THE GOTHIC SHALE of the PENNSYLVANIAN PARADOX FORMATION, GREATER ANETH FIELD (ANETH UNIT), SOUTHEASTERN UTAH: SEAL for HYDROCARBONS and CARBON DIOXIDE by Jason E

THE GOTHIC SHALE OF THE PENNSYLVANIAN PARADOX FORMATION, GREATER ANETH FIELD (ANETH UNIT), SOUTHEASTERN UTAH: SEAL FOR HYDROCARBONS AND CARBON DIOXIDE by Jason E. Heath, Thomas A. Dewers, Thomas C. Chidsey, Jr., Stephanie M. Carney, and S. Robert Bereskin

MISCELLANEOUS PUBLICATION 17-1 UTAH GEOLOGICAL SURVEY a division of UTAH DEPARTMENT OF NATURAL RESOURCES 2017 Blank pages are intentional for printing purposes THE GOTHIC SHALE OF THE PENNSYLVANIAN PARADOX FORMATION, GREATER ANETH FIELD (ANETH UNIT), SOUTHEASTERN UTAH: SEAL FOR HYDROCARBONS AND CARBON DIOXIDE

by Jason E. Heath1, Thomas A. Dewers1, Thomas C. Chidsey, Jr.2, Stephanie M. Carney2, and S. Robert Bereskin3

1Sandia National Laboratories, Albuquerque, New Mexico 2Utah Geological Survey, Salt Lake City, Utah 3Bereskin and Associates, Salt Lake City, Utah

Cover photos: Cross-bedded channel deposits of the Cretaceous Dakota Formation overlying varigated shales of the Brushy Basin Member of the Jurassic Morrison Formation, Aneth Unit (view west), Greater Aneth field, southeastern Utah. Photo by Craig D. Morgan, Utah Geological Survey. Left inset: typical Gothic shale core (view down core) of the Pennsylvanian Paradox Formation, which forms the reservoir seal for Greater Aneth field. Right inset: photomicrograph (plane light) of argillaceous shale lithotype in the Gothic shale. Both images from 5379.4 feet (1639.6 m), Aneth Unit No. H-117 well.

ISBN: 978-1-55791-940-3

MISCELLANEOUS PUBLICATION 17-1 UTAH GEOLOGICAL SURVEY a division of UTAH DEPARTMENT OF NATURAL RESOURCES 2017 STATE OF UTAH Gary R. Herbert, Governor

DEPARTMENT OF NATURAL RESOURCES Michael Styler, Executive Director

UTAH GEOLOGICAL SURVEY Richard G. Allis, Director

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Although this product represents the work of professional scientists, the Utah Department of Natural Resources, Utah Geological Survey, makes no warranty, expressed or implied, regarding its suitability for a particular use. The Utah Department of Natural Resources, Utah Geological Survey, shall not be liable under any circumstances for any direct, indirect, special, incidental, or consequential damages with respect to claims by users of this product. CONTENTS

ABSTRACT...... 1 INTRODUCTION...... 1 GREATER ANETH FIELD SYNOPSIS...... 3 Trap and Lithofacies...... 3 Reservoir Properties...... 4 Hydrocarbon Characteristics...... 4 Production, Reserves, and Enhanced Oil Recovery...... 5 THE GOTHIC SHALE IN THE ANETH UNIT...... 5 Subsurface Structural and Thickness Mapping...... 5 General Core Description...... 8 Geochemistry...... 10 Petrography...... 14 Petrographic Methods...... 14 Argillaceous Shale...... 14 Argillaceous Mudstone...... 16 Silty Calcareous-Argillaceous Mudstone...... 17 Phosphatic Argillaceous Mudstone...... 17 Analysis of Natural Fractures...... 17 Petrophysical Properties...... 21 Basic Reservoir Parameters...... 21 Mercury Injection Capillary Pressure and Pore Aperture Distributions...... 21 Geomechanics...... 22 Young’s Modulus and Poisson’s Ratio...... 22 Compressional Testing...... 25 SUMMARY AND CONCLUSIONS...... 25 ACKNOWLEDGMENTS...... 29 REFERENCES...... 29

FIGURES

Figure 1. Oil and gas fields in the Paradox Basin of Utah, Colorado, andArizona, and the Paradox Formation play...... 2 Figure 2. Pennsylvanian stratigraphic chart for the Paradox Basin...... 3 Figure 3. Drilling units within Greater Aneth field, Utah...... 4 Figure 4. Generalized isopach of the Desert Creek zone, Greater Aneth field, Utah...... 4 Figure 5. Structure contours on the top of the Gothic shale, Aneth Unit, Greater Aneth field...... 6 Figure 6. Thickness of the Gothic shale, Aneth Unit, Greater Aneth field...... 7 Figure 7. Core of the Gothic shale from the Aneth Unit No. H-117 well...... 8 Figure 8. Geophysical log and core description, Gothic shale, Aneth Unit No. H-117 well...... 9 Figure 9. Kerogen type determination of the Gothic shale from TOC and programmed pyrolysis data...... 10 Figure 10. Kerogen quality determination of the Gothic shale from TOC and programmed pyrolysis data...... 11 Figure 11. Methane adsorption for the Gothic shale...... 12 Figure 12. Graph of X-ray diffraction data from the Gothic shale...... 13 Figure 13. Photomicrographs and scanning electron microscope images of argillaceous shale lithotype in the Gothic shale...... 15 Figure 14. Photomicrographs and scanning electron microscope image of the argillaceous mudstone lithotype, Gothic shale...... 16 Figure 15. Laser scanning confocal microscopy images of the Gothic shale...... 16 Figure 16. Backscattered electron images of the Gothic shale, Aneth Unit No. H-117 well...... 17 Figure 17. Photomicrographs and scanning electron microscope images of silty calcareous-argillaceous mudstone lithotype in the Gothic shale...... 18 Figure 18. Photomicrographs and scanning electron microscope images of phosphatic argillaceous mudstone lithotype in the Gothic shale...... 19 Figure 19. Backscattered electron images of the Gothic shale, Aneth Unit No. H-117 well...... 20 Figure 20. Inclined shear fracturing with slickensides in the Gothic shale core...... 21 Figure 21. Inclined shear fracture zone displayed on various backscattered electron images, thin section photomicrographs, and laser scanning confocal microscopy images...... 21 Figure 22. Mercury injection capillary pressure and pore aperture distributions...... 22 Figure 23. Young’s modulus plots...... 23 Figure 24. Poisson’s ratio plots...... 24 Figure 25. Results of unconfined compression testing...... 26 Figure 26. Continuous unconfined compressive strength profile of the Gothic shale core...... 28

