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It is crucial to ensure the safety and integrity of underground gas storage (UGS) infrastructure for energy reliability in California, and many other places around the world. To address the risk management need in UGS industry, we take advantage of recent advances in downhole fiber optic monitoring and coupled well-reservoir simulation to provide unprecedented understanding of gas flow in wells at UGS sites. We have combined advanced monitoring and simulation of UGS operations into a decision-support system called the Integrated Risk Management and Decision Support System (IRMDSS). The IRMDSS framework includes three components: (i) mechanistic models, (ii) continuous and frequent monitoring data, and (iii) a supervisory interface for performing analyses using the models and monitoring data. The goal of the IRMDSS is to equip UGS operators with real-time monitoring data and simulation tools that can alert them to potential failures, detect early leakage, and support mitigation decision-making to prevent otherwise larger failures. We demonstrate an application of the IRMDSS by analyzing the temperature and pressure response to a hypothetical leak. Through a review of distributed temperature sensing (DTS) data collected at an operating UGS facility we show that DTS can uniquely and precisely identify the depth of the gas-water-contact in the well annulus, and that DTS can provide an early warning signal of upward gas flow as would occur in a well blowout scenario. When combined with modeling analysis, a rough leak rate can be roughly estimated to understand the severity of the leakage conditions and to support the mitigation decision needed.

This paper presents and analyzes a novel fossil-fuel–free trans-critical energy storage system that uses CO2 as the working fluid in a closed loop shuttled between two saline aquifers or caverns at different depths: one a low-pressure reservoir and the other a high-pressure reservoir. Thermal energy storage and a heat pump are adopted to eliminate the need for external natural gas for heating the CO2 entering the energy recovery turbines. We carefully analyze the energy storage and recovery processes to reveal the actual efficiency of the system. We also highlight thermodynamic and sensitivity analyses of the performance of this fossil-fuel–free trans-critical energy storage system based on a steady-state mathematical method. It is found that the fossil-fuel–free trans-critical CO2 energy storage system has good comprehensive thermodynamic performance. The exergy efficiency, round-trip efficiency, and energy storage efficiency are 67.89%, 66%, and 58.41%, and the energy generated of per unit storage volume is 2.12 kW·h/m3, and the main contribution to exergy destruction is the turbine reheater, from which we can quantify how performance can be improved. Moreover, with a higher energy storage and recovery pressure and lower pressure in the low-pressure reservoir, this novel system shows promising performance.

Growing interest in offshore geologic carbon sequestration (GCS) motivates evaluation of the consequences of subsea CO2 well blowouts. We have simulated a hypothetical major CO2 well blowout in shallow water of the Texas Gulf Coast. We use a coupled reservoir-well model (T2Well) to simulate the subsea blowout flow rate for input to an integral model (TAMOC) for modeling CO2 transport in the water column. Bubble sizes are estimated for the blowout scenario for input to TAMOC. Results suggest that a major CO2 blowout in ≥50 m of water will be almost entirely attenuated by the water column due to CO2 dissolution into seawater during upward rise. In contrast, the same blowout in 10 m of water will hardly be attenuated at all. Results also show that the size of the orifice of the leak strongly controls the CO2 blowout rate. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

Permeability estimation from pressure-pulse decay method is complicated by two facts: (1) the decay curve often deviates from the single-exponential behavior in the early time period and (2) possible existence of gas adsorption. Both the two factors cause significant permeability error in most of pressure-pulse decay methods. In this paper, we first present a thorough analysis of pressure-pulse propagation process to reveal the mechanism behind the early time and later time behaviors of pressure decay curve. Inspired by the findings from these analyses, a new scaled pressure is proposed which can: (1) be easily used to distinguish the early time and later time data and (2) make the decay curves of all cases into a single 1:1 straight line for later time. A new data-proceeding method, which calculates the apparent porosity and permeability using the same set of measured data, is then developed. The new method could not only remove the effects of the adsorption on the permeability estimation, but also identify the apparent porosity as well as proper adsorption model and parameters. The proposed method is verified by comparing with true values and calculated values through numerical simulations that cover variations in typical rock properties (porosity, permeability, slippage, and adsorption) and the experiment configurations. It is found that the new method is accurate and reliable for all test cases, whereas the Brace’s and Cui’s approaches may cause permeability error in some cases. Finally, the new method has been successfully applied to real data measured in pressure-pulse decay experiments involving different types of rocks and gases.

