Multiscale Assessment of Caprock Integrity for Geologic Carbon Storage in the Pennsylvanian Farnsworth Unit, Texas, USA

: The assessment of caprock integrity for underground storage of CO 2 and/or enhanced oil recovery (EOR) systems is a multiscale endeavor. Caprock sealing behavior depends on coupled processes that operate over a broad range of length and time scales including nanoscale heterogeneity in capillary and wettability properties to depositional heterogeneity that is basin wide. Larger-scale sedimentary architecture, fractures, and faults can govern properties of potential “seal - bypass” systems that may be difficult to assess. We present a multiscale investigation of geologic sealing integrity of the caprock system that overlies the Morrow B sandstone reservoir, Farnsworth Unit, Texas, USA. The Morrow B sandstone is the target geologic unit for an on-going combined CO 2 storage – EOR project by the Southwest Regional Partnership on Carbon Sequestration (SWP). Methods and/or data encompass small-to-large scales, including: petrography using electron and optical microscopy; mercury porosimetry; core examinations of sedimentary architecture and fractures; well logs; a suite of geomechanical testing; and a noble gas profile through sealing lithologies into the reservoir, as preserved from fresh core. The combined data set allows a comprehensive examination of sealing quality by scale, by primary features that control sealing behavior, and an assessment of sealing behavior over geologic time. examine sub-core scale capillary heterogeneity of the reservoir and sealing lithologies of the Morrow-B sandstone lithologies, the upper Morrow shale top seal, and the overlying Thirteen Finger Limestone secondary sealing lithologies using mercury porosimetry. We examine evidence for existing fractures and faults that could serve as seal bypass systems under present day stress orientations, as well as examining geomechanical constraints on induced seal bypass features associated with CCUS and EOR activities within the FWU. The lateral continuity of sealing units in the Farnsworth is assessed via subsurface mapping. The large-scale sealing capacity of these lithologies as have occurred over geologic time is assessed using noble gas measurements collected from fresh core. Formation-scale features examining the scale of the entire Farnsworth Unit and regional stratigraphic architecture using seismic methods have been discussed by Rose Coss et al. [3, 4] and Ampomah et al. [5]. We to build confidence that injection and emplacement conditions under CCUS best practices does nothing to threaten the integrity of caprock lithologies. To this end, we examine integrity of the FWU upper Morrow shale and Thirteen Finger Limestone from three perspectives: 1. The ability of the intact lithologies to sustain a capillary seal to CO 2 of a given volume or column height; 2. The nature of existing fractures and faults to serve as seal bypass features, as well as assessing potential for creation of new fractures or reactivating old ones under injection-perturbed stress conditions; and 3. The physical, stratigraphic continuity and consistency/heterogeneity in the caprock lithologies over the reservoir extent. We address each of these in turn, and then turn to noble gas distributions over the reservoir-caprock package in an integrated method for addressing caprock integrity over the scales of interest.

. Features, processes, and measurement resolution relevant to assessment of caprock integrity (adapted from DOE [6] and Heath [7]).

Unit History and General Geology
The Farnsworth Unit (FWU) is located in Ochiltree county, Texas, USA ( Figure 2), with nearby Arkalon Ethanol Plant and Agrium Fertilizer Plant supplying anthropogenic CO2 for enhanced oil recovery in the field. Production and injection at FWU occur strictly within the Pennsylvanian Morrow B sandstone (Figure 3; [5]). "Morrow" is an operational name that refers to a sequence of alternating mudstone and sandstone intervals deposited during the Morrowan period of the late Pennsylvanian [8]. The Morrow B delineates the first sandstone package deposited below the Atokan Thirteen Finger Limestone [9,10].
The primary caprock intervals at FWU are comprised of the upper Morrow shale and the Thirteen Finger Limestone (Figure 3). The Thirteen Finger Limestone is another informal name for a series of predominantly carbonate cementstone intervals that are intercalated with a  [11]. B. Locations of wells in the Farnsworth Unit (outlined in blue) used in assessing local and field-wide caprock integrity. Red lines in (B) show locations of inferred faults (modified from Hutton, [12]). black carbonaceous mudstone that were deposited during the Atokan period of the late Pennsylvanian ( Figure 3; see also Trujillo [8], and Rose-Coss, [7]). Both the Morrowan and Atokan intervals are common throughout the Texas and Oklahoma panhandles, southeastern Colorado, and western Kansas. Overlying stratigraphy includes Late Pennsylvanian through the Middle Permian shales and limestones, with lesser amounts of dolomite, sandstone and evaporites [7,[12][13][14] Figure 3. Stratigraphic columns of three SWP characterization wells (from Rose-Coss [9]; expanded versions found in his Appendix B).