TABLES

Table 1. Basic geochemical measurements from the Gothic shale, Aneth Unit No. H-117 well...... 10 Table 2. Methane adsorption isotherm for the Gothic shale...... 11 Table 3. Summary of petrophysical measurements from the Gothic shale...... 21 Table 4. Summary of multistress anisotropy measurements from the Gothic shale...... 23 THE GOTHIC SHALE OF THE PENNSYLVANIAN PARADOX FORMATION, GREATER ANETH FIELD (ANETH UNIT), SOUTHEASTERN UTAH: SEAL FOR HYDROCARBONS AND CARBON DIOXIDE

by Jason E. Heath, Thomas A. Dewers, Thomas C. Chidsey, Jr., Stephanie M. Carney, and S. Robert Bereskin

ABSTRACT INTRODUCTION

Greater Aneth oil field, Utah’s largest oil producer, was dis- Greater Aneth oil field, Utah’s largest oil producer, was discovered in 1956 and has produced over 483 million bar- covered in 1956 and has produced over 483 million barrels of rels of oil. Located in the Paradox Basin of southeastern oil (BO) (Utah Division of Oil, Gas and Mining, 2017a). It is Utah, Greater Aneth is a stratigraphic trap producing from a mature, major oil field in the western U.S. and has a large the Pennsylvanian (Desmoinesian) Paradox Formation. Be- carbonate reservoir. Located in the Paradox Basin of extreme cause Greater Aneth is a mature, major oil field in the west- southeastern Utah (figure 1) within the Colorado Plateau, ern U.S., and has a large carbonate reservoir, it was selected Greater Aneth is a stratigraphic trap created by facies changes to demonstrate combined enhanced oil recovery and carbon that seal the reservoir laterally in addition to the seals above dioxide storage. The Aneth Unit in the northwestern part of and below; fractures and small faults create a structural com- the field has produced over 160 million barrels of the esti- ponent to the field. Greater Aneth produces oil and gas from mated 386 million barrels of original oil in place—a 42% the Desert Creek zone of the Pennsylvanian (Desmoinesian) recovery rate. The large amount of remaining oil made the Paradox Formation (figure 2). The Desert Creek zone isa Aneth Unit ideal to enhance oil recovery by carbon dioxide complex reservoir representing a variety of depositional envi- flooding and demonstrate carbon dioxide storage capacity. ronments (open-marine shelf, shallow-marine oolitic shoals, phylloid-algal mounds, low-energy restricted shelf) that produce significant heterogeneity. There is some evidence of Within the Paradox Formation, the Gothic shale seals the minor hydrothermal dolomite, in-situ brecciation, and faults underlying Desert Creek oil reservoir. The Gothic shale that may affect fluid flow (Chidsey and Eby, 2014). Original ranges in thickness from 7 to 26 feet (2–8 m), averaging 15 oil in place (OOIP) reserves for Greater Aneth field are esti- feet (4.6 m). Within the Aneth Unit, it is remarkably uni- mated at 1100 million barrels (bbls) (Babcock, 1978a, 1978b, form consisting of black to gray, laminated to thin-bedded, 1978c, 1978d; Peterson, 1992). Thus, given the large amount dolomitic marine shale. The Gothic contains total organic of remaining oil, the field was ideal for enhanced oil recovery carbon ranging from 2.2% to 4.4% with type III and mixed (EOR) by carbon dioxide (CO2) flooding and a demonstration type II-III kerogen. Natural fractures are horizontal to in- of CO2 storage capacity. clined (30° to 44°) with evidence of shear in the form of slickensides; some mineralization is present. Geochemical, Paradox Formation shale, halite, and anhydrite at Greater petrological, petrophysical, and geomechanical analyses Aneth field serve as vertical reservoir seals. Lateral seals were conducted to determine (1) the geologic controls on are permeability barriers created by unfractured, off-mound sealing effeciency, (2) effects of pressure changes on the (non-buildup) mudstone and wackestone. The Gothic shale seal due to carbon dioxide injection and storage, and (3) of the Paradox Formation separates the Ismay from the un- possible chemical interaction between carbon dioxide and derlying Desert Creek zones in Greater Aneth (figure 2) and the seal at its contact with the reservoir through time. other fields in the basin. It is the primary seal for the Des- 2 Utah Geological Survey

Figure 1. Oil and gas fields in the Paradox Basin of Utah, Colorado, and Arizona. The Paradox Formation play is shaded light orange. Note location of Greater Aneth field in southeasternmost Utah. Modified from Kitcho (1981) and Harr (1996).