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.

Geothermal heat mining simulations using supercritical CO2 (sCO2) were performed in this research. Working fluid selection criteria for power generation using sCO2 from a geothermal reservoir are then presented for subcritical, superheated and supercritical organic Rankine cycles (ORCs). Meanwhile, method of working fluid classification for ORC is proposed. To get the most feasible ORC design, this study introduces the concept of “turning point” for isentropic and dry working fluids, as well as minimum turbine inlet temperature for wet working fluids. A thermodynamic model was developed with capabilities to obtain the optimal working fluid mass flow rate, evaporation temperature, superheated temperature, and supercritical pressure, to evaluate the thermal performance of the three ORC approaches using hot produced sCO2. With this model, thirty potential working fluids with critical temperatures in the range from 50 to 225 °C were screened for utilizing hot produced sCO2 considering physical properties, environmental and safety impacts, and thermodynamic performances. Finally, the thermodynamic results were compared for all possible working fluids.

The concept of injecting supercritical CO2 (sCO2) into a geothermal reservoir was computationally investigated to assess its performance in terms of the benefit of using CO2 captured from fossil power plants for geothermal heat mining. A coupled wellbore-reservoir system was simulated considering the flow of pure sCO2 in an injection well, the interaction of sCO2 and water in a permeable reservoir, and the flow of the two-phase mixture of sCO2 and water in a production well. Results of simulations indicate that this CO2 application is capable of providing a good source of renewable energy. It was found that for a reservoir with a 0.08 km3 volume, about 8-9 MWth could be extracted in a steady state fashion for a 30-year lifetime operation. This is approximately equivalent to 100 MWth/km3. A sensitivity analysis provided information on the impact of certain parameters on the performance of the integrated system. The injection flowrate, the distance between the production and injection wellbores and the penetrating depth of the production wellbore into the reservoir have a first order impact on the pressure management of the reservoir. Additionally, CO2 injection temperature has a large effect on the thermosiphon characteristics of the system.

With the goal of detecting and characterizing faults and fractures in enhanced geothermal systems (EGS), a new technology involving CO2 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 CO2 and water which cause CO2 to appear distinct from surrounding brine in seismic and other geophysical logging approaches, (2) the non-wetting nature of CO2 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 CO2 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 CO2 injection, and varies sensitively on the arrival of the CO2 plume and the degree of CO2 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 CO2 saturation data do not improve the accuracy of the inversion significantly.

In the geothermal sector, being able to simulate production tests by combining surface and downhole measurements can be extremely useful, improving data interpretation and reducing the impact of unavailable field data. This is possible with T2Well, a coupled wellbore-reservoir simulator. We plugged the EWASG equation of state for high enthalpy geothermal reservoirs into T2Well and extended the function to analytically compute the heat exchange between wellbore and formation at the short times. Changes to the analytical heat exchange function were verified by comparison with wellbore-formation heat exchange numerically simulated. T2Well-EWASG was validated by reproducing the flowing pressure and temperature logs taken from literature, and by using the software for the interpretation of a short production test. Simulation results indicate that T2Well-EWASG can be effectively used to improve the interpretation of production tests performed in geothermal wells.