Tectonic Setting
The FWU sits on the northwest shelf of the Anadarko basin in the Texas Panhandle. From the FWU, the basin plunges to the southeast where it reaches depths of over 40,000 ft (12,192 m) adjacent to the Amarillo-Wichita Uplift [15,16]. Maximum rates of subsidence occurred during Morrowan to Atokan times [14][15][16][17]. Positive features which might have influenced deposition within the region include the Ancestral Rockies to the north, the Central Kansas uplift to the north-east, and the Wichita-Amarillo uplift to the south [17,18]. The structural grain of the basin was inherited from the Precambrian to Cambrian failed arm of a triple junction known as the Southern Oklahoma Aulacogen [15,16]. The region was then tectonically quiet until the beginning of the Chesterian-Morrowan, when the Wichita-Amarillo uplift and the ancestral Rockies formed as a result of northeast-directed basement-involved thrust faulting associated with collision between the North American and Gondwanan plates [14,15,19,20]. Fault movement within the Wichita-Amarillo uplift is characterized by vertical block movement and left-lateral strike slip movement. The vertical fault movement occurred began in the Chesterian and then continued predominantly at the end of the Morrowan into the Atokan time period [17]. This period of faulting created normal faults with a down to the south displacement parallel to the axis of shear associated with the Amarillo uplift. The left lateral strike slip movement occurred afterwards in the late-to-post Atokan and is expressed as anticlinal horst blocks and synformal grabens diverging at intersections from the main shear zones [17]. Tectonic activity slowed after the Atokan and the region was quiescent by the end of the Pennsylvanian. Local uplifts and associated basins combined with climate variations at time of deposition set the stage for the stratigraphic variations seen in core, and especially evident in the Thirteen Finger Limestone, discussed below.

Coring Program, Petrologic Description, and Well Log Analysis
The coring program was designed and implemented in 2013 and 2014 by the SWP and former operator Chaparral Energy LLC, which targeted the primary Morrow B sandstone reservoir and the overlying caprocks, the upper Morrow shale and the Thirteen Finger Limestone. A review of core collected by previous developers of the FWU was conducted by the SWP at the CGG core warehouse in Schluenburg, Texas, during this time, which resulted in production of stratigraphic columns for planning of SWP characterization wells. Locations of the resulting three cored wells were chosen to enable comparison of reservoir properties of the west and east sides of the Farnsworth Unit. The coring program included core analysis plans to support major SWP project objectives and/or research topics on CO2 storage capacity, injectivity, and plume extent; storage permanence; and injectionand/or production-induced reservoir damage. Thus, the planning encompassed a suite of testing, including petrophysics, petrology, geomechanics, and geochemistry.
Schlumberger ran a large suite of wire-line tools for caprock and reservoir characterization, and wellbore integrity assessment in cooperation with the SWP, which had personnel in the field to observe drilling and coring of Well 13-10A and Well 13-14, and to assist with core preservation and core handling. Terra Tek, a former Schlumberger company, performed core handling in the field and initially housed the core for initial core characterization and sampling. Several pieces of fresh core from well 13-10A were sampled and preserved in the field immediately after core retrieval to the Earth's surface for noble gas analysis. Initial core reviews were performed by Sandia National Laboratories (SNL), New Mexico Tech (NMT), and Chaparral Energy to choose sample locations for petrologic, petrophysical, geomechanical, and geochemical analysis to be performed by Terra Tek, SNL, and NMT. SNL and NMT coauthors submitted formal sampling and analysis plans to Terra Tek, which included sampling and/or analysis for thin sections (of the caprocks and reservoir rocks and of fractures), relative permeability and capillary pressure, routine plug analysis, mercury porosimetry, Routine Core Plug (RCPA) and Tight Rock Analysis (TRA) (both by Terra Tek), X-ray diffraction, geochemical analyses including pyrolysis and vitrinite reflectance, and geomechanical testing. To help quantify heterogeneity and guide sampling densities for laboratory testing, the multi-well Heterogeneous Rock Analysis (HRA; [21]) was performed by Schlumberger. For HRA of FWU reservoir and caprock lithologies, results of gamma ray, deep resistivity, bulk density, neutron porosity, and compressional slowness logs were combined with caliper responses to make a preliminary assessment of rock classes, which resulted in determining eleven separate rock unit classes: two for the reservoir lithology (Morrow-B) and nine for the caprock lithologies (upper and lower Morrow shale and Thirteen Finger Limestone). The results of these analyses are included in our assessment of caprock integrity as discussed below. More discussion on core descriptions and core photographs are found in Rose-Coss et al. [9] and Trujillo et al. [10].