ert Creek reservoir, although the Gothic is now recognized ment of oil, natural hydrocarbon gas, and CO2 (Couples, as a potential shale-gas or shale-oil reservoir in this area 2005). Diffusion in this case is not considered an important of the Paradox Basin (Schamel, 2005, 2006; Bereskin and means for moving hydrocarbons or CO2. Key relationships McLennan, 2008, 2009; Bereskin and others, 2010; Chid- to consider in understanding seals include those between sey, 2016). The Gothic shale is widespread throughout the porosity and (1) stress, (2) permeability, and (3) capillary Paradox Basin, but is only exposed in Utah along parts of breakthrough pressure (Alpin and Larter, 2005). These rela- the San Juan River west of the Aneth area (Morgan and oth- tionships are affected by the seal’s petrographic (grain size, ers, 2016). In the Aneth Unit, the Gothic shale is remark- mineral composition, and clay fraction) and geochemical ably uniform, consisting of black to gray, laminated to thin- (organic content and maturity) characteristics. The ability bedded, organic-rich dolomitic marine shale. It averages 15 of mudrock (shale), salt, and anhydrite to prevent CO2 (and feet (4.6 m) thick and generally thins over the carbonate hydrocarbon) leakage is a critical factor for the geological buildup complex in the Desert Creek zone. storage of anthropogenic CO2 (Lu and others, 2009). For effective storage of CO2 produced from coal-fired power A reservoir seal can be defined as a body of rock that is plant point sources, retention times of 10,000 years are re- capable of significantly impeding the migration or move- quired (Lindeberg, 2002). Therefore, it is critical to under- The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 3

stand if the seal can remain effective for long periods of time (Lu and others, 2009). For large-scale geologic CO2 storage, additional questions not part of a typical hydrocarbon reservoir seal analysis must be addressed. These include:

1. Can the impact of preexisting seal fractures on CO2 transport be adequately characterized prior to CO2 injection?

2. What chemical alterations of seal rock minerals and/or organic matter would occur from interaction with CO2-rich fluids, and how would they affect sealing capacity?

3. What rate and amount of CO2 leakage would be ac- ceptable?

4. What geomechanical impacts, such as fracture creation or containment problems, accompany CO2 injection? GOTHIC A major challenge is identifying local micro- to meso-scale CHIMNEY imperfections or flaws in seals that could allow CO2 to mi- ROCK grate from potential storage sites, which may cover areas up to hundreds of square miles. We investigated these questions at Greater Aneth field, as part of a demonstration study by the Southwest Regional Partnership on Carbon Sequestra- tion conducted from 2006 through 2010, to develop and test conceptual and numerical models of sealing behavior with a focus on understanding pre-existing natural imperfections and the potential formation of new imperfections.

The following activities were conducted on the Gothic shale: (1) subsurface mapping, (2) general core description, (3) geochemistry, (4) petrography, (5) analysis of natural fractures, (6) petrophysical properties, and (7) geomechanics. The study results were used to determine the geologic controls on seal efficiency, effects of pressure changes on seal efficiency due to CO2 injection and storage, and chemical interaction between CO2 and the seal at its contact with the reservoir through time.

GREATER ANETH FIELD SYNOPSIS

Greater Aneth field is divided into four drilling units (figure 3). The 25-square-mile (65 km2) Aneth Unit (T. 40 S., R. 23 to 24 E., Salt Lake Base Line and Meridian, San Juan County) is located in the northwestern part of the field. The majority of the unit is located on Navajo Nation lands, with the exception of the western part, which is U.S. Bureau of Land Management (BLM) parcels. Figure 2. Pennsylvanian stratigraphic chart for the Paradox Basin including the Paradox Formation, informal zones (Desert Creek in tan), and numbered cycles. Red text points Trap and Lithofacies to the organic-rich Gothic and Chimney Rock shale intervals that serve as both hydrocarbon source and seals for the Desert The Greater Aneth field stratigraphic trap produces primarily Creek zone at Greater Aneth field. Modified from Hite (1960), from the Desert Creek zone, which is sealed and sourced by the Hite and Cater (1972), and Reid and Berghorn (1981). organic-rich, overlying Gothic and underlying Chimney Rock 4 Utah Geological Survey

shales, respectively (figure 2). The Desert Creek zone creates an Reservoir Properties irregular west-northwest-trending reservoir buildup (figure 4). The trap was created by facies changes, including evaporites, that The average net reservoir thickness of the Desert Creek zone at seal the reservoir laterally in addition to the seals above and be- Greater Aneth is 50 feet (15 m) over a 48,260-acre (19,530 ha) low. Within the field, the Desert Creek zone is divided into three area. Porosity ranges from 9% to 13% (but can be significantly subzones: a relatively thin lower interval that represents a transi- higher, 16% or greater) in interparticle, moldic, and intercrys- tion to the Chimney Rock shale, a middle interval composed pre- talline networks enhanced by fractures; permeability averages dominantly of phylloid-algal buildup lithofacies, and an upper 10 millidarcies (mD), ranging from 3 to 100s mD. The original interval composed of oolitic-peloidal calcarenite lithofacies (Pe- drive mechanism is fluid expansion and solution gas; original terson and Ohlen, 1963; Babcock, 1978a, 1978b, 1978c, 1978d; water saturation was 24%. The bottom-hole temperature aver- Peterson, 1992; Moore and Hawks, 1993; Chidsey and Eby, ages 125°F (52°C) (Peterson and Ohlen, 1963; Babcock, 1978a, 2014). The Desert Creek reservoir at Greater Aneth field consists 1978b, 1978c, 1978d; Peterson, 1992; Moore and Hawks, 1993). of limestone (algal bafflestone and oolitic, peloidal, and skeletal grainstone and packstone) and finely crystalline dolomite. Hydrocarbon Characteristics

