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.     

Monitoring above-zone temperature variations associated with CO2 and brine leakage from a storage aquifer

CO₂ injection in saline aquifers induces temperature changes owing to processes such as Joule–Thomson cooling, endothermic water vaporization, exothermic CO₂ dissolution besides the temperature discrepancy between injected and native fluids. CO₂ leaking from the injection zone, in addition to initial temperature contrast due to the geothermal gradient, undergoes similar processes, causing temperature changes in the above zone. Numerical simulation tools were used to evaluate temperature changes associated with CO₂ leakage from the storage aquifer to an above-zone monitoring interval and to assess the monitorability of CO₂ leakage on the basis of temperature data. The impact of both CO₂ and brine leakage on temperature response is considered for three cases (1) a leaky well co-located with the injection well, (2) a leaky well distant from the injector, and (3) a leaky fault. A sensitivity analysis was performed to determine key operational and reservoir parameters that control the temperature signal in the above zone. Throughout the analysis injection-zone parameters remain unchanged. Significant pressure drop upon leakage causes expansion of CO₂ associated with Joule–Thomson cooling. However, brine may begin leaking before CO₂ breakthrough at the leakage pathway, causing heating in the above zone. Thus, unlike the pressure which increases in response to both CO₂ and brine leakage, the temperature signal may differentiate between the leaking fluids. In addition, the strength of the temperature signal correlates with leakage velocity unlike pressure signal whose strength depends on leakage rate. Increasing leakage conduit cross-sectional area increases leakage rate and thus increases pressure change in the above zone. However, it decreases leakage velocity, and therefore, reduces temperature cooling and signal. It is also shown that the leakage-induced temperature change covers a small area around the leakage pathway. Thus, temperature data will be most useful if collected along potential leaky wells and/or wells intersecting potential leaky faults.     

Numerical simulation and optimization of CO2 sequestration in saline aquifers for vertical and horizontal well injection

With heightened concerns on CO₂ emissions from pulverized-coal (PC) power plants, there has been major emphasis in recent years on the development of safe and economical geological carbon sequestration (GCS) technology. Saline aquifers are considered very attractive for GCS because of their large storage capacity in U.S. and other parts of the world for long-term sequestration. However, uncertainties about storage efficiency as well as leakage risks remain major areas of concern that need to be addressed before the saline aquifers can be fully exploited for carbon sequestration. A genetic algorithm-based optimizer has been developed and coupled with the well-known multiphase numerical solver TOUGH2 to optimally examine various injection strategies for increasing the CO₂ storage efficiency as well as for reducing its plume migration. The optimal injection strategies for CO₂ injection employing a vertical injection well and a horizontal injection well are considered. To ensure the accuracy of the results, the combined hybrid numerical solver/optimizer code was validated by conducting simulations of three widely used benchmark problems employed by carbon sequestration researchers worldwide. The validated code is then employed to optimize the proposed water-alternating-gas injection scheme for CO₂ sequestration using both the vertical and the horizontal injection wells. The results suggest the potential benefits of CO₂ migration control and dissolution. The optimization capability of the hybrid code holds a great promise in studying a host of other problems in GCS, namely how to optimally enhance capillary trapping, accelerate the dissolution of CO₂ in water or brine, and immobilize the CO₂ plume.     

Modeling the effects of completion techniques and formation heterogeneity on CO2 sequestration in shallow and deep saline aquifers

This work studied the effect of completion techniques and reservoir heterogeneity on CO₂ storage and injectivity in saline aquifers using a compositional reservoir simulator, CMG-GEM. Two reservoir models were built based on the published data to represent a deep saline aquifer and a shallow aquifer. The effect of various completion conditions on CO₂ storage was then discussed, including partial perforation of the reservoir net pay (partial completion), well geometry, orientation, location, and length. The heterogeneity effect was addressed by considering three parameters: mean permeability, the vertical to horizontal permeability ratio, and permeability variation. Sensitivity analysis was carried out using iSIGHT software (design of experiments) to determine the dominant factors affecting CO₂ storage capacity and injectivity. Simulation results show that the most favorable option is the perforation of all layers with horizontal wells 250–300 m long set in the upper layers. Mean permeability has the most effect on CO₂ storage capacity and injectivity; k _v/k _h affects CO₂ injectivity storage capacity more than permeability variation, V _k. More CO₂ can be stored in the heterogeneous reservoirs with low mean permeability; however, high injectivity can be achieved in the uniform reservoirs with high mean permeability.     

