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TOUGH + Millstone has been developed for the analysis of coupled flow, thermal and geomechanical processes associated with the formation and/or dissociation of CH4-hydrates in geological media. It is composed of two constituent codes: (a) a significantly enhanced version of the TOUGH + HYDRATE simulator, V2.0, that accounts for all known flow, physical, thermodynamic and chemical processes associated with the behavior of hydrate-bearing systems undergoing changes and includes the most recent advances in the description of the system properties, coupled seamlessly with (b) Millstone V1.0, a new code that addresses the conceptual, computational and mathematical shortcomings of earlier codes used to describe the geomechanical response of these systems. The capabilities of TOUGH + Millstone are demonstrated in the simulation and analysis of the system flow, thermal and geomechanical behavior during gas production from a realistic complex offshore hydrate deposit. In the first paper of this series, we discuss the physics underlying the T + H hydrate simulator, the constitutive relationships describing the physical, chemical (equilibrium and kinetic) and thermal processes, the states of the CH 4 + H 2 O system and the sources of critically important data, as well as the mathematical approaches used for the development of the of mass and energy balance equations and their solution. Additionally, we provide verification examples of the hydrate code against numerical results from the simulation of laboratory and field experiments.

The TOUGH+Millstone simulator has been developed for the analysis of coupled flow, thermal and geomechanical processes associated with the formation and/or dissociation of CH 4 hydrates in geological media. It is composed of two constituent codes: (a) a significantly enhanced version of the TOUGH+HYDRATE simulator, v2.0, that accounts for all known flow, physical, thermodynamic and chemical processes associated with the behavior of hydrate-bearing systems undergoing changes and includes the most recent advances in the description of the system properties, coupled seamlessly with (b) Millstone v1.0, a new code that addresses the conceptual, computational and mathematical shortcomings of earlier codes used to describe the geomechanical response of these systems. The capabilities of the TOUGH+Millstone code are demonstrated in the simulation and analysis of the system flow, thermal and geomechanical behavior during gas production from a realistic complex offshore hydrate deposit. In the second part of this series, we describe the Millstone geomechanical simulator. The hydrate-dependent, rate-based poromechanical formulation is presented and solved using a finite element discretization. A novel multimesh coupling scheme is introduced, wherein interpolators are automatically built to transfer data between the finite difference discretization of TOUGH+ and the finite element discretization of Millstone. We provide verification examples against analytic solutions for poroelasticity and a simplified demonstration problem for mechanically induced phase change in a hydrate sediment.

The TOUGH+Millstone simulator has been developed for the analysis of coupled flow, thermal and geomechanical processes associated with the formation and/or dissociation of CH 4 -hydrates in geological media. It is composed of two constituent codes: (a) a significantly enhanced version of the TOUGH+Hydrate simulator, v2.0, that accounts for all known flow, physical, thermodynamic and chemical processes associated with the evolution of hydrate-bearing systems and includes the most recent physical properties relationships, coupled seamlessly with (b) Millstone v1.0, a new code that addresses the conceptual, computational and mathematical shortcomings of earlier codes used to describe the geomechanical response of these systems. The capabilities of the TOUGH+Millstone code are demonstrated in the simulation and analysis of the system flow, thermal, and geomechanical behavior during gas production from a realistic complex offshore hydrate deposit. In the third paper of this series, we apply the simulators described in parts 1 and 2 to a problem of gas production from a complex, multilayered system of hydrate-bearing sediments in an oceanic environment. We perform flow simulations of constant-pressure production via a vertical well and compare those results to a coupled flow-geomechanical simulation of the same process. The results demonstrate the importance of fully coupled geomechanics when modeling the evolution of reservoir properties during production.

Production simulation from fractured shale reservoirs is often performed by simplifying the hydraulic fractures as rectangular planes with homogeneous aperture. This study investigates the effects of heterogeneous fracture aperture and proppant distribution in realistic, non-rectangular fractures on the multi-phase production from shales. The heterogeneous hydraulic fractures are generated with the GEOS multiphysics simulator under realistic 3D stress field. These fractures are embedded into the TOUGH+ multi-phase flow simulator for production simulation. The results emphasize the importance of flow barriers within the hydraulic fractures, due both to low-aperture regions caused by the stress-shadow effect and the settling of proppant. The production rate is particularly sensitive to aperture heterogeneity if the flow barriers are close to the wellbore such that a great portion of fracture volume is isolated from the well. A stage-to-stage comparison reveals that production from different stages could vary significantly because the local stress field leads to different fracture area and aperture. The use of proppant prevents fracture closure, but if the propped regions are far from the well, they do not enhance production because flow barriers between these regions and the well act as bottlenecks. The present study highlights the importance of incorporating aperture heterogeneity into production simulation, provides insights on the relationship between flow barriers, proppant concentration, and well production, and proposes a practical method to mitigate numerical difficulties when modeling heterogeneous fractures.

We use the TOUGH+HYDRATE code to assess the production potential of some particularly challenging hydrate deposits, i.e., deposits that are characterized by any combination of the following factors: absence of confining boundaries, high thermodynamic stability, low temperatures, low formation permeability. Using high-resolution grids, we show that a new horizontal well design using thermal stimulation coupled with mild depressurization yields production rates that appear modest and insufficient for commercially viable production levels. The use of parallel horizontal wells (with the lower one providing thermal stimulation through heat addition, direct injection or circulation of warm water, and the upper one producing under a mild depressurization regime) offers tantalizing possibilities, and has the potential of allowing commercial production from a very large number of hydrate deposits that are not currently considered as production candidates if the problem of the corresponding large water production can be solved.