The depositional environment for the Gothic shale was generally The produced oil is a dark green, paraffinic crude. The oil was low-energy, offshore marine based on a limited number of cores originally sweet but now is sour due to sulfate-reducing bac- from wells in the Utah part of the Paradox Basin (for detailed teria introduced during waterflood operations. The API grav- core descriptions and core photographs see Chidsey, 2016). An- ity of the oil ranges from 40° to 42°; the original gas-oil ratio aerobic, dysaerobic, or anoxic conditions existed in deep water was 665 cubic feet/bbl. The viscosity of Greater Aneth oils settings. Slow deposition also included some clastic influx from ranges 0.53 to 0.54 centipoise. The pour point of the crude oil a distal source consisting of dysaerobic, organic-rich material di- is 10°F (-12°C). The average weight percent sulfur and nitro- gen of produced hydrocarbon liquids are 0.2 and 0.04, respec- luted by terrigenous clastic sediments. Water depths were prob- tively (Stowe, 1972; Peterson, 1992). Greater Aneth reservoirs ably variable, ranging from below fair-weather and storm wave produce associated gas that is fairly uniform in composition, base for the organic-rich shales to relatively shallow, nearshore averaging 62% methane, 18% ethane, 11% propane, 5.5% bu- for siltier intervals. Influx of terrigenous quartz silt in the Gothic tane and iso-butane, 2.5% pentane and iso-pentane, less than associated with the Silverton delta in the easternmost Paradox 1% hexane and higher fractions, 0.2% CO , and occasionally Basin in southwestern Colorado, combined with organic-rich 2 a trace of hydrogen sulfide and helium (Stowe, 1972; Moore material, helped create reservoirs with some marginal shale-gas and Hawks, 1993). The gas heating value averages 1450 British production in that part of the basin (Moreland and Wray, 2009). thermal units/cubic foot (Btu/ft3) (1.53 million joules). The to- The source of the quartz silt in the Gothic within the Utah part of the Paradox Basin was probably to the west-southwest.

Figure 4. Generalized isopach of the Desert Creek zone, Greater Aneth field, San Juan County, Utah; contour interval = 25 feet. Note the location of the Aneth Unit No. H-117 well (NE1/4NE1/4 Figure 3. Drilling units within Greater Aneth field, San Juan section 17, T. 40 S., R. 24 E., Salt Lake Base Line & Meridian). County, Utah. Modified from Peterson and Ohlen (1963). The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 5

