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The Special Issue “Water and Solute Transport in Vadose Zone” in the journal Water is dedicated to the memory of Dr. Gudmundur “Bo” Bodvarsson, the former director of the Earth Sciences Division of Lawrence Berkeley National Laboratory (http://eesa.lbl.gov/profiles/gudmundur-bo-sbodvarsson/).[...]

We have improved ECO2N, the TOUGH2 fluid property module of the CO2-H2O-NaCl system. The major enhancements include: (i) the upper temperature limit is increased from 110 to about 300°C; (ii) the thermophysical properties of the CO2-rich phase are more accurately calculated as a non-ideal mixture of CO2 and H2O; (iii) the approach to calculate the specific enthalpy of dissolved CO2 has been improved to make the code more robust in modeling phase transitions under non-isothermal conditions; and (iv) more sophisticated models for effective heat conductivity of formations saturated with supercritical CO2 have been provided. The new module includes a comprehensive description of the thermodynamic and thermophysical properties of H2ONaClCO2 mixtures, that reproduces fluid properties largely within experimental error for the temperature, pressure and salinity conditions 10°C < T < 300°C, P < 600 bar, and salinity up to halite saturation. This includes density, viscosity, and specific enthalpy of fluid phases as functions of temperature, pressure, and composition, as well as partitioning of mass components H2O, NaCl and CO2 among the different phases. ECO2N with the TOUGH2 reservoir simulator can be applied to a wide range of problems in geologic sequestration of CO2 in saline aquifers, and in enhanced geothermal reservoirs. ECO2N can describe both sub- and supercritical states of CO2, but applications that involve subcritical conditions are limited to systems in which there is no change of phase between liquid and gaseous CO2, and in which no mixtures of liquid and gaseous CO2 occur. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd.

Correlations are presented to compute the mutual solubilities of CO2 and chloride brines at temperatures 12–300°C, pressures 1–600 bar (0.1–60 MPa), and salinities 0–6 m NaCl. The formulation is computationally efficient and primarily intended for numerical simulations of CO2-water flow in carbon sequestration and geothermal studies. The phase-partitioning model relies on experimental data from literature for phase partitioning between CO2 and NaCl brines, and extends the previously published correlations to higher temperatures. The model relies on activity coefficients for the H2O-rich (aqueous) phase and fugacity coefficients for the CO2-rich phase. Activity coefficients are treated using a Margules expression for CO2 in pure water, and a Pitzer expression for salting-out effects. Fugacity coefficients are computed using a modified Redlich–Kwong equation of state and mixing rules that incorporate asymmetric binary interaction parameters. Parameters for the calculation of activity and fugacity coefficients were fitted to published solubility data over the P–T range of interest. In doing so, mutual solubilities and gas-phase volumetric data are typically reproduced within the scatter of the available data. An example of multiphase flow simulation implementing the mutual solubility model is presented for the case of a hypothetical, enhanced geothermal system where CO2 is used as the heat extraction fluid. In this simulation, dry supercritical CO2 at 20°C is injected into a 200°C hot-water reservoir. Results show that the injected CO2 displaces the formation water relatively quickly, but that the produced CO2 contains significant water for long periods of time. The amount of water in the CO2 could have implications for reactivity with reservoir rocks and engineered materials.

Injection of carbon dioxide (CO2) into saline aquifers confined by low- permeability cap rock will result in a layer of CO2 overlying the brine. Dissolution of CO2 into the brine increases the brine density, resulting in an unstable situation in which more-dense brine overlies less-dense brine. This gravitational instability could give rise to density-driven convection of the fluid, which is a favorable process of practical interest for CO2 storage security because it accelerates the transfer of buoyant CO2 into the aqueous phase, where it is no longer subject to an upward buoyant drive. Laboratory flow visualization tests in transparent Hele-Shaw cells have been performed to elucidate the processes and rates of this CO2 solute-driven convection (CSC). Upon introduction of CO2 into the system, a layer of CO2-laden brine forms at the CO2-water interface. Subsequently, small convective fingers form, which coalesce, broaden, and penetrate into the test cell. Images and time-series data of finger lengths and wavelengths are presented. Observed CO2 uptake of the convection system indicates that the CO2 dissolution rate is approximately constant for each test and is far greater than expected for a diffusion-only scenario. Numerical simulations of our system show good agreement with the experiments for onset time of convection and advancement of convective fingers. There are differences as well, the most prominent being the absence of cell-scale convection in the numerical simulations. This cell-scale convection observed in the experiments may be an artifact of a small temperature gradient induced by the cell illumination.