Industrial-scale geological storage of CO2 in saline aquifers may cause CO2 and brine leakage from abandoned wells into shallow fresh aquifers. This leakage problem involves the flow dynamics in both the wellbore and the storage reservoir. T2Well/ECO2N, a coupled wellbore-reservoir flow simulator, was used to analyze CO2 and brine leakage under different conditions with a hypothetical simulation model in water-CO2-brine systems. Parametric studies on CO2 and brine leakage, including the salinity, excess pore pressure (EPP) and initially dissolved CO2 mass fraction, are conducted to understand the mechanism of CO2 migration. The results show that brine leakage rates increase proportionally with EPP and inversely with the salinity when EPP varies from 0.5 to 1.5 MPa; however, there is no CO2 leakage into the shallow freshwater aquifer if EPP is less than 0.5 MPa. The dissolved CO2 mass fraction shows an important influence on the CO2 plume, as part of the dissolved CO2 becomes a free phase. Scenario simulation shows that the gas lifting effect will significantly increase the brine leakage rate into the shallow freshwater aquifer under the scenario of 3.89% dissolved CO2 mass fraction. The equivalent porous media (EPM) approach used to model the wellbore flow has been evaluated and results show that the EPM approach could either under- or over-estimate brine leakage rates under most scenarios. The discrepancies become more significant if a free CO2 phase evolves. Therefore, a model that can correctly describe the complex flow dynamics in the wellbore is necessary for investigating the leakage problems.

A blowout of the Sesnon Standard-25 well (SS-25; API 03700776) at the Aliso Canyon Underground Gas Storage Facility, first observed on October 23, 2015, eventually resulted in emission of nearly 100,000 tonnes of natural gas (mostly methane) to the atmosphere. Several thousand people were displaced from their homes as the blowout spanned 111 days. Seven attempts to gain pressure control and stop the gas flow by injection of heavy kill fluids through the wellhead failed, a process referred to as a “top kill.” Introduction of drilling mud when a relief well milled through the casing of SS-25 at a depth of ∼8 400 ft (“bottom kill”) succeeded in halting the gas flow on February 11, 2016. We carried out coupled well-reservoir numerical modeling using T2Well to assess why the top kills failed to control the blowout. T2Well couples a reservoir simulation in which porous media flow is described using Darcy's law with a discretized wellbore in which the Navier-Stokes momentum equation implemented via a drift-flux model (Shi et al., 2005) is used to describe multi-phase fluid transport to allow detailed process modeling of well blowouts and kill attempts. Modeling reveals the critical importance of well geometry in controlling flow dynamics and the corresponding success or failure of the kill attempts. Geometry plays a role in controlling where fluids can flow, e.g., when gas flow prevents liquid flow from entering the tubing from the annulus, but geometry also provides the opportunity for dead end regions to accumulate stagnant gas and liquid that can also affect kill attempts. Simulations show that follow-up fluid injections after the main kill attempts likely would have been effective to ensure that gas leakage remains stopped. T2Well is capable of simulating well kills and understanding the mechanisms behind well control failures and successes.

CO2 has been proposed as a working fluid for geothermal energy production because of its ability to establish a self-sustaining CO2 thermosiphon, taking advantage of the strong temperature dependence of CO2 density. To test the concept of CO2 heat extraction, in January 2015 a CO2 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 CO2 flood since December 2009 as part of a U.S. Department of Energy demonstration of CO2 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 CO2-H2O-CH4 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 CO2-based geothermal reservoir exploitation.

