A guideline for appropriate application of vertically-integrated modeling approaches for geologic carbon storage modeling

Mathematical modeling is an essential tool for answering questions related to geologic carbon storage (GCS). The choice of modeling approach depends on the type of questions being asked. In this paper we discuss a series of approaches with a hierarchical complexity including vertically-integrated single-phase flow approaches, vertically-integrated multi-phase flow approaches (with and without vertical equilibrium assumption), three-dimensional multi-phase flow approaches, and fully-coupled multi-phase flow approaches that couple flow with geochemistry and/or geomechanics. Three spatial scales are used to categorize the questions to be addressed by modeling: regional scale (encompasses CO2 plume extent and majority of area of pressure impact of one or more injection operations), site scale (includes the CO2 plume extent and some of the area impacted by the pressure increase of a single injection site), and well scale (the immediate vicinity of an injection well). A set of guidelines is developed to help modelers choose the most appropriate modeling approach, and show when simpler modeling approaches may be the better choice. Vertically-integrated single-phase flow models are the most appropriate choice at both the site and regional scales, if the pressure impact outside of the CO2 plume is of interest. Vertically-integrated multi-phase flow models should be chosen at the regional scale, if the locations of CO2 plumes are of interest, and at the site scale if vertical segregation of CO2 and brine is fast or vertical heterogeneity in properties can be presented by distinct, continuous layers. Three-dimensional multi-phase flow models are the appropriate choice at the well and site scales for cases with significant vertical flow components of CO2 and brine. Fully-coupled multi-phase flow models should only be chosen if pore-space alteration through geochemistry or geomechanics feeds back to fluid flow.Carbon Mitigation Initiative at Princeton University; U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL) United States Department of Energy (DOE) [FE009563]; DOE/NETL United States Department of Energy (DOE)24 month embargo; published online: 12 September 2019This item from the UA Faculty Publications collection is made available by the University of Arizona with support from the University of Arizona Libraries. If you have questions, please contact us at [email protected]

Impact of Model Complexity on CO2 plume modeling at Sleipner

AbstractThe goal of geologic carbon sequestration (GCS) is to store carbon dioxide (CO2) in the subsurface for time periods on the order of thousands of years. Mathematical modeling is an important tool to predict the migration of both CO2 and brine to ensure safe and permanent storage. Many modeling approaches with different levels of complexity have been applied to the problem of GCS ranging from simple analytic solutions to fully-coupled three-dimensional reservoir simulators. The choice of modeling approach is often a function of the spatial and temporal scales of the problem, reservoir properties, data availability, available computational resources, and the familiarity of the modeler with a specific modeling approach. In this study we apply a series of models with different levels of model complexity to the 9th layer of the Utsira Formation. The list of modeling approaches includes (from least complex to most complex): numerical vertical-equilibrium model with sharp-interface, numerical vertical-equilibrium model with capillary transition zone, vertically-integrated model with dynamic vertical pressure and saturation reconstruction, and fully- coupled three-dimensional model. The model domain consists of a 3 x 6km section of the 9th layer, as described in the IEAGHG benchmark dataset. The layer thickness varies in space, ranging from 5 to 30 m, while porosity and permeability are close to constant at 0.36 and 1.8 Darcy, respectively. The models are all based on the same input data, and initial and boundary conditions are chosen in a way that ensures the different models are comparable. In addition, a simple box model is used for preliminary simulations. The models are compared based on the predicted CO2 plume footprints and saturation cross-sections. The predicted CO2 plumes are also compared to the actual CO2 plume footprint from seismic surveys to determine the ability of the different models to predict the actual CO2 plume footprint. The results show that vertical-equilibrium models are sufficient to model CO2 migration in the 9th layer of Sleipner, due to the formation's higher permeability and relatively thin capillary transition zone. None of the models used in this study was able to accurately predict the actual plume footprint; this suggests the modeling approaches used here are missing essential physics or that some parameters in the site model (e.g., topography of the caprock) are inaccurate

Vertically integrated dual-continuum models for CO2 injection in fractured geological formations