The cost of meeting increased cooling-water demands for CO2 capture and storage utilizing non-traditional waters from geologic saline formations

Deep (> ～800 m) saline water-bearing formations in the United States have substantial pore volume that is targeted for storage of carbon dioxide (CO₂) and the associated saline water can be extracted to increase CO₂ storage efficiency, manage pressure build up, and create a new water source that, once treated, can be used for power-plant cooling or other purposes. Extraction, treatment and disposal costs of saline formation water to meet added water demands from CO₂ capture and storage (CCS) are discussed. This underutilized water source may be important in meeting new water demand associated with CCS. For a representative natural gas combined-cycle (NGCC) power plant, simultaneous extraction of brine from the storage formation could provide enough water to meet all CCS-related cooling demands for 177 out of the 185 (96 %) saline formations analyzed in this study. Calculated total cost of water extraction, treatment and disposal is less than 4.00 US Dollars (USD) m^?3 for 93 % of the 185 formations considered. In 90 % of 185 formations, treated water costs are less than 10.00 USD tonne^?1 of CO₂ injected. On average, this represents approximately 6 % of the total CO₂ capture and injection costs for the NGCC scenario.     

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.     

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.     

Pressure transient technique to constrain CO<Subscript>2</Subscript> plume boundaries

Carbon dioxide (CO₂) has been injected in the subsurface permeable formations as a means to cut atmospheric CO₂ emissions and/or enhance oil recovery (EOR). It is important to constrain the boundaries of the CO₂ plume in the target formation and/or other formations hosting the CO₂ migrated from the target formation. Monitoring methods and technologies to assess the CO₂ plume boundaries over time within a reservoir of interest are required. Previously introduced methods and technologies on pressure monitoring to detect the extent of the CO₂ plume require at least two wells, i.e. pulser and observation wells. We introduce pressure transient technique requiring single well only. Single well pressure transient testing (drawdown/buildup/injection/falloff) is widely used to determine reservoir properties and wellbore conditions. Pressure diagnostic plots are used to identify different flow regimes and determine the reservoir/well characteristics. We propose a method to determine the plume extent for a constant rate pressure transient test at a single well outside the CO₂ plume. Due to the significant contrast between mobility and storativity of the CO₂ and native fluids (oil or brine), the CO₂ boundary causes deviation in the pressure diagnostic response from that corresponding to previously identified heterogeneities. Using the superposition principle, we develop a relationship between the deviation time and the plume boundary. We demonstrate the applicability of the proposed method using numerically generated synthetic data corresponding to homogeneous, heterogeneous, and anisotropic cases to evaluate its potential and limitations. We discuss ways to identify and overcome the potential limitations for application of the method in the field.     

Spatial characterization of the location of potentially leaky wells penetrating a deep saline aquifer in a mature sedimentary basin

This work was motivated by considerations of potential leakage pathways for CO₂ injected into deep geological formations for the purpose of carbon sequestration. Because existing wells represent a potentially important leakage pathway, a spatial analysis of wells that penetrate a deep aquifer in the Alberta Basin was performed and various statistical measures to quantify the spatial distribution of these wells were presented. The data indicate spatial clustering of wells, due to oil and gas production activities. The data also indicate that the number of wells that could be impacted by CO₂ injection, as defined by the spread of an injected CO₂ plume, varies from several hundred in high well-density areas to about 20 in low-density areas. These results may be applied to other mature continental sedimentary basins in North America and elsewhere, where detailed information on well location and status may not be available.     

Site characterization for CO<Subscript>2</Subscript> geologic storage and vice versa: the Frio brine pilot,Texas, USA as a case study

