Search

Carbon dioxide (CO2) extraction from deep reservoirs is currently important in CO2 enhanced oil recovery (EOR) and may become more important in the future if interim CO2 storage becomes common. In late 2014, we were involved in a production test of liquid CO2 from the Middle Duperow dolostone at Kevin Dome, Montana. The test resulted in lowering the temperature at the well bottom to ∼2 °C, and showed that the well and reservoir had very low CO2 productivity. We have used the CO2 modeling capabilities of the TOUGH codes to simulate the test and to show that liquid CO2 in the reservoir changes to gas phase as the pressure is lowered in the well during production testing. The associated phase change and decompression combine to drastically lower the bottom‐hole temperature, creating the potential for water ice or CO2 hydrate to form. By hypothesizing a relatively high‐permeability damage zone near the well surrounded by lower permeability reservoir rock, we can match the observed pressure, temperature, and production rate. Moving from the Kevin Dome test to the question of CO2 extraction from deep reservoirs in general, we carried out a parametric study to investigate the effects of reservoir depth and transmissivity on CO2 production rate for a prototypical reservoir. Simulations show that depth and high transmissivity favor productivity. Complex phase changes within the ranges of P‐T encountered in typical CO2 production wells affect production rates. The results of our parametric study may be useful for the preliminary feasibility assessment of CO2 extraction from deep reservoirs. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

CO 2 has been proposed as a working fluid for geothermal energy production because of its ability to establish a self-sustaining CO 2 thermosiphon, taking advantage of the strong temperature dependence of CO 2 density. To test the concept of CO 2 heat extraction, in January 2015 a CO 2 thermosiphon was operated at the SECARB Cranfield Site, Cranfield, Mississippi, where a brine-saturated sand at a depth of 3.2 km has been under near continuous CO 2 flood since December 2009 as part of a U.S. Department of Energy demonstration of CO 2 sequestration, resulting in a partially saturated reservoir surrounding a well pair. The lateral distance between the producer and injector was 112 m at reservoir depth, a distance considered pre-commercial in scale, but great enough that thermal breakthrough was still not significant after several years of injection. Instead of producing power with a turbine, heat was extracted heat from recirculated fluid using a heat exchanger and portable chiller. The well field and surface equipment were instrumented to compare field observations with predicted responses from numerical models. Thermosiphon flow could be initiated by venting, but thereafter flow rate steadily declined, indicating that the thermosiphon was not sustainable. To model the system, the capability of T2Well, a fully coupled wellbore/reservoir numerical simulator, was expanded to enable simulation of the entire loop of fluid circulation in the fully-coupled system consisting of the injection/production wells, the reservoir, and the surface devices (heat exchanger, flow-rate regulator etc.). Combined with the newly developed TOUGH2 equation of state module called EOS7CMA, the enhanced T2Well was used prior to the field experiment to simulate the circulation of a CO 2 -H 2 O-CH 4 mixture in a model geothermal system patterned after the Cranfield demonstration test. The model predicted that a sustainable thermosiphon could be achieved. After the field thermosiphon did not achieve the pre-test prediction of flow rates and thermosiphon sustainability, the numerical model was modified to improve realism and calibrate certain processes; it was then able to reproduce the major phenomena observed in the field. In a series of sensitivity studies, many factors were found that could potentially contribute to the failing of a sustainable thermosiphon. These factors could be categorized as two types: factors that increase the resistance to flow and factors that increase heat loss of the working fluid. The lessons learned can be applied to both future modeling and to achieving CO 2 -based geothermal reservoir exploitation. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

We consider using CO 2 as an alternative to water as a working fluid to produce geothermal electricity through the application of a coupled reservoir, wellbore, and surface power-plant model. Our approach has relaxed some of the simplifying assumptions others have made in previous work, through the application of a subsurface reservoir model fully coupled with a detailed wellbore simulator. We also include a simplified representation of CO 2 turbomachinery for a surface plant optimized for direct use of supercritical CO 2 . The wellbore model includes heat transfer between the fluid in the well and the surrounding formation, in addition to frictional, inertial, and gravitational forces. Our results show that thermophysical operating conditions and the amount of power production are greatly influenced by wellbore flow processes and by wellbore/caprock heat transfer. We investigate competing effects that control development of a thermosiphon, which enables production of geothermal electricity without the need for a continuously operating external pump. [ABSTRACT FROM AUTHOR]