Water injection has been recognized as a powerful technique for enhancing energy recovery from vapor-dominated geothermal systems such as The Geysers. In addition to increasing reservoir pressures, production well flow rates, and long-term sustainability of steam production, injection has also been shown to reduce concentrations of non-condensible gases (NCGs) in produced steam. The latter effect improves energy conversion efficiency and reduces corrosion problems in wellbores and surface lines.This report reviews thermodynamic and hydrogeologic conditions and mechanisms that play an important role in reservoir response to water injection. An existing general-purpose reservoir simulator has been enhanced to allow modeling of injection effects in heterogeneous fractured reservoirs in three dimensions, including effects of non-condensible gases of different solubility. Illustrative applications demonstrate fluid flow and heat transfer mechanisms that are considered crucial for developing approaches to in situ abatement of NCGs.

Numerical simulation is used to evaluate mass flow and heat extraction rates from enhanced geothermal injection-production systems that are operated using either CO2 or water as heat transmission fluid. For a model system patterned after the European hot dry rock experiment at Soultz, we find significantly greater heat extraction rates for CO2 as compared to water. The strong dependence of CO2 mobility (= density/viscosity) upon temperature and pressure may lead to unusual production behavior, where heat extraction rates can actually increase for a time, even as the reservoir is subject to thermal depletion.

TOUGH2-MP is a massively parallel (MP) version of the TOUGH2 code, designed for computationally efficient parallel simulation of isothermal and nonisothermal flows of multicomponent, multiphase fluids in one, two, and three-dimensional porous and fractured media. In recent years, computational requirements have become increasingly intensive in large or highly nonlinear problems for applications in areas such as radioactive waste disposal, CO2 geological sequestration, environmental assessment and remediation, reservoir engineering, and groundwater hydrology. The primary objective of developing the parallel-simulation capability is to significantly improve the computational performance of the TOUGH2 family of codes. The particular goal for the parallel simulator is to achieve orders-of-magnitude improvement in computational time for models with ever-increasing complexity. TOUGH2-MP is designed to perform parallel simulation on multi-CPU computational platforms. An earlier version of TOUGH2-MP (V1.0) was based on the TOUGH2 Version 1.4 with EOS3, EOS9, and T2R3D modules, a software previously qualified for applications in the Yucca Mountain project, and was designed for execution on CRAY T3E and IBM SP supercomputers. The current version of TOUGH2-MP (V2.0) includes all fluid property modules of the standard version TOUGH2 V2.0. It provides computationally efficient capabilities using supercomputers, Linux clusters, or multi-core PCs, and also offers many user-friendly features. The parallel simulator inherits all process capabilities from V2.0 together with additional capabilities for handling fractured media from V1.4. This report provides a quick starting guide on how to set up and run the TOUGH2-MP program for users with a basic knowledge of running the (standard) version TOUGH2 code, The report also gives a brief technical description of the code, including a discussion of parallel methodology, code structure, as well as mathematical and numerical methods used. To familiarize users with the parallel code, illustrative sample problems are presented.