tal dissolved solids in the produced water ranges from 103,000 million bbls of OOIP (Babcock, 1978a). However, production to 304,000 mg/L; the resistivity of the water is 0.35 ohm-meters has improved due to a CO2 flood program initiated in 2007 at formation temperature (Peterson, 1992). by the current field operator, Resolute Energy Corporation. Incremental recovery from CO2 flooding is estimated at 33 Production, Reserves, and Enhanced Oil Recovery million BO or an additional incremental recovery efficiency of 9% (Jim Rutledge, Los Alamos National Laboratory, ver- Greater Aneth field was discovered in February 1956 with the bal communication, 2007). The Aneth Unit has produced over completion of the Texaco No. 1 Navajo C well, NW1/4NE1/4 160 million BO as of January 1, 2017 (Utah Division of Oil, section 23, T. 40 S., R. 24 E. (figure 3), which had an initial Gas and Mining, 2017b)—a 42% recovery rate. flowing potential (IFP) of 568 bbls of oil per day (BOPD) and 4376 thousand cubic feet of gas per day (MCFGPD). The original reservoir field pressure was 2170 pounds per square inch THE GOTHIC SHALE IN THE ANETH UNIT (psi [14,960 kPa]) (Moore and Hawks, 1993). Currently, 444 producing (or shut-in) wells and 123 abandoned producers are Subsurface Structural and Thickness Mapping in the field. Cumulative production as of January 1, 2017, was 483.1 million BO, 440.2 billion cubic feet of gas (BCFG), and The Gothic shale is the seal for the Desert Creek oil reservoir 1879.5 million bbls of water (BW) (Utah Division of Oil, Gas and injected CO2 in the Aneth Unit. The structure contour and and Mining, 2017a). The OOIP reserves for Greater Aneth field thickness maps for the Gothic are shown on figures 5 and 6, re- are estimated at 1100 million bbls (Babcock, 1978a, 1978b, spectively. The lateral extent and shape of the underlying Des- 1978c, 1978d; Peterson, 1992). ert Creek carbonate buildup complex is seen in the structure contour map as elevated areas within the Aneth Unit. Struc- Waterflood operations began in 1961 and are used in all four tural mapping of the Gothic also suggests the presence of faults Greater Aneth field units (figure 3)—the largest waterflood -pro that are undetected on seismic data or on wireline well logs, gram in Utah (Babcock, 1978b). More than 340 water injec- but are expressed only as unusual or localized shifts in con- tion wells exist in the field in 2016 (over 500 injection wells tour orientation. Most notably are possible northeast-southwest in the past) (Utah Division of Oil, Gas and Mining oil and gas trending faults in the southwest corner of section 18, T. 40 S., database). Both fresh and produced water are used. The EOR R. 24 E., and in section 29, T. 40 S., R. 25 E. (figure 5). Hydro- waterflood programs at Greater Aneth field units using vertical thermal (saddle) dolomite, intense brecciation, doubly termi- wells will ultimately recover 8% to 30% of the OOIP or ap- nated quartz, and other evidence of faulting are present in core proximately 230 million BO (37 million m3), whereas primary from the Desert Creek zone in the Aneth Unit No. E-418 well recovery was about 200 million BO or 15% to 25% of the OOIP (NW1/4SW1/4SW1/4 section 18, T. 40 S., R. 24 E.) (Chidsey (Babcock, 1978a, 1978b, 1978c, 1978d; Peterson, 1992). and Eby, 2014). However, the northeast-southwest strike of these potential faults as seen on the structure contour map do Carbon dioxide flooding, through a water-alternating-gas not match the known structural northwest-southeast trend of (WAG) program, began in the McElmo Creek Unit in 1985 (fig- other, deeper faults in the area. For example, three-dimensional ure 3). Production increased in unit wells between one and two (3-D) seismic specifically of Greater Aneth field shows base- years. The Devonian Ouray Formation and Mississippian Lead- ment faults of Mississippian and Pennsylvanian age that strike ville Limestone, at McElmo Dome field on the eastern edge of northwest-southeast (Mike Tryggestad, formerly with Resolute the Paradox Basin in southwest Colorado, supply CO2 to Great- Natural Resources, verbal communication, 2009). Also, the un- er Aneth field (and Permian Basin fields) via an 8-inch pipeline usual northeast-striking faults do not appear in structure con- (figure 1). A pilot CO2 flood using horizontal wells (lateral) was tour maps of overlying strata such as the DeChelly and Navajo conducted in the eastern part of the Aneth Unit in 1998. Sandstones, and therefore, are likely localized structures with minimal displacement. The postulated fault near the Aneth Unit Extensive