The numerous CO2 reservoirs in the Colorado Plateau region of the United States are natural analogues for potential geological CO2 sequestration repositories. To understand better the risk of leakage from reservoirs used for long-term underground CO2 storage, we examine evidence for CO2 migration along two normal faults that cut a reservoir in east-central Utah. CO2-charged springs, geysers, and a hydrocarbon seep are localized along these faults. These include natural springs that have been active for long periods of time, and springs that were induced by recent drilling. The CO2-charged spring waters have deposited travertine mounds and carbonate veins. The faults cut siltstones, shales, and sandstones and the fault rocks are fine-grained, clay-rich gouge, generally thought to be barriers to fluid flow. The geological and geochemical data are consistent with these faults being conduits for CO2 moving to the surface. Consequently, the injection of CO2 into faulted geological reservoirs, including faults with clay gouge, must be carefully designed and monitored to avoid slow seepage or fast rupture to the biosphere.

32 33 Fine-grained sedimentary rocksnamely mudrocks, including their laminated fissile variety -34 shales -make up about two thirds of all sedimentary rocks in the Earth's crust and a quarter of 35 the continental land mass. Organic-rich shales and mudstones are the source rocks and reservoirs 36 for conventional and unconventional hydrocarbon resources. Mudrocks are relied upon as natural 37 barriers for geological carbon storage and nuclear waste disposal. Consideration of mudrock 38 multi-scale physics and multi-scale spatial and temporal behavior is vital to address emergent 39 phenomena in shale formations perturbed by engineering activities. Unique physical 40 characteristics of shales arise as a result of their layered and highly heterogeneous and 41 anisotropic nature, low permeability fabric, compositional complexity, and nano-scale confined 42 chemical environments. Barriers of lexicon among geoscientists and engineers impede the 43 development and use of conceptual models for the coupled thermal-hydraulic-mechanical-44chemical-biological (THMCB) processes in mudrock formations. This manuscript reviews the 45 THMCB process couplings, resulting emergent behavior, and key modeling approaches. We 46 identify future research priorities, in particular fundamental knowledge gaps in understanding the 47 phase behavior under nano-scale confinement, coupled chemo-mechanical effects on fractures, 48 the interplay between physical and chemical processes and their rates, and issues of non-linearity 49 and heterogeneity. We develop recommendations for future research and integrating multi-50 disciplinary conceptual models for the coupled multi-scale multi-physics behavior of mudrocks. 51 Consistent conceptual models across disciplines are essential for predicting emergent processes 52 in the subsurface, such as self-focusing of flow, time-dependent deformation (creep), fracture 53 network development, and wellbore stability. 54 55 56 temporal scale, THCMB 57 58 59 60 61 62 65 66Sedimentary rock containing more than 50 percent (by weight or volume) of particles less than 67 62.5 microns in size are known variously as shale, siltstone, claystone, mudstone, and are 68 cumulatively referred to as mudrocks [1][2][3] . Some workers apply "shale" narrowly to refer to the 69 visibly laminated, fissile variety of this sedimentary rock, but in this paper we apply this term as 70 the overall name for the broad class of fine-grained layered sedimentary rocks, and, where 71 appropriate, use it interchangeably with the term "mudrock" [4] . Shale constitutes around two-72 thirds of the sedimentary record of planet Earth [5, 6] , and a quarter of the continental land mass 73 [7] . In some portions of sedimentary basins, distant from the principal axes of sediment transport, 74 the abundance of mudrocks may approach 90 percent of the local sediment volume [8] . Shales are 75 volumetrically dominant in both marine and terrigenous successions, and host significant 76 portions of the fluid-rock interactions controlling ...

Mudstone pore networks are strong modifi ers of sedimentary basin fl uid dynamics and have a critical role in the distribution of hydrocarbons and containment of injected fl uids. Using core samples from continental and marine mudstones, we investigate properties of pore types and networks from a variety of geologic environments, together with estimates of capillary breakthrough pressures by mercury intrusion porosimetry. Analysis and interpretation of quantitative and qualitative three-dimensional (3D) observations, obtained by dual focused ion beamscanning electron microscopy, suggest seven dominant mudstone pore types distinguished by geometry and connectivity. A dominant planar pore type occurs in all investigated mudstones and generally has high coordination numbers (i.e., number of neighboring connected pores). Connected networks of pores of this type contribute to high mercury capillary pressures due to small pore throats at the junctions of connected pores and likely control most matrix transport in these mudstones . Other pore types are related to authigenic (e.g., replacement or pore-lining precipitation) clay minerals and pyrite nodules; pores in clay packets adjacent to larger, more competent clastic grains; pores in organic phases; and stylolitic and microfracture-related pores. Pores within regions of authigenic clay minerals often form small isolated networks (<3 μm). Pores in stringers of organic phases occur as tubular pores or slit-and/or sheet-like pores. These form short, connected lengths in 3D reconstructions, but appear to form networks no larger than a few microns in size. Sealing effi ciency of the studied mudstones increases with greater distal depositional environments and greater maximum depth of burial.

This article presents numerical simulations of CO2 storage mechanisms in the Pennsylvanian Upper Morrow sandstone reservoir, locally termed the Morrow B sandstone in the Farnsworth Unit (FWU) of Ochiltree County, Texas. The CO2 storage mechanisms considered in the study under a CO2 enhanced oil recovery (EOR) mode include structural-stratigraphic trapping, CO2 dissolution in formation water and oil, and residual trapping. The reservoir simulation model was constructed on the basis of field geophysical, geological, and engineering data such as three-dimensional surface seismic data, well logs, and fluid analysis. A representative fluid sampled from the reservoir was analyzed and used to tune the equation of state. A thermodynamic minimum miscible pressure was subsequently computed and compared to the experimental outcome. A history-matched model was constructed and used as a baseline to determine the effects of different hypothetical injection strategies (that consider CO2 purchase, gas recycling, and infill drilling), water-alternating-gas (WAG) schemes, and variable salinity on CO2 storage. The simulation results showed that a significant amount of stored CO2 was dissolved in residual oil, contributing to enhanced oil recovery from the tertiary stage of the field operations. Supercritical-phase CO2 mass within the reservoir compared to CO2 dissolved in formation water was found to be dependent on the CO2 injection strategy. The residual trapping contribution was significant when hysteresis was considered. Pressure, volume of reservoir fluid present, caprock integrity, and optimized WAG injection strategies were significant parameters determining the long-term CO2 storage capacity within the FWU. Caprock integrity analyses showed that sealing units have excellent storage capacity with the potential to support column heights of up to 10000 ft. This work shows an improved strategy of maximizing CO2 storage within a depleted oil reservoir. The results from this study show that pressure changes within the reservoir should be continuously monitored to enhance CO2 storage. This study serves as a benchmark for future CO2-EOR projects in the Anadarko basin or geologically similar basins throughout the world.