Large-scale water injection at The Geysers, California, has generated substantial benefits in terms of sustaining reservoir pressures and production rates, as well as improving steam composition by reducing the content of non-condensible gases (NCGs). Two effects have been recognized and discussed in the literature as contributing to improved steam composition, (1) boiling of injectate provides a source of "clean" steam to production wells, and (2) pressurization effects induced by boiling of injected water reduce upflow of native steam with large NCG concentrations from depth. In this paper we focus on a possible additional effect that could reduce NCGs in produced steam by dissolution in a condensed aqueous phase.Boiling of injectate causes pressurization effects that will fairly rapidly migrate outward, away from the injection point. Pressure increases will cause an increase in the saturation of condensed phase due to vapor adsorption on mineral surfaces, and capillary condensation in small pores. NCGs will dissolve in the additional condensed phase which, depending upon their solubility, may reduce NCG concentrations in residual steam.We have analyzed the partitioning of HCl between vapor and aqueous phases, and have performed numerical simulations of injection into superheated vapor zones. Our simulations provide evidence that dissolution in the condensed phase can indeed reduce NCG concentrations in produced steam.

This paper summarizes our research to date into operating EGS with CO2. Our modeling studies indicate that CO2 would achieve more favorable heat extraction than aqueous fluids. The peculiarthermophysical properties of CO2 give rise to unusual features in the dependence of energy recovery on thermodynamic conditions and time. Preliminary geochemical studies suggest that CO2 may avoid unfavorable rock-fluid interactions that have been encountered in water-basedsystems. To more fully evaluate the potential of EGS with CO2 will require an integrated research programme of model development, and laboratory and field studies.

An efficient parallel simulator for large-scale, long-term CO2 geologic sequestration in saline aquifers has been developed. The parallel simulator is a three-dimensional, fully implicit model that solves large, sparse linear systems arising from discretization of the partial differential equations for mass and energy balance in porous and fractured media. The simulator is based on the ECO2N module of the TOUGH2 code and inherits all the process capabilities of the single-CPU TOUGH2 code, including a comprehensive description of the thermodynamics and thermophysical properties of H2O-NaCl- CO2 mixtures, modeling single and/or two-phase isothermal or non-isothermal flow processes, two-phase mixtures, fluid phases appearing or disappearing, as well as salt precipitation or dissolution. The new parallel simulator uses MPI for parallel implementation, the METIS software package for simulation domain partitioning, and the iterative parallel linear solver package Aztec for solving linear equations by multiple processors. In addition, the parallel simulator has been implemented with an efficient communication scheme. Test examples show that a linear or super-linear speedup can be obtained on Linux clusters as well as on supercomputers. Because of the significant improvement in both simulation time and memory requirement, the new simulator provides a powerful tool for tackling larger scale and more complex problems than can be solved by single-CPU codes. A high-resolution simulation example is presented that models buoyant convection, induced by a small increase in brine density caused by dissolution of CO2.

This report details the work done between June 13 and September 30, 2006 by Lawrence Berkeley National Laboratory (LBNL) scientists to assist Fermi National Accelerator Laboratory (Fermilab) staff in understanding tritium transport at the Neutrino at the Main Injector (NuMI) facility. As a byproduct of beamline operation, the facility produces (among other components) tritium in engineered materials and the surrounding rock formation. Once the tritium is generated, it may be contained at the source location, migrate to other regions within the facility, or be released to the environment.

We use TOUGH+/GasH2O to study the effects of a heat source buried in the Martian permafrost to evaluate the possibility of establishing a wet zone of liquid water, in which terrestrial microorganisms could survive and multiply. Analysis of the problem indicates that (1) only a limited permafrost volume (not exceeding 0.35 m in radius) is affected, (2) a "wet" zone with limited amounts of liquid water de-velops (not exceeding 8 and 0.7 kg for a 250 W and a 62.5 W source, respectively), (3) the wet zone per-sists for a long time, becomes practically stationary after t = 20 sols because of venting into the Martian atmosphere, and its thickness is limited and decreases slowly over time, (4) a "dry" zone (where SG > 0.9) evolves, continues to expand (albeit slowly) with time, but its extent remains limited, and (5) the ice front surrounding the wet zone is self-sharpening. For a range of initial conditions investigated, evolution of the liquid water mass occurs at approximately the same rate, reaches roughly the same maximum, and occurs at about the same time (10 to 20 sols; 1 sol = 24.39 hours).