and successful horizontal drilling programs have No. E-418 well could be a potential migration pathway for CO2 been conducted in Greater Aneth field. These drilling pro- between the Ismay and Desert Creek reservoirs, but since the grams were carried out primarily in the Aneth (in 1996) and fault does not appear to extend outside of the Paradox Forma- Ratherford (in 1994) Units in the northwest and southeast tion, the risk of leakage into overlying strata is small. parts of the field, respectively (figure 3). Northwest-southeast- directed horizontal wells in the Desert Creek zone, perpen- The Gothic shale within the Aneth Unit ranges from 7 to 26 dicular to the fault/fracture zones, have successfully increased feet (2–8 m) thick and thins to the southeast (figure 6), indicat- production in these units (Amateis, 1995). ing slightly shallower water to the southeast during the time of deposition; regional mapping of the Gothic shows thicknesses Production in the Aneth Unit had declined by 50% over the ranging from 2 to 70 feet (0.6–21 m) (Chidsey, 2016). An area past 20 years as the waterflood operations and horizontally of very thin shale (4 to 6 feet [1.2–1.8 m]) occurs in section drilled wells have matured. Primary recovery was 58.4 mil- 23, T. 40 S., R. 24 E., which is coincident with a thickened lion BO (15%) and secondary recovery from waterflooding interval in the Desert Creek zone. This indicates that the shale was 76.7 million BO (20%), respectively, of the estimated 386 was likely deposited on a high-relief carbonate buildup. We be- 6 Utah Geological Survey M-12B 1 19 M-11 42-31 M-09 10-F 11-F M-330 M-130 ? L-12 6-F L-10 12-F L-230 31-31 L-430 L 419L 33-31-C 24-31 2 1 6 7-F 22-31 K-11 K-131 K-330 K-130 15 J-12 5-F 13-31 J-231 J-430 9-F 11-31 J-230 16 R. 25 E. I-11 I-12 136 1 H- H-125H-125H-125H-125 H-425 H-325H-325H-325 H-225H-225H-225 H-424H-424 H-224H-224 H-12 2 2 G-325X G-425G-425 2525 G-236 G-325 G-136 G-424 G-225 G-324 G-125G-125G-125G-125 R. 24 E. G-12 1 F136 G-11 F-225F-225F-225F-225F-225 F-424 F-236F-236 F-324 F-425F-425 F-125F-125 23-13 F-224 F-325 22-13 24-13 F-12 B-2 E-425 E-225 E-136 E-325E-325E-325 E-236 E-125 E-313 E-124E-124 E-324 E-224 E-213 E-413 E-424 14-12 H-426H-426 H-423 H-326H-326H-326H-326H-326H-326 H-323 H-335 H-414 1 H-235H-235 H-135 H-226H-226 H314X H-123 H-314 H-223 H-126H-126H-126H-126H-126 H-114H-114 H214 H-411H-411 H-435 6 223 G-126X G-426 G-226 G-135 G-326G-326G-326G-326G-326 G-126 G-423 G- G-323 G-123G-123G-123 G-414 G-314 G-214 G-411G-411 G-114G-114G-114G-114G-114G-114G-114G-114 F-235F-235 F-435F-435 F214SE F-426 F-123 F-326F-326F-326F-326F-326 F-323 F-126F-126F-126F-126F-126F-126F-126 F-226F-226 F-423 F-314 F-223 F-214 F-311F-311 F-414 F-114F-114F-114F-114F-114 F-411 3 E-335 -226 E-135E-135 E-426 E-326 E E-411 E-223 E-123E-123 E-314E-314E-314E-314E-314E-314 E-126E-126E-126E-126E-126E-126 E-42 E-414 E-214E-214E-214E-214E-214E-214 E-323 E-114 122 H-427 H-234H-234 H-127H-127H-127H-127H-127 H-227H-227H-227H-227H-227 H-215H-215 H-422H-422 H-122H- H-410 H-315H-315H-315 H-322 H-222 H-434 H-415 2- X G-327 G-134 G-32 G-215 34-C-3 G-422 G-127G-127 G-122 G-315G-315 G315X G-115 G-222 G-322 G-415 315 315F- F-434F-434 F-115F-115 F-227 F-422F-422 F-322 F215 F-222 F-122 F- F-127 F415 E-222E-222 E-127E-127 E-322E-322 E-122 E-415 E115 E-422E-422 E-315 E-215E-215E-215 14-1014-10 33-D4 H-228 H-321 H-128 H-221 H-416 H-316 H-421H-421 H-216 H-121 H-409 H116 5X 15 5 G-316 G-321X G-121X G-128 G-421 G-221 G-416 G221X 32-16 G-116 G-309 F-121 F-421 F-228F-228 F-316 F-221 F-128 F-416 F-216 F-409 F-116 F-321 E121I 4 E-321E-321 E-128 E-416 E-421 - 209 209E E-221 E-216 E-409 E-209E- E-116 E-309 E-316 H-220H-220 H-229H-229 H-420 H-320 H129 H-417H-417 H-408 H-120 H-120X H-208 H-308 H-217H-217 H-317 H-117 1 G-129 G-420 G-417 G-320 G-120G-120 G-317 G-329G-329 G-217 G-220 G-308 G-117 G-108G-108G-108 G-208 G-408 30 F-417F-417 F-420 F-317 F-220F-220F-220 F-120 F-229F-229 F-320 F-208 F-408 F-217F-217 F129 F-117 F-308 E-320 E-129 E-120E-120 E-417 E-220 E-317 E-420 E-117 E-308 E-217 E-408 E-208E-208 H-419H-419 H119 H-319 H-219 H-318 H-418 H-407 H-218 H-118 H-207 H-307 G-118 G-219 G418 G-319 G-318 G218 G-119G-119 G-407 G-307G-307 G-207G-207 ? 31 6 F-219 F-319 F-118 F-119 F-218 F-407 F-418 F-407 F-207 F307 F-318 E407SE E218I E118I E-119E-119 E-319 1 E-407 E-207E-207 E-318 E-218 E-418 E-307 E-118 1.0 mile E-107 E407 D213I D-412 1.0 km D113SE D-124 D-413 D-113 D-213 D-312 D-212 D-313 ? C-313SE C-213 C-312 C-124 C-413 C-313C-313 C-412 C-113 C-112C-112 C113LDVL R. 23 E. R. 24 E. 36 1 B-413 B-313 B-213 B-113 B-312B-312 0 B-401 B412 2