Petrologic Characterization
Petrologic methods involve standard thin section petrography and backscattered electron microscopy conducted at both SNL and NMT. Twelve thin sections were half-coated with carbon from well 13-10A for electron microprobe analysis, with the remaining half uncoated to allow for other analyses. The thin sections were analyzed using a Cameca SX-100 microprobe that has three wavelength dispersive spectrometers along with secondary electron and high-speed backscattered electron detectors. The beam diameter was 20 μm and 10 μm for clay minerals. These thin sections were analyzed at the New Mexico Bureau of Geology and Mineral Resources (NMBGMR) at NMT.
Backscattered electron (BSE) images were taken to help determine mineral composition and phases.
The images were taken and analyzed in a preliminary manner by Lynne Heizler of NMBGMR, who identified the mineral phases. The backscattered electron images were correlated with the optical thin section photomicrographs to determine mineral composition especially for the carbonate and clay minerals. The BSE images helped constrain the diagenetic history by determining any mineral alteration of different phase compositions.

Retort Analysis
Retort oil and water saturation measurements were performed on core (biscuit) samples by Terra Tek. Porosity, grain density, and fluid saturation were calculated from a representative portion of the crushed sample, and the whole sample was used for bulk density determination. The total weight and bulk volume were determined for each sample, and then the sample was crushed and sieved until a significant portion of the sample was of the proper size range. The crushed sample was then weighed and placed in a retort vessel and heated to an initial temperature stage to collect the interstitial water. Once the production of fluid had ceased, the temperature of the retort vessel was elevated to remove all remaining condensate and light mobile hydrocarbons. Finally, the temperature was elevated to the final stage to remove any remaining fluids including bound water and any interstitial oil, or 'cracked' kerogen hydrocarbons. The sieved sample, prior to retorting was weighed and the partial grain volume (grain volume plus interstitial fluid volume) of each sample was determined by Boyle's Law technique in order to measure the gas-filled pore space (BV-GV partial).
The porosity, bulk density, grain density, and fluid saturation were then calculated.

Pulse Decay Permeability Analysis
Pulse-decay permeability was measured on core plug samples by Terra Tek at 'as received' saturation conditions. If microfractures were present, the plugs were first prepared by injecting with a penetrating epoxy resin to fill the stress-release microfractures. The sample ends were then trimmed, and pre-weighed 18-mesh screens were added for gas distribution over the end faces of the sample. Each sample was then placed in a hydrostatic core holder and allowed to reach net overburden and pore pressure equilibrium. Sample permeability was then measured by the pulsedecay method.

Pressure Decay Permeability for Tight Rock Analysis (TRA)
Pressure Decay Permeability was measured on samples at 'as received' saturation conditions (measured prior to additional processing). A specific weight fraction of crushed, sieved sample material was loaded into a matrix cup for gas expansion. Data derived from the gas expansion measurement was used to calculate the permeability to gas. Because the sample was crushed, the permeability measurement was not conducted at net overburden conditions; however, a proprietary correlation for net overburden data has been developed and routinely used for specific shale types and was applied to analysis of rock samples herein.

Mercury Porosimetry
Intrusion-extrusion mercury porosimetry was performed on core plugs by Poro-Technology, a Micromeritics company, using a Micromeritics AutoPore IV 9500 Series porosimeter. Core plugs were oriented either vertically or horizontally (i.e., parallel or perpendicular to the long axis of the core).
The core plugs were approximately 0.9-inch (2.3 cm) diameter by 0.9-inch (2.3 cm) long and were jacketed with epoxy for directional intrusion. Poro-Technology made closure corrections accounting for volumes of mercury injected that did not penetrate into the pore space prior to the pressure achieving the mercury entry pressure of the pore space. Breakthrough pressure, or the pressure at which a non-wetting phase penetrates a rock through the connected pore space [22], was estimated for core plugs using methods of Dewhurst et al. [23]. Breakthrough pressures were converted from the mercury-air system to a CO2-water system and to CO2 column heights using the methods of Ingram et al. [24]. We use an interfacial tension value of 484 mN/m for mercury-air-rock system, and a contact angle of 140°. We assumed a geothermal gradient of 25°C/km and a hydrostatic pressure gradient of 0.0098 MPa/m to estimate the density of CO2 and water at the depths of the core plugs.
Interfacial tension values for the water-CO2 system assumed zero ionic strength and used the methods of Heath et al. [25]. Contact angles for the water-CO2-mineral system were estimated from Iglauer et al. [26] for quartz, calcite, and mica, resulting in a range of 10 o to 57°.