Compressed air energy storage (CAES) is a grid-scale energy storage technology for intermittent energy, as proven by the decades-long successful operation of two existing compressed air energy storage in cavern (CAESC) power plants. Because of the limited availability of salt domes appropriate for CAESC, the more widely available aquifers (compressed air energy storage in aquifers, CAESA) have recently attracted considerable attention as candidates for CAES. An ideal aquifer for CAESA is highly permeable around the well to facilitate easy injection and withdrawal of air, but the high-permeability region is surrounded by low-permeability zones to minimize the loss of injected air and decrease in energy efficiency. However, such ideal geological structures are not always available in nature. Therefore, the potential of creating man-made low-permeability barrier in high-permeability aquifers is very interesting. In this paper, we investigate the feasibility of man-made low-permeability barriers in high-permeability aquifers using the numerical simulator TOUGH2/Gel to calculate the three-component flow (including a miscible gelling liquid). The simulation results show that an expected low-permeability barrier can be created by injecting grout with certain properties, and the altered aquifer performs well for CAESA. Additional sensitivity studies are also performed to reveal the effects of the various factors on the success of the low-permeability barrier creation, including the critical solidification concentration, the scale factor of the time dependence of the grout viscosity, the relative density of the grout, and the volume of the follow-up water injection. The results indicate that, in a horizontal aquifer, low critical solidification concentrations, and small scale factors are generally preferred and the density of grout should be close to that of the in situ water. For the given volume of the injected grout, there is an optimal follow-up water injection that will create the largest storage space without damaging the barrier. These results may help to extend the candidate sites for CAESA and the prospect of large scale energy storage.

Different from conventional compressed air energy storage (CAES) systems, the advanced adiabatic compressed air energy storage (AA-CAES) system can store the compression heat which can be used to reheat air during the electricity generation stage. Thus, AA-CAES system can achieve a higher energy storage efficiency. Similar to the AA-CAES system, a compressed air energy storage in aquifers (CAESA) system, which is integrated with an aquifer thermal energy storage (ATES) could possibly achieve the same objective. In order to investigate the impact of ATES on the performance of CAESA, different injection air temperature schemes are designed and analyzed by using numerical simulations. Key parameters relative to energy recovery efficiencies of the different injection schemes, such as pressure distribution and temperature variation within the aquifers as well as energy flow rate in the injection well, are also investigated in this study. The simulations show that, although different injection schemes have a similar overall energy recovery efficiency (∼97%) as well as a thermal energy recovery efficiency (∼79.2%), the higher injection air temperature has a higher energy storage capability. Our results show the total energy storage for the injection air temperature at 80 °C is about 10% greater than the base model scheme at 40 °C. Sensitivity analysis reveal that permeability of the reservoir boundary could have significant impact on the system performance. However, other hydrodynamic and thermodynamic properties, such as the storage reservoir permeability, thermal conductivity, rock grain specific heat and rock grain density, have little impact on storage capability and the energy flow rate. Overall, our study suggests that the combination of ATES and CAESA can help keep the high efficiency of energy storage so as to make CAESA system more efficiency.

We propose the use of CO2 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 CO2 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 CO2 buoyancy. While the CO2-plume grows laterally and upward during injection, not all CO2 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 CO2. To improve EGS characterization, comparisons can be made of active seismic methods carried out before and after (time lapse mode) CO2 injection into the fracture or fault. We find that across the CO2 saturation range, C11 (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 CO2 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.

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.

Understanding fluids migration and leakage risk along the fault zone is necessary to guarantee the safety of CO2 geological storage. The validity of Darcy's law gets challenged in dealing with the flow in open fractures since the occurring of turbulence flow. In this study, we develop a 2D model with usage of T2Well, an integrated wellbore-reservoir simulator, to investigate the leakage problem along open fractures which are embedded in a fault zone from the deep injection reservoir to shallow aquifers. The results record a positive feedback of gas expansion and pressure response in fracture, which causes a quick downward propagation of highly gas saturated zone from the top of fracture and an easy gas breakthrough in the shallower aquifers. The decreasing of aperture size of fracture significantly enhances the leakage rates in fracture, but with less influences as aperture increases. In comparison, the Equivalent PorousMedia models show a good approximation with the momentum model of large apertures but poor for the small one. Nevertheless, the differences are small in terms of final CO2 distribution among various aquifers, suggesting that Darcy's law may be still "effective" in solving flow problem along fractures in a constant injection system at a large time scale.