0 A-412 A-413

A-124A-124 A-213 A-113 A-313 -740

D-414

D-123 D-314

D-311 -760 D-214 D-114D-114

-780 C-314 -800 C-414

C-223C-223 C-214 C-114

C314LDVL C-411 -820 -840

B-123B-123

1 -860

B-314B-314

B-114 B-214

-880 -900

A-414 A-214 -920 A-114

Possible Fault Abandoned Water Injector Location Only Oil Well Hole Dry Injection Well Service Well Water Alt. Gas Injection Hole, with Dry Show of Oil Hole, with Dry Show of Gas Abandoned Oil Well Shut-in Oil Well Plugged Injection Shut-in Water Injector Bottom-hole Location Structure contours on the top of the Gothic shale, Aneth Unit, Greater Aneth field. Aneth Unit shown by red outline; note the location of the Aneth Unit No. H-117 well well H-117 No. Unit Aneth the of location the note outline; red by shown Unit Aneth field. Aneth Greater Unit, Aneth shale, Gothic the of top the on contours Structure -940

Explanation ? WELL SYMBOLS 2 -960

Contour Interval = 20 feet

-980

(Well status as of September 1, 2009) -1000 T. 40 S. T. Figure 5. 40 S., R. 24 E.). (black box in NE1/4NE1/4 section 17, T. The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 7 M-12B 1 19 M-11 42-31 M-09 10-F 11-F M-330 M-130 12 L- 6-F L-10 12-F L-230 L-430 31-31 33-31-C L 419L 2 1 7-F 22-31 24-31 K-11 K-131 K-330 K-130 15 5-F J-12 13-31 J-231 J-430 9-F 11-31 J-230 16 R. 25 E. I-11 I-12 1 H-136 H-125H-125H-125H-125 H-425 H-325H-325H-325H-325H-325 H-225H-225H-225H-225H-225H-225H-225H-225 H-424H-424 H-224H-224 2 2 G-325X G-425G-425 2525 G-236 H-12 G-325 G-136 G-424 G-225 G-324 G-125G-125G-125G-125 1 F136 G-11 F-424 F-225F-225F-225F-225F-225 G-12 F-236F-236 F-324 F-425F-425 F-125F-125 23-13 F-224 F-325F-325F-325F-325F-325 22-13 24-13 B-2 E-425 E-225 F-12 E-136 E-325E-325E-325 E-236 E-125 E-313 E-124E-124 E-324 E-224 E-213 E-413 E-424 14-12 6H- 326 H-426H-426 H-423 H-326H-326H-326H-326H-32 14 H-323 H-335 H-414 H-435 1 H-235H-235 H-135 H-226H-226 H-123 H-314 H-223 H-126H-126H-126H-126H-126 H-114H-114 H2 H-411H-411 6 G-126XG-126XG-126XG-126XG-126XG-126X 314 G-226 G-426 G-135 G-326G-326G-326G-326G-326 G-126 G-423 G-223 G-323 G-123G-123G-123 G-414 G- G-214 G-411G-411 G-114G-114G-114G-114G-114G-114 F-235F-235 F-435F-435 F214SE 311 F-426 F-123 F-326F-326F-326F-326F-326 F-323 F-126F-126F-126F-126F-126F-126F-126 F-226F-226 F-423 F-314 F-223 F-214 F-311F- F-414 F-114F-114F-114 F-411 E-335 E-135E-135 E-426 E-326 E-226 E-411 E-223 E-123E-123 E-314E-314E-314E-314E-314E-314 E-126E-126E-126E-126E-126E-126 E-423 E-414 E-214E-214E-214E-214E-214E-214 E-323 E-114 H-434 H-234H-234 H-127H-127H-127H-127H-127 H-427 H-227H-227H-227H-227H-227 H-215H-215 H-422 H-122H-122 H-410 H-315H-315H-315 H-322 H-222 H-415 G-327 G-134 G-322-X G-215 34-C-3 G-422 G-127G-127 G-122 G315X G-115 G-222 G-322 G-415 315F-315 F-422 F-434F-434 F-115F-115 F-227 F-322 F215 F-222 F- F-122 F-127 F415 E-222E-222 -215 215E E-127E-127 E-322E-322 E-122 E-415 E115 E-422E-422 E-315 E-215E- 14-1014-10 33-D4 H-228 H-321 H-128 H-221 H-416 H-316 H-421H-421 H-216 H-121 H-409 H116 15 5 5X G-316 G-321X G-121X G-128 G-421 G221X G-221 G-416 32-16 G-116 G-309 F-121 F-421 F-228F-228 F-316 F-221 F-128 F-416 F-216 F-116 F-321 F-409F-409 E121I 4 E-321E-321 E-128 E-416 E-421 E-221 E-216 E-409 E-209E-209E-209 E-116 E-309 E-316 08 H-220H-220 H-229H-229 H-420 H-320 H129 H-408 H-417H-417 H-120 H-120X H-308 H-2 H-217H-217 H-117 H-317 G-129 G-420 G-320 G-120G-120 G-317 G-329G-329 G-417 G-217 G-220 G-308 G-117 G-108G-108G-108 G-208 G-408 30 F-420 F-417F-417 F-317 F-220F-220F-220 F-120 F-229F-229 F-320 F-208 F-408 F-217F-217 F129 F-117 F-308 E-320 E-129 E-120E-120 E-417 E-220 E-317 E-420 E-117 E-408 E-308 E-217 E-208E-208 H-419H-419 218 H119 H-319 H-219 H-418 H-318 H-407 H- H-118 H-207 H-307 G-118 G-219 G418 G-319 G-318 G-407 G218 G-119G-119 G-307G-307 G-207G-207 6 31 F-219 F-319 F-118 F-119 F-218 F-407 F-207 F307 F-418 F-318 E407SE E218I E118I E-119E-119 E-319 1 E-207E-207 E-318 E-218 E-307 E-118 E-107 E-407 R. 24 E. 1.0 mile E-418 412 E407 D213I D- D113SE 1.0 km D-124 D-413 D-213 D-113 D-312 D-212 D-313 C-313SE C-213 C-312 C-124 C-413 C-313C-313 C-412 C-113 C-112C-112 C113LDVL R. 23 E. 36 1 B-413 B-313 B-213 B-113 B-312B-312 B-401 0 B412 2 A-412

A-413 A-124A-124 A-213

A-113 0 A-313

D-414 24 D-123 D-314

D-311 D-214 D-114D-114

22 20

C-314

C-223C-223 C-414 C-214 C-114

C314LDVL 18 C-411

16 B-123B-123 14

B-314B-314

B-114 B-214

12 10

Thickness of the Gothic shale, Aneth Unit, Aneth Greater field. Aneth Unit shownred by outline; note the location of the Aneth Unit well No. H-117 A-414 A-214 8 A-114

Abandoned Water Injector Location Only Oil Well Hole Dry Injection Well Service Well Water Alt. Gas Injection Hole, with Dry Show of Oil Hole, with Dry Show of Gas Abandoned Oil Well Shut-in Oil Well Plugged Injection Shut-in Water Injector Bottom-hole Location 6

WELL SYMBOLS Explanation

Contour Interval = 2 feet 4 2 (Well status as of September 1, 2009) Figure 6. 40 S., R. 24 E.). (black box in NE1/4NE1/4 section 17, T. T. 40 S. T. 8 Utah Geological Survey