Abstract: A major global research and development effort is underway to commercialize carbon capture and storage (CCS) as a method to mitigate climate change. Recent studies have shown the potential to couple CCS with geothermal energy extraction using supercritical CO2 (ScCO2) as the working fluid. In a geothermal reservoir, the working fluid produces electricity as a byproduct of the CCS process by mining heat out of a reservoir as it is circulated between injector and producer wells. While ScCO2 has lower heat capacity than water, its lower viscosity more than compensates by providing for greater fluid mobility. Furthermore, CO2 exhibits high expansivity and compressibility, which can both help reduce parasitic loads in fluid cycling. Given the high capital costs for developing the deep well infrastructure for geologic storage of CO2, the potential to simultaneously produce geothermal energy is an attractive method to offset some of the costs and added energy requirements for separating and transporting the waste CO2 stream. We present here the preliminary design and reservoir engineering associated with the development of direct-fired turbomachinery for pilot-scale deployment at the SECARB Cranfield Phase III CO2 Storage Project, in Cranfield, Mississippi, U.S.A. The pilot-scale deployment leverages the prior investment in the Cranfield Phase III research site, providing the first ever opportunity to acquire combined CO2 storage/geothermal energy extraction data necessary to address the uncertainties involved in this novel technique. At the SECARB Cranfield Site, our target reservoir, the Tuscaloosa Formation, lies at a depth of 3.0km, and an initial temperature of 127°C. A CO2 injector well and two existing observation wells are ideally suited for establishing a CO2 thermosiphon and monitoring the thermal and pressure evolution of the well-pair on a timescale that can help validate coupled models. It is hoped that this initial demonstration on a pre-commercial scale can accelerate commercialization of combined CCS/geothermal energy extraction by removing uncertainties in system modeling. [Copyright &y& Elsevier]

Abstract: The efficiency and sustainability of CO2 storage in deep saline formations depends on the integrity of the overlying caprocks. Existing oil and gas wells, which penetrate the formations, are potential leakage pathways. In this paper, T2WELL/ECO2N, a coupled wellbore–reservoir flow simulator of carbon dioxide and brine, is employed to analyze the effects of salinity and excess pore pressure (EPP) on brine leakage from an injection reservoir to a shallow fresh aquifer. The effectiveness of the Equivalent Porous Media (EPM) approach, a widely used approximation of wellbore flow in wellbore–reservoir simulations, is also evaluated. A hypothetical model is built to create test cases with EPP of 0.1MPa, 0.5MPa and 1.5MPa under low-, middle-, and high-salinity. The results show that a quasi-steady-state leakage rate will be quickly established if the EPP caused by CO2 injection is higher than the threshold EPP. However, the brine salinity has an important impact on the brine leakage rate including the threshold EPP below which no leakage occurs. The leakage rate decreases with the increase of the salinity whereas the threshold EPP increases with the increase of the salinity. For the same brine salinity, the quasi-steady-state leakage rate increases with the EPP nonlinearly. The leakage rate calculated by the EPM approach is very sensitive to the equivalent permeability of the wellbore, which however, is not an intrinsic parameter of a given wellbore–aquifer system. Although the EPM approach could reproduce the dynamic leakage rate reasonably well with a fitted permeability, it could over- or underestimates the leakage rate by orders in magnitude for the same system depending on whether the true leakage rate itself is smaller or larger than that of the fitting case due to changes in the salinity and/or the EPP through an abandoned well. The dependence of the equivalent permeability on the flow rate makes the EPM approach not to be a viable method for predicting wellbore leakage except for the cases with very small leakage rates. [Copyright &y& Elsevier]

• A single-well push-pull test carried out at the Heletz CO 2 storage site is analyzed. • T2Well/ECO2N simulator is used to model CO 2 /brine geyser-like self-release. • The geyser-like behavior leakage can be justified by reduced relative permeability. • The reduced-mobility of CO 2 in reservoir can be linked to formation of exsolved−CO 2. • A coupled well-reservoir model is needed to study CO 2 leakage processes through well. In order to quantify CO 2 residual trapping in situ , two dedicated single-well push-pull experiments have been carried out at the Heletz, Israel pilot CO 2 injection site. Field data from some parts of these experiments suggests the important effect of the hydrodynamic behavior in the injection-withdrawal well. In the present work a model capturing the CO 2 transport and trapping behavior during Heletz Residual Trapping Experiment I is developed, with a special focus on coupled wellbore-reservoir flow. The simulation is carried out with the numerical simulator T2Well/ECO2N (Pan et al. 2011) which considers the wellbore-reservoir coupling. Of particular interest is to accurately model the period when the well is open to the atmosphere and self-producing CO 2 and water in a geyser-like manner. It is also of interest to identify what conditions are causing the oscillating pressure-temperature behavior and the associated periodic gas-liquid releases, as well as to determine the amount of gas lost from the reservoir during this period. The results suggest that the behavior is due to cyclical CO 2 exsolution from the aqueous phase along with a reduction of mobility of both CO 2 and brine in the near wellbore-reservoir area, the latter being due to a zone of dispersed CO 2 bubbles near the wellbore. This behavior could be successfully captured with a new set of relative permeability functions developed earlier for CO 2 exsolution in laboratory experiments (Zuo et al., 2013). [ABSTRACT FROM AUTHOR]