CAESA (compressed air energy storage in aquifers) attracts more and more attention as the increase need of large scale energy storage. The compassion of CAESA and CAESC (compressed air energy storage in caverns) can help on understanding the performance of CAESA, since there is no on running CAESA project. In order to investigate the detail thermodynamic process, integrated wellbore-reservoir (cavern or aquifer) simulations of CAES (compressed air energy storage) are carried out based on parameters of the Huntorf CAES plant. Reasonable matches between monitored data and simulated results are obtained for the Huntorf cavern systems in the wellbore and cavern regions. In this study, the hydrodynamic and thermodynamic behaviors of CAES in cavern and aquifer systems are investigated, such as pressure and temperature distribution and variation in both the wellbore and cavern regions of the CAES systems. Performances of CAESA are investigated with numerical models and compared with the performances of CAESC. The comparisons of CAESC and CAESA indicate that the pressure variation in CAESA shows a wider variation range than that in CAESC, while the temperature shows a smooth variation due to the large grain specific heat of the grains in the porous media. The simulation results confirm that the CAES can be achieved in aquifers, and further that the performance of energy storage in aquifers can be similar to or better than CAESC, if the aquifers have appropriate reservoir properties, which means the gas bubble can be well developed in an aquifer with such properties and the aquifer should have closed or semi-closed boundaries. The impacts of gas-bubble volume, formation permeability, and aquifer boundary permeability on storage efficiency are investigated and the simulation results indicate that the increase of gas bubble volume and permeability can improve the efficiency, but the effect is not significant. The gas bubble boundary permeability has a small effect on the energy efficiency of the sustainable daily cycle but can significantly affect total sustainable cycle times. The analysis of thermodynamic behaviors in CAESA suggests that more attention should be paid to the heat storage, reservoir properties and two-phase flow processes.

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 CO2 energy storage system. We present here thermodynamic and parametric analyses of the performance of an idealized two-reservoir CO2 energy storage system under supercritical and transcritical conditions using a steady-state mathematical model. Results show that the transcritical compressed CO2 energy storage system has higher round-trip efficiency and exergy efficiency, and larger energy storage density than the supercritical compressed CO2 energy storage. However, the configuration of supercritical compressed CO2 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.

Introduction MotivationThe 2015-2016 Aliso Canyon/Porter Ranch natural gas well blowout emitted approximately 100,000 tonnes of natural gas (mostly methane, CH4) over four months. The blowout impacted thousands of nearby residents, who were displaced from their homes. The high visibility of the event has led to increased scrutiny of the safety of natural gas storage at the Aliso Canyon facility, as well as broader concern for natural gas storage integrity throughout the country. Federal Review of Well IntegrityIn April of 2016, the U.S. Department of Energy (DOE), in conjunction with the U.S. Department of Transportation (DOT) through the Pipeline and Hazardous Materials Safety Administration (PHMSA), announced the formation of a new Interagency Task Force on Natural Gas Storage Safety. The Task Force enlisted a group of scientists and engineers at the DOE National Laboratories to review the state of well integrity in natural gas storage in the U.S. The overarching objective of the review is to gather, analyze, catalogue, and disseminate information and findings that can lead to improved natural gas storage safety and security and thus reduce the risk of future events. The “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016’’ or the ‘‘PIPES Act of 2016,’’which was signed into law on June 22, 2016, created an Aliso Canyon Natural Gas Leak Task Force led by the Secretary of Energy and consisting of representatives from the DOT, Environmental Protection Agency (EPA), Department of Health and Human Services, Federal Energy Regulatory Commission (FERC), Department of Commerce and the Department of Interior. The Task Force was asked to perform an analysis of the Aliso Canyon event and make recommendations on preventing similar incidents in the future. The PIPES Act also required that DOT/PHMSA promulgate minimum safety standards for underground storage that would take effect within two years. Background on the DOE National Laboratories Well Integrity Work GroupOne of the primary areas that the Task Force is studying is integrity of natural gas wells at storage facilities. The DOE Office of Fossil Energy (FE) took the lead in this area and asked scientists and engineers from the National Energy Technology Laboratory (NETL), Lawrence Livermore National Laboratory (LLNL), Sandia National Laboratories (SNL), and Lawrence Berkeley National Laboratory (LBNL)) to form a Work Group to address this area. This Work Group is an expansion of the original “Lab Team” comprising scientists and engineers from SNL, LLNL, and LBNL which was formed to support the State of California’s response to the Aliso Canyon incident and operated under the Governor of California’s Aliso Canyon Emergency Order (1/6/2016). The Lab Team played a key role in advising the State of California’s Department of Conservation (DOC) in its oversight of SoCalGas during and after the incident.