Geomechanics Analysis
A series of rock mechanical tests were performed on rock core sampled and tested at Terra Tek's laboratories in Salt Lake City, Utah, using standard techniques. These include Brazil tension (or cylinder splitting) tests, unconfined compression tests, and triaxial compression tests. These were used to extract static elastic properties, rock unconfined and triaxial strength, and tensile strength information from samples from all three SWP characterization wells in the FWU. A standard Mohrcircle analysis was used to delineate failure envelopes for sampled lithologies. descriptions focused on identifying fracture types based on morphologic characteristics and intensity. As the core was not oriented, Terra Tek drew an arbitrary "North" line on the core to enable measurement of relative orientation of measured fractures. Fracture attributes measured include fracture strike and dip, general fracture type, type of mineral fill, type of oil stain, fracture porosity, fracture spacing, and intensity of fractures for each cored interval. Fracture classes include those induced from drilling or coring versus natural fractures that may or may not exhibit shear, extension, or mineralization. Terra Tek analysis included tabulation of fracture types by depth and stereo plots of relative fracture orientations by fracture type.

Preservation of Fresh Core and Noble Gas Analysis
Core preservation for noble and other pore fluid gases followed procedures found in Osenbrück [27]. Specially designed canisters were built from high-vacuum service equipment to seal samples against atmospheric contamination or significant pore fluid degassing. Core was preserved immediately in the field after the core was retrieved to Earth's surface and slabbed in the field to obtain samples. After sub-sampling of core from Well 13-10A, samples were weighed and sealed in canisters. A purging and vacuum pump-down process evacuated atmospheric noble gases from the canisters. Helium, neon, and argon isotopes were analyzed at the University of Utah's Dissolved and Noble Gas Laboratory in Salt Lake City, Utah, USA. After transfer of the gases into a purification line, analysis followed methods described by Hendry et al. [28] using quadrupole and magnetic sector field mass spectrometers.

Results
As stated in the introduction, caprock integrity for EOR-CCUS is a multiscale assessment of the ability of a caprock lithology or set of lithologies to sustain emplacement of a body of CO2 for a given time. For CCUS, this may be 100s or 1000s of years. One aspect for CCUS which is favorable for use of CO2 for oil recovery and storage is the fact that the same caprock invoked for CO2 uses is the same caprock involved in oil and gas storage over geologic time. We know from the long history of subsurface engineering at FWU that storage under EOR conditions is favorable for CO2 containment.
We need to build confidence that injection and emplacement conditions under CCUS best practices does nothing to threaten the integrity of caprock lithologies. To this end, we examine integrity of the 3. The physical, stratigraphic continuity and consistency/heterogeneity in the caprock lithologies over the reservoir extent. We address each of these in turn, and then turn to noble gas distributions over the reservoir-caprock package in an integrated method for addressing caprock integrity over the scales of interest. Figure 3 shows stratigraphic columns of each core obtained from the three characterization wells at Farnsworth (the 13-10A, 13-14, and 32-8), depicting the extent of mud and sand in the clastic mixture, including fractured zones, depositional fabrics (i.e., carbonate hardgrounds, burrows, and coal cleats) and diagenetic features (i.e., carbonate "beef", concretions, and mineralized fractures) that could exert positive or negative influences on caprock integrity. Details about these features are found in [9] and [10].

