 m³ of oil and 2.26 × 10⁶ m³ of gas) were produced which confirmed injection of CO₂ as a successful tertiary oil recovery mechanism in Upper Miocene sandstone reservoirs in the Croatian part of the Pannonian Basin System.     

An “On-Line” Method for Oxygen Isotope Exchange Between Gas-Phase CO<Subscript>2</Subscript> and Water

An “on-line” mixing system has been developed and evaluated for continuous oxygen isotope exchange between gas-phase CO₂ and liquid water. The system is composed of three basic parts: equipment and materials used to introduce water and gas into a mixing reservoir, the mixing and exchange reservoir, and a vessel used to separate gas and water phases exiting the system. A series of experiments were performed to monitor the isotope exchange process over a range of temperatures (5–40 °C) and CO₂ partial pressures (202–15,200 Pa). Isotopic exchange was evaluated using CO₂ having δ¹⁸O values of 30.4 and 37.8 ‰ and waters of two distinct oxygen isotope compositions (?6.5 to ?5 and 6 to 7.5 ‰). Isotope ratios were determined by isotope ratio mass spectrometry and cavity ring-down spectroscopy. CO₂ did not reach oxygen isotope equilibrium under the conditions described here. However, oxygen isotope exchange rate constants were determined at different temperatures and regressed to yield the expression k (h^?1) = 0.020 × T (°C) + 0.28. Using this expression, the residence time required to reach oxygen isotope equilibrium may be estimated for a given set of environmental conditions (e.g., δ¹⁸O value of water, temperature). System parameters can be modified to achieve a specific δ¹⁸O value for CO₂. Consequently, the exchange system described here has the ability to deliver a constant flow of CO₂ at a desired oxygen isotope composition. This ability is attractive for a variety of applications such as experiments that utilize flow-through reactors and environmental chambers or require static chemical conditions.