With the goal of detecting and characterizing faults and fractures in enhanced geothermal systems (EGS), a new technology involving CO 2 push-pull testing, active-source geophysical imaging, and well logging has recently been proposed. This technique takes advantage of (1) the contrasting properties of supercritical CO 2 and water which cause CO 2 to appear distinct from surrounding brine in seismic and other geophysical logging approaches, (2) the non-wetting nature of CO 2 which keeps it localized to the faults and fractures to create contrast potentially sufficient for active seismic and well-logging approaches to image faults and fracture zones at EGS sites. In this study, we evaluate the feasibility of using pressure transient monitoring during CO 2 push-pull tests to complement active seismic and wireline well logging for EGS characterization. For this purpose, we developed a 2D model of a prototypical geothermal site (Desert Peak, NV) that includes a single fault. The fault zone consists of a slip plane, fault gouge, and damage zone, and is bounded by the surrounding matrix of the country rock. Through numerical simulation using iTOUGH2, we found that the pressure transient at the monitoring wells in the fault gouge shows unique traits due to the multiphase flow conditions developed by CO 2 injection, and varies sensitively on the arrival of the CO 2 plume and the degree of CO 2 saturation. A sensitivity analysis shows the pressure transient is most sensitive to the fault gouge permeability, but also depends on multiphase flow parameters and the boundary conditions of the fault. An inversion study reveals that the fault gouge permeability can be best estimated with the pressure transient data, whereas additional CO 2 saturation data do not improve the accuracy of the inversion significantly. [ABSTRACT FROM AUTHOR]

We propose the use of CO 2 in push-pull well tests to improve geophysical identification and characterization of fractures and faults at enhanced geothermal system (EGS) sites. Using TOUGH2/ECO2N, we carried out numerical experiments of push-pull injection-production cycling of CO 2 into idealized vertical fractures and faults to produce pressure-saturation-temperature conditions that can be analyzed for their geophysical response. Our results show that there is a strong difference between injection and production mainly because of CO 2 buoyancy. While the CO 2 -plume grows laterally and upward during injection, not all CO 2 is recovered during the subsequent production phase. Even under the best conditions for recovery, at least 10% of the volume of the pores still remains filled with CO 2 . To improve EGS characterization, comparisons can be made of active seismic methods carried out before and after (time lapse mode) CO 2 injection into the fracture or fault. We find that across the CO 2 saturation range, C 11 (the normal stiffness in the horizontal direction perpendicular to the fracture plane) varies between maximum and minimum values by about 15%. It reaches a maximum at around 6% gas saturation, decreasing exponentially to a minimum at higher saturations. Our results suggest that CO 2 injection can be effectively used to infiltrate fault and fracture zones reaching about optimal saturation values in order to enhance seismic imaging at EGS sites. [ABSTRACT FROM AUTHOR]

Compressed air energy storage (CAES) is one of the leading large-scale energy storage technologies. However, low thermal efficiency and low energy storage density restrict its application. To improve the energy storage density, we propose a two-reservoir compressed CO 2 energy storage system. We present here thermodynamic and parametric analyses of the performance of an idealized two-reservoir CO 2 energy storage system under supercritical and transcritical conditions using a steady-state mathematical model. Results show that the transcritical compressed CO 2 energy storage system has higher round-trip efficiency and exergy efficiency, and larger energy storage density than the supercritical compressed CO 2 energy storage. However, the configuration of supercritical compressed CO 2 energy storage is simpler, and the energy storage densities of the two systems are both higher than that of CAES, which is advantageous in terms of storage volume for a given power rating. [ABSTRACT FROM AUTHOR]