Lithofacies Interpretations of Caprock Lithologies
The upper Morrow shale is a marine mudstone that directly overlies the Morrow B sandstone reservoir ( Figure 3) and thus serves as the primary caprock. It is composed of three common mudstone lithofacies (Table 1) including black laminated mudstone (blM), calcareous mudstone (cM) and green bioturbated mudstone (gbM) as determined [9]. The lower portions of the upper Morrow shale consist of the gbM facies, which is transitional from the sands of the Morrow B reservoir. The green bioturbated mudstone (gbM) lithology is a slightly fossiliferous, organic-rich, slightly calcareous mudstone, that contains scattered quartz, feldspar, muscovite, and calcareous fossil-hash silt. The middle portion of the upper Morrow shale consists of the blM facies, which is interpreted by [9] to be deposited under anoxic conditions, consisting of fissile, slightly fossiliferous organic-rich mudstone. This facies gradually transitions upward into the cM facies, a more friable and calcareous mudstone that contains several hardgrounds (i.e., cemented paleo sea-floor surfaces) that are found to be laterally continuous through the FWU [9,10]. The variable degree of cementation in the cM facies imparts a heterogeneity to the geomechanical response, as discussed later.  Adams [34]). From thin section observation [9,10], the mudstones contain variable amounts of organic matter, quartz, and macro and microfossils. Authigenic pyrite, calcite, and dolomite are common.
Many of the cementstone layers contain fractures, many of which are filled with carbonate cement [10]. The limestone is somewhat unusual, in that, at least for the few samples analyzed thus far, it is dominated by diagenetic carbonate (Figure 5C and D). The limestone locally contains significant biogenic carbonate [10]. Thus, most of the limestones in the Thirteen Finger Limestone are more properly classified as cementstones. This interpretation is supported by the obvious occurrence of concretions in the core ( Figure 5D), which are similar in character to the limestone beds.

Porosity and Permeability by Lithofacies
Porosity, water and oil saturation, and gas permeability for a range of rock types in each of the characterization wells were analyzed via Terra Tek's RCA at depth intervals of approximately three feet if core plugs were attainable, and these are mostly reservoir lithologies. Data for well 13-10A are given in the Appendix of Rasmussen et al. [2]; data for the other two wells (13-14 and 32-8) are given   This method allows determination of gas-filled porosity, hydrocarbon filled porosity, effective gas saturation, as well as total porosity and permeability among other parameters. These results are summarized in Table SM-5 for all three characterization wells and are mapped to both the caprock facies designation of [9] and the HRA color unit. In Figure 6 we plot total porosity and permeability While there is well-to-well variability, in general the Morrow shale mudstones have higher porosity and slightly higher permeability than mudstone and limestone in the other formations.
Porosities and permeabilities of the hydrologic flow units in the Morrow B sandstone are considerably higher, with porosity values ranging largely from 15 to 20%, and permeability ranging from 10 to 1000 mD (orders of magnitude higher than the mudstone facies of the caprock units at FWU shown in Figure 6; see Figure 2 in [2]).

Porosimetry and CO2 Column Heights in Farnsworth Reservoir and Sealing Lithologies
Sealing capacity in the context of CCUS is the CO2 column height that is retained by the capillarity of a water wet rock. Here, we estimate CO2 column heights (using calculated pore throat diameters and breakthrough pressures) for the different reservoir and caprock lithologies using MICP analyses from core plug samples summarized in Table SM

Natural and Induced Fractures
Natural fractures in mudstone lithologies can impact fluid-flow, fracture permeability, and mechanical strength of the rock [35], all critical aspects for caprock integrity. For the purposes of understanding how natural fractures impact the ability of FWU caprock lithologies to prevent CO2 leakage, we need to characterize fracture apertures and density as well as orientation spatially and in reference to current in situ stress orientations. Orientation aspects are especially relevant as: 1.
fractures are generally strength-limiting at above-core length scales, and the increase in pore pressure can induce slip and permeability increases for suitably oriented fractures [36,37], 2. fracture orientation with respect to the in situ local stress tensor affects aperture width and thus permeability, Fractures in FWU caprock were described via fracture class type, orientation, fracture dip, type of mineral fill, fracture porosity, fracture spacing and intensity for wells 13-14 and 32-8 [38,39]. For to be more recent, i.e. formed under current stress orientations. According to Snee and Zoback's [40] stress map of Texas (see also [10]), the FWU should be located in a transitional stress state between a normal faulting regime and a strike-slip faulting regime where the maximum horizontal stress (SH) is slightly less but approaching the vertical stress Sv in magnitude (i.e., SH max ̴ Sv > Sh where Sh is the minimum horizontal stress). The orientations of maximum horizontal stress in the Texas Panhandle, determined from horizontal breakouts, trend from SE-NW to EW, which would be the injection. This is beyond the scope of the present chapter but will be addressed in a later work.
However, the coincidence of the coring induced fractures and the natural fractures would suggest that these fractures would be of a critical orientation for slip (i.e. shear fracture) associated with fluidinjection induced overpressure. What bodes well for caprock integrity, however, is the relative rare occurrence of fractures overall in the FWU caprock lithologies.