ECO2N is a fluid property module for the TOUGH2 simulator (Version 2.0) that was designed for applications to geologic storage of CO2 in saline aquifers. It includes a comprehensive description of the thermodynamics and thermophysical properties of H2O - NaCl - CO2 mixtures, that reproduces fluid properties largely within experimental error for the temperature, pressure and salinity conditions of interest (10oC

While the purpose of geologic storage in deep saline formations is to trap greenhouse gases underground, the potential exists for CO2 to escape from the target reservoir, migrate upward along permeable pathways, and discharge at the land surface. In this paper, we evaluate the potential for such CO2 discharges based on the analysis of natural analogs, where large releases of gas have been observed. We are particularly interested in circumstances that could generate sudden, possibly self enhancing release events. The probability for such events may be low, but the circumstances under which they occur and the potential consequences need to be evaluated in order to design appropriate site-selection and risk-management strategies. Numerical modeling of hypothetical test cases is suggested to determine critical conditions for large CO2 releases, to evaluate whether such conditions may be possible at designated storage sites, and, if applicable, to evaluate the potential impacts of such events as well as design appropriate mitigation strategies.

Rising atmospheric concentrations of CO2, and their role in global warming, have prompted efforts to reduce emissions of CO2 from burning of fossil fuels. An attractive mitigation option under consideration in many countries is the injection of CO2 from stationary sources, such as fossil-fueled power plants, into deep, stable geologic formations, where it would be stored and kept out of the atmosphere for time periods of hundreds to thousands of years or more. Potential geologic storage reservoirs include depleted or depleting oil and gas reservoirs, unmineable coal seams, and saline formations. While oil and gas reservoirs may provide some attractive early targets for CO2 storage, estimates for geographic regions worldwide have suggested that only saline formations would provide sufficient storage capacity to substantially impact atmospheric releases. This paper will focus on CO2 storage in saline formations.Injection of CO2 into a saline aquifer will give rise to immiscible displacement of brine by the advancing CO2. The lower viscosity of CO2 relative to aqueous fluids provides a potential for hydrodynamic instabilities during the displacement process. At typical subsurface conditions of temperature and pressure, CO2 is less dense than aqueous fluids and is subject to upward buoyancy force in environments where pressures are controlled by an ambient aqueous phase. Thus CO2 would tend to rise towards the top of a permeable formation and accumulate beneath the caprock. Some CO2 will also dissolve in the aqueous phase, while the CO2-rich phase may dissolve some formation waters, which would tend to dry out the vicinity of the injection wells. CO2 will make formation waters more acidic, and will induce chemical rections that may precipitate and dissolve mineral phases (Xu et al., 2004). As a consequence of CO2 injection, significant pressurization of formation fluids would occur over large areas. These pressurization effects will change effective stresses, and may cause movement along faults with associated seismicity and increases in permeability that could lead to leakage from the storage reservoir (Rutqvist and Tsang, 2005).

Large amounts of CO2 would need to be injected underground to achieve a significant reduction of atmospheric emissions. The large areal extent expected for CO2 plumes makes it likely that caprock imperfections will be encountered, such as fault zones or fractures, which may allow some CO2 to escape from the primary storage reservoir. Leakage of CO2 could also occur along wellbores. Concerns with escape of CO2 from a primary geologic storage reservoir include (1) acidification of groundwater resources, (2) asphyxiation hazard when leaking CO2 is discharged at the land surface, (3) increase in atmospheric concentrations of CO2, and (4) damage from a high-energy, eruptive discharge (if such discharge is physically possible). In order to gain public acceptance for geologic storage as a viable technology for reducing atmospheric emissions of CO2, it is necessary to address these issues and demonstrate that CO2 can be injected and stored safely in geologic formations.