Abstract: The development of enhanced geothermal systems using CO2 (CO2-EGS) is a promising idea for expanding geothermal energy production (especially in areas with scarce water resources) when large supplies of captured anthropogenic CO2 may be available in the future. Implementing this concept relies on replacing the natural geothermal brine in the reservoir with injected CO2 to achieve enhanced energy recovery, and raises the questions of the fate of dissolved salts in the brine as CO2 dries out the system, and how any precipitated salt could affect fluid flow. In this case, a new TOUGH2 equation of state module (ECO2H) was used to simulate CO2 injection in an EGS with a brine system comprised of H2O and NaCl. This so called CO2-EGS reservoir is at a depth of 3.5–4.5km with normal pressure (hydrostatic) and temperature (160–200°C) gradients. A classic “five-well” geometry is assumed in our 706m×706m×1km block, of which only one eighth of the area needs to be modeled due to symmetry. The fractured EGS reservoir was modeled using the multiple interacting continua (MINC) conceptual model with fracture spacing of 10m. Dry CO2 was injected at the bottom of the initially brine-saturated reservoir and hot fluids were produced from the top of the reservoir. Simulations show that the brine contained in the fractures is produced initially, and only a few weeks later, the CO2 plume breaks through at the production well. The two-phase nature of flow at this time causes a reduction in flow rate. Fluid production increases again as the reservoir dries out and the injected CO2 fills the fractures (and more slowly the matrix). As the produced fluid becomes single-phase CO2, energy production is enhanced. For salt mass fractions of the order of 0.01 (salinity of 10,000ppm), total heat produced during the lifetime of the well (about 6 years) is 270% more than that achievable with H2O as the working fluid. This result is probably at the lower end of what had been previously suggested by . Simulation results show that as the brine is driven out of the matrix by capillary pressure, H2O evaporates into the CO2 plume and salt precipitates in the fractures clogging up the flow system. At the highest salt mass fraction modeled here (0.15), enhanced energy production is inhibited by halite precipitation in the fractures. Our simulations suggest that for low-salinity systems, significant clogging occurs close to the production well after less than 10 years, while at high salinities clogging occurs close to the injection well in less than one year. Even though clogging of the reservoir is an apparently inevitable consequence of the drying of the saline geothermal reservoir, the fact that clogging occurs in specific reservoir regions could imply that remediation strategies could be developed to mitigate clogging. [Copyright &y& Elsevier]

To evaluate in-situ CO2 residual trapping for CO2 geological storage, two dedicatedsingle-well push-pull experiments have been done at the Heletz, Israel pilot CO2 injectionsite. The site is well characterized and instrumented for CO2 injection including sophisticatedsampling and monitoring (Niemi et al., 2016). The first residual trapping experiment (RTE I)was carried out in autumn 2016. In this experiment the residually trapped zoneof CO2 was created by first injecting 100 tons of CO2 into the target reservoir,followed by fluid withdrawal - first by self-production, then by active pumping - untilCO2 was deemed to be at residual saturation. In this work, the aim is to develop asimulation model that reproduces the measured pressure and temperature data atthe injection well. Because of the overlap in wellbore and reservoir response timescales during the fluid withdrawal, the numerical simulator T2Well/ECO2N (Panet al., 2011) is used to account for the wellbore-reservoir coupling. Of particularinterest in this work is to accurately model the period after well opening whenthe well is self-producing fluids and to analyze what conditions are causing theobserved oscillating pressure and periodic gas-liquid release. Comparison of numericalsimulations and the measured data suggests that the CO2 phase is trapped in thetarget reservoir and only carbonated brine moves upward during the self-producingperiod. By performing numerical simulations with new sets of relative permeabilitycurves against the measured data, we show that the observed behavior during theself-production could be explained by a zone of dispersed CO2 bubbles near the wellbore.Here, the new sets of relative permeability curves reflected the reduction in relativepermeability in both the CO2 and the brine phase caused by a zone of dispersed gas phase(Zou et al. 2013), which could be formed due to snap-off and exsolution near thewellbore. Keywords: CO2 geological storage, residual trapping, push-pull test, wellbore-reservoircoupling, dispersed CO2 bubbles References: Niemi, A., J. Bensabat, V. Shtivelman, K. Edlmann, P. Gouze, L. Luquot, F. Hingerl, S.M. Benson, P. A. Pezard, K. Rasmusson, T. Liang, F. Fagerlund, M. Gendler, I. Goldberg, A.Tatomir, T. Lange, M. Sauter &#x0026; B. Freifeld (2016) Heletz experimental site overview,characterization and data analysis for CO2 injection and geological storage. InternationalJournal of Greenhouse Gas Control, 48, 3. Pan, L., C. M. Oldenburg, Y.-S. Wu &#x0026; K. Pruess, (2011b) T2Well/ECO2N Version 1.0:Multiphase and Non-isothermal Model for Coupled Wellbore-reservoir Flow of CarbonDioxide and Variable Salinity Water. LBNL-4291E (Ed.). Zuo, L., C. Zhang, R. W. Falta &#x0026; S. M. Benson (2013) Micromodel investigations of CO2exsolution from carbonated water in sedimentary rocks. Advances in Water Resources, 53,188. [ABSTRACT FROM AUTHOR]