Static and Dynamic Mechanical Behavior
It is important to understand the limiting strength of the shallow crust posed by existing fractures [37], and as well is it necessary to understand the heterogeneity in matrix rock mechanical properties. Static rock mechanics properties concern poroelastic deformation, yielding, and ultimate rock strength and failure. A typical suite of rock mechanics tests that permit parameterization of constitutive models includes an unconfined compression (UCS) test (a right cylinder of rock is exposed to an axial load with no confining load applied to the round surface of the cylinder), several triaxial (TXC) tests (an axial load is applied to the long axis of the cylinder with a constant confining pressure applied to the cylinder sides), and a hydrostatic test in which the rock cylinder is subject to a constant applied pressure, with or without separately controlled pore pressure. A deformable jacket surrounding the cylinder keeps the pore and confining systems separate. These tests allow us to examine the variability of elastic properties (i.e., Young's Modulus and Poisson's Ratio, which can either be used to represent an elastically isotropic medium, or be directionally dependent, which is a simplified means to assess elastic anisotropy, for example with respect to primary bedding direction), yielding behavior (involving inelastic processes such as microfracture growth and coalescence, or pore collapse), and failure (involving complete loss of cohesion of a deforming rock generally by a through-going shear fracture).
An extensive suite of geomechanical properties have been assembled from the Terra Tek testing program for the FWU characterization wells and are available in the series of Terra Tek reports [41][42][43]. One valuable aspect of the data set is the degree to which it maps properties on rock units based on Terra Tek's HRA methodology for sampling and testing. We focus here on elastic properties, failure envelopes and fracture gradients as they concern caprock integrity, but this array of geomechanical data can be used for, among other things: • Advanced elastic-plastic modeling of yielding and failure associated with CO2 injection and plume migration; • Biot and compressibility parameters for reservoir engineering; • Determination of "frac" gradients to guide injectivity and pressure management strategies for risk and performance assessment.
• Guiding modeling for estimating surface expressions of CO2 injection such as uplift and subsidence for monitoring and verification efforts.
• Inform monitoring of induced microseismic activity during injection.
• Aid in construction of velocity models for seismic inversion.
• Aid in determining caprock integrity for risk and performance assessments. this is not an unexpected degree of elastic heterogeneity, but could influence how the caprock responds to a reservoir-scale increase in pore pressure associated with CCUS activities.
Probably more important for caprock integrity is the failure behavior of the suite of rock types.  Figure 11A and B show the shear dilatant behavior of the weaker rock types tested, Blm mudstones from the Thirteen Finger Limestone (rock class Orange as shown in Figure 4) in Figure   11A, and from the Morrow shale (rock class Red, a laminated mudstone as shown in Figure 4). The two mudstones behave very similarly, with an angle of internal friction ϕ equal to 27°, and an apparent cohesion of around 3500 psi. A slightly weaker shale tested was a silty mudstone from the Morrow shale ( Figure 11C, rock class Yellow) with a lower ϕ of 21° and an apparent cohesion of ~3200 psi.
Morrow B sandstones are apparently much weaker, as shown in Figure 11D. The sandstones have a greater ϕ of 44°, but a very low cohesive strength of 830 psi. This analysis shows that Trujillo [10] also shows that a sample of cementstone from the Thirteen Finger Limestone has apparently an incredibly high unconfined compressive strength of ~47 kpsi, which is approaching that of some crystalline rocks.

Fracture Gradients in Farnsworth Reservoir and Sealing Lithologies
We bracketed the orientation of the three principal stresses within the FWU from both regional observations [40] and

Seal Lateral Continuity in the Farnsworth Unit
Isopach maps of the upper Morrow shale and Thirteen Finger Limestone across the FWU were prepared from formation tops and bottoms after data compiled by [9] and are shown in Figure SM