Careful site characterization is critical for successful geologic storage of carbon dioxide (CO₂) because of the many physical and chemical processes impacting CO₂ movement and containment under field conditions. Traditional site characterization techniques such as geological mapping, geophysical imaging, well logging, core analyses, and hydraulic well testing provide the basis for judging whether or not a site is suitable for CO₂ storage. However, only through the injection and monitoring of CO₂ itself can the coupling between buoyancy flow, geologic heterogeneity, and history-dependent multi-phase flow effects be observed and quantified. CO₂ injection and monitoring can therefore provide a valuable addition to the site-characterization process. Additionally, careful monitoring and verification of CO₂ plume development during the early stages of commercial operation should be performed to assess storage potential and demonstrate permanence. The Frio brine pilot, a research project located in Dayton, Texas (USA) is used as a case study to illustrate the concept of an iterative sequence in which traditional site characterization is used to prepare for CO₂ injection and then CO₂ injection itself is used to further site-characterization efforts, constrain geologic storage potential, and validate understanding of geochemical and hydrological processes. At the Frio brine pilot, in addition to traditional site-characterization techniques, CO₂ movement in the subsurface is monitored by sampling fluid at an observation well, running CO₂-saturation-sensitive well logs periodically in both injection and observation wells, imaging with crosswell seismic in the plane between the injection and observation wells, and obtaining vertical seismic profiles to monitor the CO₂ plume as it migrates beyond the immediate vicinity of the wells. Numerical modeling plays a central role in integrating geological, geophysical, and hydrological field observations.     

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.     

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.     

Dissolution kinetics of selected natural minerals relevant to potential CO2-injection sites – Part 2: Dissolution and alteration of carbonates and feldspars in CO2-bearing brines

Chemical interaction processes among injected CO₂, saline fluids and potential reservoir materials are experimentally simulated to derive dissolution rates of natural materials (minerals) that can be used as input parameters for modeling of CO₂ storage in deep saline formations and risk analyses. In order to study dissolution processes, mineral aliquots were exposed to CO₂-bearing brines at elevated temperature (60, 100, 150 °C) and pressure (85 bar) and at various run durations. Several potential reservoir rocks include carbonates as cement. Calcite and dolomite grains were therefore mainly used as solid starting material. Experiments with the two feldspar varieties alkali feldspar and almost pure anorthite were performed in addition. Grain sizes of the mineral starting materials varied between <63 μm and 500 μm with most experiments performed at grain size fractions of 160 – 250 μm and 250 – 500 μm. All experiments run with a complex synthetic brine (total dissolved solids: ∼156 g/l) according to a natural upper cretaceous formation water. Dry ice was used as CO₂-source. All experiments were done in closed batch reactors. These reactors allow mimicking reservoir conditions far from the injection site as well as reservoir conditions after finishing the CO₂ injection. The concentration changes during the experiment were monitored by ICP-OES measurements of the initial and the post-run fluids. Dissolution rates were derived based on the concentration changes of the brine.Most of the studied experimental variables and parameters (temperature, run duration, grain size, brine composition – expressed as pH-value and ionic strength) impact alteration of the reacting agents, i.e. they change the chemical composition of the brine, change the surfaces of the mineral aliquots exposed to the CO₂-bearing brine, and induce formation of secondary minerals. Hence, all influencing parameters on dissolution processes have to be considered and time-resolved changes of the dissolution behavior have to be implemented in numerical simulations of processes at CO₂ injection sites and CO₂ storage reservoirs.     

A pressure-monitoring method to warn CO2 leakage in geological storage sites

This paper proposes a pressure-monitoring method to warn any possible CO₂ leakage by monitoring pressure change at the upper layer of storage reservoirs within injection wells. The monitoring method is tested with two problems under various scenarios. With a current pressure detection limit, the proposed pressure-monitoring technique can be widely applicable wherever a permeable upper formation exists above the CO₂ storage reservoir and is effective even in offshore storage sites wherever conventional monitoring methods for onshore sites cannot be applied. Meanwhile, the method is limited to apply during injection and is subject to any possible pressure dampening.     

Gas–water–rock interactions in sedimentary basins: CO2 sequestration in the Frio Formation, Texas, USA

To investigate the potential for the geologic storage of CO₂ in saline sedimentary aquifers, 1600 ton of CO₂ were injected at 1500 m depth into a 24-m sandstone section of the Frio Formation — a regional reservoir in the US Gulf Coast. Fluid samples obtained from the injection and observation wells before, during and after CO₂ injection show a Na–Ca–Cl type brine with 93,000 mg/L TDS and near saturation of CH₄ at reservoir conditions. As injected CO₂ gas reached the observation well, results showed sharp drops in pH (6.5 to 5.7), pronounced increases in alkalinity (100 to 3000 mg/L as HCO₃) and Fe (30 to 1100 mg/L), and significant shifts in the isotopic compositions of H₂O and DIC. Geochemical modeling indicates that brine pH would have dropped lower, but for buffering by dissolution of calcite and Fe oxyhydroxides. Post-injection results show the brine gradually returning to its pre-injection composition.     