Potential CO2 leakage through existing open wellbores is one of the most significant hazards that need to be addressed in geologic carbon sequestration (GCS) projects. In the framework of the National Risk Assessment Partnership (NRAP) which requires fast computations for uncertainty analysis, rigorous simulation of the coupled wellbore-reservoir system is not practical. We have developed a 7,200-point look-up table reduced-order model (ROM) for estimating the potential leakage rate up open wellbores in response to CO2 injection nearby. The ROM is based on coupled simulations using T2Well/ECO2H which was run repeatedly for representative conditions relevant to NRAP to create a look-up table response-surface ROM. The ROM applies to a wellbore that fully penetrates a 20-m thick reservoir that is used for CO2 storage. The radially symmetric reservoir is assumed to have initially uniform pressure, temperature, gas saturation, and brine salinity, and it is assumed these conditions are held constant at the far-field boundary (100 m away from the wellbore). In such a system, the leakage can quickly reach quasi-steady state. The ROM table can be used to estimate both the free-phase CO2 and brine leakage rates through an open well as a function of wellbore and reservoir conditions. Results show that injection-induced pressure and reservoir gas saturation play important roles in controlling leakage. Caution must be used in the application of this ROM because well leakage is formally transient and the ROM lookup table was populated using quasi-steady simulation output after 1000 time steps which may correspond to different physical times for the various parameter combinations of the coupled wellbore-reservoir system.

Surface leakage of CO2, and associated potential impacts on health, safety, and the environment (HSE) are considered hazards of geologic carbon sequestration (GCS). There are two challenges associated with impact assessment of CO2 surface dispersion. First, the fact that CO2 is a dense gas makes its dispersion in air a complex process. Rigorous numerical solutions for modeling concentration distributions are relatively time-consuming. Second, impact assessment requires consideration of uncertainty, e.g., quantification of how much uncertainty is propagated through input parameters to model outputs by carrying out large numbers of model runs. In order to assess the potential consequences of surface leakage of CO2, it is useful to have a model that executes very quickly for repeated model calculations (e.g., in Monte Carlo mode) of the atmospheric dispersion of CO2 (concentrations as a function of space and time). In addition, the model should be able to handle multiple surface leakage sources. In this study, we have extended the nomograph approach of Britter and McQuaid (1988) for estimating dense gas plume length from single leakage source to multiple leakage sources. The method is very fast and therefore amenable to general system-level GCS risk assessment including uncertainty quantification within the framework of the National Risk Assessment Partnership (NRAP) Integrated Assessment Model (IAM). The method is conservative in that it assumes the wind could be from any direction, and it handles multiple sources by a simple superposition approach. The method produces results in reasonable agreement with a sophisticated computational fluid dynamics (CFD) code, but runs in a small fraction of the time.