Caprock Integrity Inferred from Noble Gas Analyses
Measurement of naturally occurring noble gases in a vertical profile from preserved fresh core Context for interpreting noble gas data measured in this study is that atmospherically sourced isotopes are 20 Ne and 36 Ar, whereas geogenic isotopes sourced in the subsurface are 3 He, 4 He, 40 Ar, and 22 Ne [44]. Isotopic ratios for atmospheric, crustal, and mantle reservoirs are well known and used to identify sources of fluids in petroleum systems [45]. The measured 3 He over 4 He ratio (R) from Formation that probably had R/Ra values at closer to 1.00 than the older caprock fluids (younger groundwaters will probably have values closer to one than older crustal fluids; see [45]. The R/Ra value greater than 1.00 in the Morrow B sandstone may be an artifact of the laboratory analysis; mantle-sourced fluids have R/Ra values much greater than one [45], but this is unlikely as a source due to the rest of the samples being less than one. Complex phase partitioning between groundwater, oil, and any gas phase may also lead to ratios greater than one. Ratios of 4 He/ 20 Ne, normalized by the atmospheric value, are several orders of magnitude greater than one for most samples, thus indicating high helium concentrations due to long-term production of 4 He from U and Th in the sealing lithologies with low permeability and low effective diffusivity. The very distinct change in R/Ra from the Morrow B into the upper Morrow shale indicates that the upper Morrow shale is a good seal at least at that contact measured by the coring. Figure 13. Noble gas ratios versus depth for Well 13-10A. The subscript m stands for the ratio measured for the sample, whereas the subscript ASW stands for the air saturated water value for the ratio.
Because of the high amount of methane and helium in many samples as observed during laboratory analysis, sample splitting was necessary, which affected the reliability of the argon values.
Thus, argon values were not reported by the laboratory for several samples (Table SM-7). The argon isotopic values that are available also reflect some process that introduce fluids into the system that may have been in equilibrium with the atmosphere (Figure 13). A sample within the upper Morrow shale has a relatively low light-to-heavy Ar isotopic ratio, which is expected as 40 K within the formation would produce 40 Ar.
The deviations from 0.02 R/Ra for the Thirteen Finger Formation may be due to improper sealing or leakage of the preservation canisters as such leakage would bring the values closer to 1.00, which may be likely for the sample at depth 7,515 ft (2290.57 m) as its R/Ra is 0.47, and its neon and argon isotope ratios are close to the atmospheric values ( Figure 13). However, the adjacent sample at depth 7,502 (2286.01 m) also has a relatively high R/Ra of 0.034 and its neon and argon ratios are slightly shifted from the atmospheric equilibrium values. Thus, it is possible that some process is

Discussion
Direct formation-scale assessment of caprock integrity is difficult. Core-based measurements, wire-line logging, and seismic techniques are: very localized and/or may lack resolution to identify potential seal-by systems (e.g., such as connected fracture networks that are below seismic resolution); or used to infer large-scale behavior, which may include modeling to integrate to the reservoir and caprock properties made at different locations and different scales [46]. To build confidence in and understanding of caprock integrity at FWU, this study by the Site Characterization team of the SWP approaches caprock integrity by systematically assessing processes that govern sealing quality at different scales following the framework of Figure 1.

Conclusions
Our main conclusions from this study are as follows: • Cementstones in the Thirteen Fingers have anomalously high sealing potential and strength, and the ability of these thin bands of tight carbonate to serve as seals by themselves would be limited only by their lateral continuity.
• Failure analyses show that the Morrow B sands are weaker than overlying lithologies, so that any fracture initiation around the injection well would not be expected to propagate into the overlying sealing units.
• A preliminary assessment of fracture gradient shows that formations should larger be able to support injection and overpressure to ~5000 psi, a few thousand psi over hydrostatic pressure values at the depths of interest.
• Noble gas analysis from fresh core shows that the caprock lithologies show no degree of leakage from historical water and CO2 flooding in the FWU, whereas the Morrow B sandstone shows an impact from EOR activities.
Together, these analyses conducted at different scales strongly suggest an excellent sealing capacity for the Morrow Shale and Thirteen Fingers lithologies. This is from both the high degree of capillary sealing, the low potential for seal bypass, and the large regional extent of the caprock lithologies in the FWU.

Supplementary Materials:
The following are available online at www.mdpi.com/xxx/s1: Tables: Table SM1 Results of noble gas analysis, including the sample mass and supplementary estimates of wet bulk density, total porosity based on laboratory analysis on fresh core samples or well log interpretation. Figures: Figure SM1. Well 13-14 HRA summary and accompanying well logs used in analysis; prepared by Schlumberger; Figure SM