Various modeling approaches, including fully three-dimensional (3D) models and vertical-equilibrium (VE) models, have been used to study the large-scale storage of carbon dioxide (CO2) in deep saline aquifers. 3D models solve the governing flow equations in three spatial dimensions to simulate migration of CO2 and brine in the geological formation. VE models assume rapid and complete buoyant segregation of the two fluid phases, resulting in vertical pressure equilibrium and allowing closed-form integration of the governing equations in the vertical dimension. This reduction in dimensionality makes VE models computationally much more efficient, but the associated assumptions restrict the applicability of VE models to geological formations with moderate to high permeability. In the present work, we extend the VE models to simulate CO2 storage in fractured deep saline aquifers in the context of dual-continuum modeling, where fractures and rock matrix are treated as porous media continua with different permeability and porosity. The high permeability of fractures makes the VE model appropriate for the fracture domain, thereby leading to a VE dual-continuum model for the dual continua. The transfer of fluid mass between fractures and rock matrix is represented by a mass transfer function connecting the two continua, with a modified transfer function for the VE model based on vertical integration. Comparison of the new model with a 3D dual-continuum model shows that the new model provides comparable numerical results while being much more computationally efficient.Carbon Mitigation Initiative at Princeton University; U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL) [DE-FE0023323]; DOE/NETL12 month embargo; published online: 12 January 2019This item from the UA Faculty Publications collection is made available by the University of Arizona with support from the University of Arizona Libraries. If you have questions, please contact us at [email protected]

Numerical Modeling of Gas and Water Flow in Shale Gas Formations with a Focus on the Fate of Hydraulic Fracturing Fluid

Hydraulic fracturing in shale gas formations involves the injection of large volumes of aqueous fluid deep underground. Only a small proportion of the injected water volume is typically recovered, raising concerns that the remaining water may migrate upward and potentially contaminate groundwater aquifers. We implement a numerical model of two-phase water and gas flow in a shale gas formation to test the hypothesis that the remaining water is imbibed into the shale rock by capillary forces and retained there indefinitely. The model includes the essential physics of the system and uses the simplest justifiable geometrical structure. We apply the model to simulate wells from a specific well pad in the Horn River Basin, British Columbia, where there is sufficient available data to build and test the model. Our simulations match the water and gas production data from the wells remarkably closely and show that all the injected water can be accounted for within the shale system, with most imbibed into the shale rock matrix and retained there for the long term

A Model To Estimate Carbon Dioxide Injectivity and Storage Capacity for Geological Sequestration in Shale Gas Wells

Recent studies suggest the possibility of CO₂ sequestration in depleted shale gas formations, motivated by large storage capacity estimates in these formations. Questions remain regarding the dynamic response and practicality of injection of large amounts of CO₂ into shale gas wells. A two-component (CO₂ and CH₄) model of gas flow in a shale gas formation including adsorption effects provides the basis to investigate the dynamics of CO₂ injection. History-matching of gas production data allows for formation parameter estimation. Application to three shale gas-producing regions shows that CO₂ can only be injected at low rates into individual wells and that individual well capacity is relatively small, despite significant capacity variation between shale plays. The estimated total capacity of an average Marcellus Shale well in Pennsylvania is 0.5 million metric tonnes (Mt) of CO₂, compared with 0.15 Mt in an average Barnett Shale well. Applying the individual well estimates to the total number of existing and permitted planned wells (as of March, 2015) in each play yields a current estimated capacity of 7200–9600 Mt in the Marcellus Shale in Pennsylvania and 2100–3100 Mt in the Barnett Shale

Effective Permeabilities of Abandoned Oil and Gas Wells: Analysis of Data from Pennsylvania

Abandoned oil and gas (AOG) wells can provide pathways for subsurface fluid migration, which can lead to groundwater contamination and gas emissions to the atmosphere. Little is known about the millions of AOG wells in the U.S. and abroad. Recently, we acquired data on methane emissions from 42 plugged and unplugged AOG wells in five different counties across western Pennsylvania. We used historical documents to estimate well depths and used these depths with the emissions data to estimate the wells’ effective permeabilities, which capture the combined effects of all leakage pathways within and around the wellbores. We find effective permeabilities to range from 10^–6 to 10² millidarcies, which are within the range of previous estimates. The effective permeability data presented here provide perspective on older AOG wells and are valuable when considering the leakage potential of AOG wells in a wide range of applications, including geologic storage of carbon dioxide, natural gas storage, and oil and gas development