Closed-loop heat exchange for geothermal energy production involves injecting working fluid down a well that extends through the geothermal resource over a significant length to absorb heat by conduction through the well pipe. The well then needs to return to the surface for energy recovery and fluid re-injection to complete the cycle. We have carried out mixed convective-conductive fluid-flow modeling using a wellbore flow model for TOUGH2 called T2Well to investigate the critical factors that control closed-loop geothermal energy recovery. T2Well solves a mixed explicit-implicit set of momentum equations for flow in the pipe with full coupling to the implicit three-dimensional integral finite difference equations for Darcy flow in the porous medium. T2Well has the option of modeling conductive heat flow from the porous medium to the pipe by means of a semi-analytical solution which makes the computation very efficient because the porous medium does not have to be discretized. When the fully three-dimensional option is chosen, the porous medium is discretized and heat flow to the pipe is by conduction and convection, depending on reservoir permeability and other factors. Simulations of the closed-loop system for a variety of parameter values have been carried out to elucidate the heat recovery process. To the extent that convection may occur to aid in heat delivery to the pipe, the permeability of the geothermal reservoir, whether natural or stimulated, is an important property in heat extraction. The injection temperature and flow rate of the working fluid strongly control the ultimate energy recovery. Pipe diameter also plays a strong role in heat extraction, but is correlated with flow rate. Similarly, the choice of working fluid plays an important role, with water showing better heat extraction than CO2 for certain flow rates, while the CO2 has higher pressure at the production wellhead which can aid in surface energy recovery. In general, we find complex interactions between the critical factors that will require advanced computational approaches to fully optimize.

The most accepted conceptual model to explain surface degassing of cold magmatic CO2 in volcanic-geothermal systems involves the presence of a gas reservoir. In this study, numerical simulations using the TOUGH2-ECO2N V2.0 package are performed to get quantitative insights into how cold CO2 soil flux measurements are related to reservoir and fluid properties. Although the modeling is based on flux data measured at a specific geothermal site, the Acoculco caldera (Mexico), some general insights have been gained. Both the CO2 fluxes at the surface and the depth at which CO2 exsolves are highly sensitive to the dissolved CO2 content of the deep fluid. If CO2 mainly exsolves above the reservoir within a fracture zone, the surface CO2 fluxes are not sensitive to the reservoir size but depend on the CO2 dissolved content and the rock permeability. For gas exsolution below the top of the reservoir, surface CO2 fluxes also depend on the gas saturation of the deep fluid as well as the reservoir size. The absence of thermal anomalies at the surface is mainly a consequence of the low enthalpy of CO2. The heat carried by CO2 is efficiently cooled down by heat conduction and to a certain extent by isoenthalpic volume expansion depending on the temperature gradient. Thermal anomalies occur at higher CO2 fluxes (>37,000 g m-2 d-1) when the heat flux of the rising CO2 is not balanced anymore. Finally, specific results are obtained for the Acoculco area (reservoir depth, CO2 dissolved content, and gas saturation state).

An understanding of the hydrologic interactions among atmosphere, land surface, and subsurface is one of the keys to understanding the water cycling system that supports our life system on earth. Properly modeling such interactions is a difficult task because of theinherent coupled processes and complex feedback structures among subsystems. In this paper, we present a model that simulates the landsurface and subsurface hydrologic response to meteorological forcing. This model combines a state of the art landsurface model, the NCAR Community Land Model version 3 (CLM3), with a variably saturatedgroundwater model, the TOUGH2, through an internal interface that includes flux and state variables shared by the two submodels. Specifically, TOUGH2, in its simulation, uses infiltration, evaporation, and rootuptake rates, calculated by CLM3, as source/sink terms? CLM3, in its simulation, uses saturation and capillary pressure profiles, calculated by TOUGH2, as state variables. This new model, CLMT2, preserves the best aspects of both submodels: the state of the art modeling capability of surface energy and hydrologic processes from CLM3 and the more realistic physical process based modeling capability of subsurface hydrologic processes from TOUGH2. The preliminary simulation results show that the coupled model greatly improves the predictions of the water table, evapotranspiration, surface temperature, and moisture in the top 20 cm of soil at a real watershed, as evaluated from 18 years of observed data. The new model is also ready to be coupled with an atmospheric simulation model, representing one of the first models that are capable to simulate hydraulic processes from top of the atmosphere to deep ground.