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 626 metric 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 11 m 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.     

Simulation of CO2 plume movement in multilayered saline formations through multilayer injection technology in the Ordos Basin,China

Deep saline aquifers still remain a significant option for the disposal of large amounts of CO₂ from the atmosphere as a means of mitigating global climate change. The small scale Carbon Capture and Sequestration demonstration project in Ordos Basin, China, operated by the Shenhua Group, is the only one of its kind in Asia, to put the multilayer injection technology into practice. This paper aims at studying the influence of temperature, injection rate and horizontal boundary effects on CO₂ plume transport in saline formation layers at different depths and thicknesses, focusing on the variations in CO₂ gas saturation and mass fraction of dissolved CO₂ in the formation of brine in the plume’s radial three-dimensional field around the injection point, and interlayer communication between the aquifer and its confining beds of relatively lower permeability. The study uses the ECO2N module of TOUGH2 to simulate flow and pressure configurations in response to small-scale CO₂ injection into multilayer saline aquifers. The modelling domain involves a complex multilayer reservoir–caprock system, comprising of a sequence of sandstone aquifers and sealing units of mudstone and siltstone layers extending from the Permian Shanxi to the Upper Triassic Liujiagou formation systems in the Ordos Basin. Simulation results indicate that CO₂ injected for storage into deep saline aquifers cause a significant pressure perturbation in the geological system that may require a long duration in the post-injection period to establish new pressure equilibrium. The multilayer simultaneous injection scheme exhibits mutual interference with the intervening sealing layers, especially when the injection layers are very close to each other and the corresponding sealing layers are thin. The study further reveals that injection rate and temperature are the most significant factors for determining the lateral and vertical extent that the CO₂ plume reaches and which phase and amount will exist at a particular time during and after the injection. In general, a large number of factors may influence the CO₂–water fluid flow system considering the complexity in the real geologic sequence and structural configurations. Therefore, optimization of a CO₂ injection scheme still requires pursuance of further studies.     

CO<Subscript>2</Subscript> leakage through an abandoned well: problem-oriented benchmarks

The efficiency and sustainability of carbon dioxide (CO₂) storage in deep geological formations crucially depends on the integrity of the overlying cap-rocks. Existing oil and gas wells, which penetrate the formations, are potential leakage pathways. This problem has been discussed in the literature, and a number of investigations using semi-analytical mathematical approaches have been carried out by other authors to quantify leakage rates. The semi-analytical results are based on a number of simplifying assumptions. Thus, it is of great interest to assess the influence of these assumptions. We use a numerical model to compare the results with those of the semi-analytical model. Then we ease the simplifying restrictions and include more complex thermodynamic processes including sub- and supercritical fluid properties of CO₂ and non-isothermal as well as compositional effects. The aim is to set up problem-oriented benchmark examples that allow a comparison of different modeling approaches to the problem of CO₂ leakage.     

Well blowout rates and consequences in California Oil and Gas District 4 from 1991 to 2005: implications for geological storage of carbon dioxide

Well blowout rates in oil fields undergoing thermally enhanced recovery (via steam injection) in California Oil and Gas District 4 from 1991 to 2005 were on the order of 1 per 1,000 well construction operations, 1 per 10,000 active wells per year, and 1 per 100,000 shut-in/idle and plugged/abandoned wells per year. This allows some initial inferences about leakage of CO₂ via wells, which is considered perhaps the greatest leakage risk for geological storage of CO₂. During the study period, 9% of the oil produced in the United States was from District 4, and 59% of this production was via thermally enhanced recovery. There was only one possible blowout from an unknown or poorly located well, despite over a century of well drilling and production activities in the district. The blowout rate declined dramatically during the study period, most likely as a result of increasing experience, improved technology, and/or changes in safety culture. If so, this decline indicates the blowout rate in CO₂-storage fields can be significantly minimized both initially and with increasing experience over time. Comparable studies should be conducted in other areas. These studies would be particularly valuable in regions with CO₂-enhanced oil recovery (EOR) and natural gas storage. Electronic supplementary material  The online version of this article (doi:) contains supplementary material, which is available to authorized users.