The amounts of CO2 that would need to be injected into geologic storage reservoirs to achieve a significant reduction of atmospheric emissions are very large. A 1000 MWe coal-fired power plant emits approximately 30,000 tonnes of CO2 per day, 10 Mt per year (Hitchon, 1996). When injected underground over a typical lifetime of 30 years of such a plant, the CO2 plume may occupy a large area of order 100 km2 or more, and fluid pressure increase in excess of 1 bar (corresponding to 10 m water head) may extend over an area of more than 2,500 km2 (Pruess, et al., 2003). The large areal extent expected for CO2 plumes makes it likely that caprock imperfections will be encountered, such as fault zones or fractures, which may allow some CO2 to escape from the primary storage reservoir. Under most subsurface conditions of temperature and pressure, CO2 is buoyant relative to groundwaters. If (sub-)vertical pathways are available, CO2 will tend to flow upward and, depending on geologic conditions, may eventually reach potable groundwater aquifers or even the land surface. Leakage of CO2 could also occur along wellbores, including pre-existing and improperly abandoned wells, or wells drilled in connection with the CO2 storage operations. The pressure increases accompanying CO2 injection will give rise to changes in effective stress that could cause movement along faults, increasing permeability and potential for leakage.Escape of CO2 from a primary geologic storage reservoir and potential hazards associated with its discharge at the land surface raise a number of concerns, including (1) acidification of groundwater resources, (2) asphyxiation hazard when leaking CO2 is discharged at the land surface, (3) increase in atmospheric concentrations of CO2, and (4) damage from a high-energy, eruptive discharge (if such discharge is physically possible). In order to gain public acceptance for geologic storage as a viable technology for reducing atmospheric emissions of CO2, it is necessary to address these issues and demonstrate that CO2 can be injected and stored safely in geologic formations. This requires an understanding of the risks and hazards associated with geologic storage, and a demonstration that the risks are acceptably small or can be mitigated. Much work is currently underway to develop comprehensive approaches towards risk assessment from a systems analysis perspective, which in general requires a simplified description of physical and chemical processes (Maul, et al., 2004, Espie, 2004; Wildenborg, et al., 2004; Walton, et al., 2004). This type of approach is very important, but needs to be complemented with development of an understanding of the physical and chemical processes associated with CO2 storage and leakage (Evans, et al., 2004).

This report presents numerical simulations of isothermal reactive flows which might be induced in the caprock of an Italian depleted gas reservoir by the geological sequestration of carbon dioxide. Our objective is to verify that CO2 geological disposal activities already planned for the study area are safe and do not induce any undesired environmental impact.Gas-water-rock interactions have been modelled under two different intial conditions, i.e., assuming that i) caprock is perfectly sealed, or ii) partially fractured. Field conditions are better approximated in terms of the "sealed caprock model". The fractured caprock model has been implemented because it permits to explore the geochemical beahvior of the system under particularly severe conditions which are not currently encountered in the field, and then to delineate a sort of hypothetical maximum risk scenario.Major evidences supporting the assumption of a sealed caprock stem from the fact that no gas leakages have been detected during the exploitation phase, subsequent reservoir repressurization due to the ingression of a lateral aquifer, and during several cycles of gas storage in the latest life of reservoir management.An extensive program of multidisciplinary laboratory tests on rock properties, geochemical and microseismic monitoring, and reservoir simulation studies is underway to better characterize the reservoir and cap-rock behavior before the performance of a planned CO2 sequestration pilot test.In our models, fluid flow and mineral alteration are induced in the caprock by penetration of high CO2 concentrations from the underlying reservoir, i.e., it was assumed that large amounts of CO2 have been already injected at depth. The main focus is on the potential effect of these geochemical transformations on the sealing efficiency of caprock formations. Batch and multi-dimensional 1D and 2D modeling has been used to investigate multicomponent geochemical processes. Our simulations account for fracture-matrix interactions, gas phase participation in multiphase fluid flow and geochemical reactions, and kinetics of fluid-rock interactions.The main objectives of the modeling are to recognize the geochemical processes or parameters to which the advancement of high CO2 concentrations in the caprock is most sensitive, and to describe the most relevant mineralogical transformations occurring in the caprock as a consequence of such CO2 storage in the underlying reservoir. We also examine the feedback of these geochemical processes on physical properties such as porosity, and evaluate how the sealing capacity of the caprock evolves in time.