Characterizing percolation patterns in unsaturated zones has posed a greater challenge to numerical modeling investigations than comparable saturated zone studies, because of the heterogeneous nature of unsaturated media as well as the great number of variables impacting unsaturated zone flow. This paper presents an integrated modeling methodology for quantitatively characterizing percolation patterns in the unsaturated zone of Yucca Mountain, Nevada, a proposed underground repository site for storing high-level radioactive waste. It takes into account the multiple coupled processes of air, water, heat flow and chemical isotopic transport in Yucca Mountain s highly heterogeneous, unsaturated fractured tuffs. The modeling approach integrates a wide variety of moisture, pneumatic, thermal, and isotopic geochemical field data into a comprehensive three-dimensional numerical model for modeling analyses. Modeling results are examined against different types of field-measured data and then used to evaluate different hydrogeological conceptual models and their results of flow patterns in the unsaturated zone. In particular, this integration model provides a much clearer understanding of percolation patterns and flow behavior through the unsaturated zone, both crucial issues in assessing repository performance. The integrated approach for quantifying Yucca Mountain s flow system is also demonstrated to provide a comprehensive modeling tool for characterizing flow and transport processes in complex subsurface systems.

WINGRIDDER V3.0 is a Windows-based software for designing and generating numerical grids for numerical simulators that are based on the "integral finite difference" or the "control volume" numerical scheme (e.g., TOUGH2, Pruess et al., 1996). The user can design and generate grid that properly represents the stratigraphic features, inclined faults, and repository. WINGRIDDER V3.0 is an upgrade from WINGRIDDER V2.0. This revision includes testable requirements as listed in the Requirements Document (RD), 10024-RD-3.0-00, Section 2. With new features, WINGRIDDER V3.0 adds the ability to generate a multiple-interactive-continuum (MINC) grid.

CLMT2 is designed to simulate the land-surface and subsurface hydrologic response to meteorological forcing. This model combines a state-of-the-art land-surface model, the NCAR Community Land Model version 3 (CLM3), with a variably saturated groundwater model, the TOUGH2, through an internal interface that includes flux and state variables shared by the two submodels. Specifically, TOUGH2, in its simulation, uses infiltration, evaporation, and root-uptake rates, calculated by CLM3, as source/sink terms; CLM3, in its simulation, uses saturation and capillary pressure profiles, calculated by TOUGH2, as state variables. This new model, CLMT2, preserves the best aspects of both submodels: the state-of-the-art modeling capability of surface energy and hydrologic processes from CLM3 (including snow, runoff, freezing/melting, evapotranspiration, radiation, and biophysiological processes) and the more realistic physical-process-based modeling capability of subsurface hydrologic processes from TOUGH2 (including heterogeneity, three-dimensional flow, seamless combining of unsaturated and saturated zone, and water table). The preliminary simulation results show that the coupled model greatly improved the predictions of the water table, evapotranspiration, and surface temperature at a real watershed, as evaluated using 18 years of observed data. The new model is also ready to be coupled with an atmospheric simulation model, representing one of the first models that are capable to simulate hydraulic processes from top of the atmosphere to deep-ground.

Modeling fracture-matrix interaction within a complex multiple phase flow system is a key issue for fractured reservoir simulation. Commonly used mathematical models for dealing with such interactions employ a dual- or multiple-continuum concept, in which fractures and matrix are represented as overlapping, different, but interconnected continua, described by parallel sets of conservation equations. The conventional single-point upstream weighting scheme, in which the fracture relative permeability is used to represent the counterpart at the fracture-matrix interface, is the most common scheme by which to estimate flow mobility for fracture-matrix flow terms. However, such a scheme has a serious flaw, which may lead to unphysical solutions or significant numerical errors. To overcome the limitation of the conventional upstream weighting scheme, this paper presents a physically based modeling approach for estimating physically correct relative permeability in calculating multiphase flow between fractures and the matrix, using continuity of capillary pressure at the fracture-matrix interface. The proposed approach has been implemented into two multiphase reservoir simulators and verified using analytical solutions and laboratory experimental data. The new method is demonstrated to be accurate, numerically efficient, and easy to implement in dual- or multiple-continuum models.