The quantity of hydrocarbon gases trapped in natural hydrate accumulations is enormous, leading to a significant interest in the evaluation of their potential as an energy source. It has been shown that large volumes of gas can be readily produced at high rates for long times from some types of methane hydrate accumulations by means of depressurization-induced dissociation, and using conventional horizontal or vertical well configurations. However, these resources are currently assessed using simplified or reduced-scale 3D or 2D production simulations. In this study, we use the massively parallel TOUGH+HYDRATE code (pT+H) to assess the production potential of a large, deep ocean hydrate reservoir and develop strategies for effective production. The simulations model a full 3D system of over 38 km 2 extent, examining the productivity of vertical and horizontal wells, single or multiple wells, and explore variations in reservoir properties. Systems of up to 2.5 M gridblocks, running on thousands of supercomputing nodes, are required to simulate such large systems at the highest level of detail. The simulations reveal the challenges inherent in producing from deep, relatively cold systems with extensive water-bearing channels and connectivity to large aquifers, mainly difficulty of achieving depressurization and the problem of enormous water production. Also highlighted are new frontiers in large-scale reservoir simulation of coupled flow, transport, thermodynamics, and phase behavior, including the construction of large meshes and the computational scaling of larger systems.

Vast quantities of methane are trapped in oceanic hydrate deposits, and there is concern that a rise in the ocean temperature will induce dissociation of these hydrate accumulations, potentially releasing large amounts of methane into the atmosphere. The recent discovery of active methane gas venting along the landward limit of the gas hydrate stability zone (GHSZ) on the shallow continental slope west of Spitsbergen could be an indication of this process, if the source of the methane can be confidently attributed to dissociating hydrates. In the first large‐scale simulation study of its kind, we simulate shallow hydrate dissociation in conditions representative of the West Spitsbergen margin to test the hypothesis that the observed gas release originated from hydrates. The simulation results are consistent with this hypothesis, and are in remarkable agreement with the recently published observations. They show that shallow, low‐saturation hydrate deposits, when subjected to temperature increases at the seafloor, can release significant quantities of methane, and that the releases will be localized near the landward limit of the top of the GHSZ. These results indicate the possibility that hydrate dissociation and methane release may be both a consequence and a cause of climate change.

Vast quantities of methane are trapped in oceanic hydrate deposits, and there is concern that a rise in the ocean temperature will induce dissociation of these hydrate accumulations, potentially releasing large amounts of carbon into the atmosphere. Because methane is a powerful greenhouse gas, such a release could have dramatic climatic consequences. The recent discovery of active methane gas venting along the landward limit of the gas hydrate stability zone (GHSZ) on the shallow continental slope (150 m to 400 m) west of Svalbard suggests that this process may already have begun, but the source of the methane has not yet been determined. This study performs 2‐D simulations of hydrate dissociation in conditions representative of the Arctic Ocean margin to assess whether such hydrates could contribute to the observed gas release. The results show that shallow, low‐saturation hydrate deposits, if subjected to recently observed or future predicted temperature changes at the seafloor, can release quantities of methane at magnitudes similar to what has been observed, and that the releases will be localized near the landward limit of the GHSZ. Both gradual and rapid warming is simulated, along with a parametric sensitivity analysis, and localized gas release is observed for most of the cases. These results resemble the recently published observations and strongly suggest that hydrate dissociation and methane release as a result of climate change may be a real phenomenon, that it could occur on decadal timescales, and that it already may be occurring. Key Points Seafloor warming can dissociate hydrates and cause methane release Shallow hydrates alone may contribute to significant release Methane release may occur under a wide range of sediment conditions

Geologic carbon sequestration (GCS) is the process of injecting CO 2 into deep subsurface rock formations such as into depleted oil and gas reservoirs or deep saline aquifers for long‐term storage. Over the last decade, a number of field, laboratory, and modeling studies have been undertaken to assess the feasibility and safety of CO 2 geologic storage, including their potential impact on shallow groundwater aquifers overlying target CO 2 storage reservoirs. This chapter provides a review of the literature on the primary concerns to groundwater quality from GCS and practices to mitigate or avoid impacts to water. The review covers possible pathways by which CO 2 can leak from GCS reservoirs, the potential hazards associated with leakage of dissolved CO 2 into shallow groundwater, state‐of‐the‐art monitoring strategies for CO 2 leakage, and an overview of guidelines and regulations in the United States that seek to minimize potential impact. Several knowledge gaps and science needs still remain for understanding the impacts of large‐scale deployment of GCS to groundwater including likely leakage scenarios, pathways and associated fluxes, key characteristics of aquifers that could make them vulnerable to degradation upon CO 2 intrusion, and the development of reduced‐order models and effective monitoring strategies for understanding and designing appropriate responses to CO 2 leakage.

This chapter illustrates the nonintrusive analysis of parametric uncertainty. Quantification of spectral modes adds a new level of understanding, identifying the significance of individual uncertain parameters and determining where within the evolution of the system each parameter has the most influence. In this study, a technique of uncertainty quantification through spectral projection methods is used to examine the propagation of parametric uncertainty through 0D combustion chemistry and 1D premixed flame, with a focus on higher-order information and the correlations among parameters. Compared to conventional Monte Carlo analysis, this method quantifies the extent, dependence, and propagation of uncertainty through the model system and allows correlation of uncertainties in specific parameters to the resulting total uncertainty in product concentrations and flame structure. Analysis of 0D and 1D hydrogen-oxygen combustion demonstrates that known empirical uncertainties in model parameters may result in large uncertainties in the final output, and nonlinearities in system response behavior make the order of the analysis an important consideration. Furthermore, this analysis is readily extendable to multiple dimensions and greater numbers of uncertain parameters, while preserving the integrity of the realization engine through the nonintrusive operation of the method.