As part of the Frio Brine Pilot, downhole pressure measurements were obtained from both the injection well and observation well throughout the injection and recovery phases of the test. In addition, a pre-injection interference test was used to obtain accurate information about the permeability and compressibility of the formation. By comparing the two data sets it is possible to obtain information on field-scale relative permeability during CO2 injection. Both numerical and analytical techniques have been used to interpret the pressure transient data. Comparison between pressure transients at the injection well and observation well allow inference about changes in near-well permeability in the vicinity of the injection well. This is the first time a data set such as this has been collected for CO2 injection into a saline formation, and the results provide important insights into the multi-phase flow behavior of CO2. They also provide important information for predicting the injectivity of saline formations.

While the purpose of geologic storage in deep saline formations is to trap greenhouse gases underground, the potential exists for CO2 to escape from the target reservoir, migrate upward along permeable pathways, and discharge at the land surface. In this paper, we evaluate the potential for such CO2 discharges based on the analysis of natural analogs, where large releases of gas have been observed. We are particularly interested in circumstances that could generate sudden, possibly self-enhancing release events. The probability for such events may be low, but the circumstances under which they occur and the potential consequences need to be evaluated in order to design appropriate site-selection and risk-management strategies. Numerical modeling of hypothetical test cases is suggested to determine critical conditions for large CO2 releases, to evaluate whether such conditions may be possible at designated storage sites, and, if applicable, to evaluate the potential impacts of such events as well as design appropriate mitigation strategies.

TMVOC is designed for studying subsurface contamination by volatile organic compounds (VOCs), such as hydrocarbon fuels and industrial solvents. It can model the one-, two-, or three-dimensional migration of non-aqueous phase liquids (NAPLs) through the unsaturated and saturated zones, the formation of an oil lens on the water table, the dissolution and subsequent transport of VOCs in groundwater, as well as the vaporization and migration of VOCs in the interstitial air of the unsaturated zone, and the reversible sorption of VOCs on the rock matrix of a porous medium. TMVOC accounts for differences in aqueous solubility and volatility of different VOCs that may be present in a NAPL. Thermal remediation treatments such as steam injection or electric resistance heating and associated phase change and flow effects can also be modeled. A simple half-life model for biodegradation is included as well.

Storage of greenhouse gases, primarily CO2, in geologic formations has been proposed as a means by which atmospheric emissions of such gases may be reduced (Bachu et al., 1994; Orr, 2004). Possible storage reservoirs currently under consideration include saline aquifers, depleted or depleting oil and gas fields, and unmineable coal seams (Baines and Worden, 2004). The amount of CO2 emitted from fossil-fueled power plants is very large, of the order of 30,000 tonnes per day (10 million tonnes per year) for a large 1,000 MW coal-fired plant (Hitchon, 1996). In order to make a significant impact on reducing emissions, very large amounts of CO2 would have to be injected into subsurface formations, resulting in CO2 disposal plumes with an areal extent of order 100 km2 or more (Pruess et al., 2003). It appears inevitable, then, that such plumes will encounter imperfections in caprocks, such as fracture zones or faults, that would allow CO2 to leak from the primary storage reservoir. At typical subsurface conditions of temperature and pressure, CO2 is always less dense than aqueous fluids; thus buoyancy forces will tend to drive CO2 upward, towards the land surface, whenever adequate (sub-)vertical permeability is available. Upward migration of CO2 could also occur along wells, including pre-existing wells in sedimentary basins where oil and gas exploration and production may have been conducted (Celia et al., 2004), or along wells drilled as part of a CO2 storage operation.Concerns with leakage of CO2 from a geologic storage reservoir include (1) keeping the CO2 contained and out of the atmosphere, (2) avoiding CO2 entering groundwater aquifers, (3) asphyxiation hazard if CO2 is released at the land surface, and (4) the possibility of a self-enhancing runaway discharge, that may culminate in a "pneumatic eruption" (Giggenbach et al., 1991). The manner in which CO2 may leak from storage reservoirs must be understoodin order to avoid hazards and design monitoring systems.

Leakage of CO2 from a hypothetical geologic storage reservoir along an idealized fault zone has been simulated, including transitions between supercritical, liquid, and gaseous CO2. We find strong non-isothermal effects due to boiling and Joule-Thomson cooling of expanding CO2. Leakage fluxes are limited by limitations in conductive heat transfer to the fault zone. The interplay between multiphase flow and heat transfer effects produces non-monotonic leakage behavior.

The transport of chemicals or heat in fractured reservoirs is strongly affected by the fracture-matrix interfacial area. In a vapor-dominated geothermal reservoir, this area can be estimated by inert gas tracer tests, where gas diffusion between the fracture and matrix causes the tracer breakthrough curve (BTC) to have a long tail determined by the interfacial area. For water-saturated conditions, recent studies suggest that sorbing solute tracers can also generate strong tails in BTCs that may allow a determination of the fracture-matrix interfacial area. To theoretically explore such a useful phenomenon, this paper develops an analytical solution for BTCs in slug-tracer tests in a water-saturated fractured reservoir. The solution shows that increased sorption should have the same effect on BTCs as an increase of the diffusion coefficient. The solution is useful for understanding transport mechanisms, verifying numerical codes, and for identifying appropriate chemicals as tracers for the characterization of fractured reservoirs.

Fluid flow in geothermal production and injection wells can be strongly affected by heat transfer effects with the formations surrounding the wellbore. Various techniques and approximations to model wellbore heat transmission have been presented in the literature. The objective of the present work is to develop a treatment of conductive heat transfer in the formations surrounding a wellbore that is simple, yet provides good accuracy for transient effects at early time. This is accomplished by adapting the well known semi-analytical heat transfer method of Vinsome and Westerveld (1980) to the problem of heat transfer to and from a flowing well. The Vinsome-Westerveld method treats heat exchange between a reservoir and adjacent cap and base rocks by means of a hybrid numerical-analytical method, in which temperature distributions in the conductive domain are approximated by simple trial functions, whose parameters are obtained concurrently with the numerical solution for the flow domain. This method can give a very accurate representation of conductive heat transfer even for non-monotonic temperature variations over a broad range of time scales. The only enhancement needed for applying the method to wellbore heat transmission is taking account of the cylindrical geometry around a flowing well, as opposed to the linear flow geometry in cap and base rocks. We describe the generalization of trial functions needed for cylindrical geometry, and present our implementation into the TOUGH2 reservoir simulator. The accuracy of the method is evaluated through application to non-isothermal flow through a pipe.

TOUGHREACT is a numerical simulation program for chemically reactive non-isothermal flows of multiphase fluids in porous and fractured media. The program was written in Fortran 77 and developed by introducing reactive geochemistry into the multiphase fluid and heat flow simulator TOUGH2. A variety of subsurface thermo-physical-chemical processes are considered under a wide range of conditions of pressure, temperature, water saturation, ionic strength, and pH and Eh. Interactions between mineral assemblages and fluids can occur under local equilibrium or kinetic rates. The gas phase can be chemically active. Precipitation and dissolution reactions can change formation porosity and permeability. The program can be applied to many geologic systems and environmental problems, including geothermal systems, diagenetic and weathering processes, subsurface waste disposal, acid mine drainage remediation, contaminant transport, and groundwater quality. Here we present two examples to illustrate applicability of the program: (1) injectivity effects of mineral scaling in a fractured geothermal reservoir and (2) CO2 disposal in a deep saline aquifer.

Correlations presented by Spycher et al. (2003) to compute the mutual solubilities of CO2 and H2O are extended to include the effect of chloride salts in the aqueous phase. This is accomplished by including, in the original formulation, activity coefficients for aqueous CO2 derived from several literature sources, primarily for NaCl solutions. Best results are obtained when combining the solubility correlations of Spycher et al. (2003) with the activity coefficient formulation of Rumpf et al. (1994) and Duan and Sun (2003), which can be extended to chloride solutions other than NaCl. This approach allows computing mutual solubilities in a noniterative manner with an accuracy typically within experimental uncertainty for solutions up to 6 molal NaCl and 4 molal CaCl2.