lieve that the integrity of the seal of the Desert Creek is unaf- and diagenetic factors defining the seal. In the Gothic shale, fected by this area of thin Gothic shale. The two wells located in seemingly subtle variations in mineralogical character, ce- SE1/4 section 23 penetrated the thinnest section of Gothic but mentation, or depositional environment result in important have produced 226,505 BO and 1,023,549 BO from the Des- changes in seal capacity or result in mechanical boundaries. ert Creek, respectively (Utah Division of Oil, Gas and Mining, These subtle differences in turn control fracture spacing, dis- 2017b), implying the presence of a high-quality seal. In addi- tribution, orientation, and conductivity. tion, much of the overlying lower Ismay and uppermost Des- ert Creek zones throughout the Aneth Unit are non-reservoir The Gothic shale strata consist of a fairly monotonous interval rock (widespread low-permeability carbonates and siltstones) of dark brown to dark gray, faintly wavy laminated, calcareous and provide secondary seals, as do anhydrite intervals common mudstone (figure 8B). Variable amounts of terrigenous quartz, laterally in the upper Desert Creek itself away from the produc- chert, feldspar, micas, illitic and chloritic clays, phosphate, tive limits of Greater Aneth field (Peterson, 1992; Chidsey and some carbonaceous material, and fossil fragments are pres- others, 1996; Chidsey and Eby, 2014). ent in this core. Both megafossils and microfossils are present (transported and indigenous) including calcareous bivalve General Core Description mollusks and ostracods, inarticulate brachiopods, phosphatic conulariids, conodonts, arenaceous foraminifera, and possible When most of the development drilling of Greater Aneth field spores of indeterminate origin. Diagenetic products include occurred during the 1950s and 1960s, the goal of coring opera- abundant pyrite and varying amounts of rare to common do- tions was to acquire core from the Desert Creek reservoir, not lomite/ankerite. Modest amounts of clay microporosity likely the overlying Gothic shale. However, core from the Aneth Unit exists, but the permeability is in the nannodarcy range. No. H-117 well (SW1/4NE1/4NE1/4 section 17, T. 40 S., R. 24 E., figure 4) contains nearly a complete (16 feet [4.9 m]), The basal portion of the Gothic shale appears to be the most unslabbed section of Gothic shale (figures 7 and 8); this core organic rich, containing a total organic content (TOC) of and other Greater Aneth cores are publicly available at the 4.4%, whereas the section above contains less than 3% TOC Utah Core Research Center (UCRC) in Salt Lake City, Utah. (table 1). Here a flooding event transgressed over older mot- This core is ideal for detailed representative analysis of the tled carbonates with possible subaerial pisolitic character. In Gothic seal for the Desert Creek reservoir in the Aneth Unit. some instances, the basal mudstone appears to have eroded Comprehensive geological description of core is essential to the underlying limestones, depositing a basal lag rich in bi- define lithologic units and, in combination with petrological valve mollusks. Above this basal lag, the lower portion of analysis, provides the fundamental mineralogical, textural, the Gothic contains a wider assemblage of phosphatic con-

Figure 7. Core (unslabbed) of the Gothic shale from the Aneth Unit No. H-117 well. Scale bars = 2 feet (showing tenths of a foot increments). The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 9

stituents—conodonts, conulariids, and indistinct (fish) frag- Only two other Aneth Unit cores currently stored at the ments, as well as pyrite throughout the section. UCRC penetrated part of the Gothic shale—the Aneth Unit No. E-418 well (NW1/4SW1/4SW1/4 section 18, T. 40 S., R. Most of the depositional environments for the Gothic shale 24 E.) and Aneth Unit No. 27-C-3 well (NW1/4SE1/4 sec- in the Aneth Unit No. H-117 core were the same low-energy, tion 18, T. 40 S., R. 24 E.). These wells are located 2 miles offshore marine typically described elsewhere in the Para- (3.2 km) west-southwest and 3.5 miles (5.6 km) southeast, dox Basin. Deep-water conditions were dysaerobic to anox- respectively, from the Aneth Unit No. H-117 well. The cores ic. The quartz silt in some intervals also represents the clas- were examined for this study (for detailed core descriptions tic influx redeposited from the source to the west-southwest and core photographs see Chidsey and Eby, 2014) and show observed elsewhere in the Paradox Basin of Utah, where or little lateral lithologic variability in the Gothic from what when water depths were shallower and the shoreline closer. was observed in the Aneth Unit No. H-117 core.

5376

539,461 BO, 382,585 MCFG, 2,242,245 BW

A 5378.5

5381

5383.5

5372.8 ft

5386

5388.5

5391

Cored 5393.5 Interval

Explanation Mottled Carbonates Shale or Mudstone-Calcareous Wackestone

Carbonaceous Ostracod 5571.8 ft Conodont Partially Filled Vertical Fracture Conularioid Pelmatozoan Erosion Surface Phosphatic Microfossil Pyritic Mottled Shell Fragment Perforations * Utah Division of Oil, Gas and Mining, 2017. Pisolitic Stylolitic Wavy Lamination

Figure 8. Aneth Unit No. H-117 well. A. Interpreted geophysical log; vfs - very fine sand cs - coarse sand cored interval of the Desert Creek zone and Gothic shale shown in fs - fine sand vcs - very coarse sand red. B. Gothic shale core description. ms - medium sand gran - granule 10 Utah Geological Survey

Table 1. Basic geochemical measurements from the Gothic shale in the Aneth Unit No. H-117 well.

As-Received Depth 1 2 3 4 5 6 7 8 9 Bulk Density TOC S1 S2 S3 Tmax HI OI S2/TOC PI Calc R (ft) o (g/cc) 5379.40 2.570 2.89 2.09 6.45 0.73 445 224 25 72 0.24 0.85 5382.80 2.561 2.81 2.16 5.97 0.64 451 213 23 77 0.27 0.96 5386.90 2.572 2.23 1.93 5.15 0.84 444 231 38 87 0.27 0.83 5390.80 2.522 4.42 2.39 9.46 0.76 449 214 17 54 0.20 0.92

1TOC = total organic carbon (wt.%) 2S1 = amount of free hydrocarbons in the sample (mg HC/g rock) 3S2 = amount of hydrocarbons generated by pyrolytic degradation of kerogen (mg HC/g rock) 4 S3 = amount of CO2 (mg CO2/g rock) produced during pyrolysis of kerogen 5 Tmax = temperature (ºC) of maximum release of hydrocarbons from cracking of kerogen during pyrolysis 6HI = hydrogen index, the ratio of the amount of hydrogen relative to the amount of organic carbon present in a sample; (S2/TOC) x 100 7OI = oxygen index, the ratio of the amount of oxygen relative to the amount of organic carbon present in a sample; (S3/TOC) x 100 8PI = production index, the ratio of already generated hydrocarbons to potential hydrocarbons; S1/(S1 + S2) 9 Calc Ro = calculated vitrinite reflectance (%)

Geochemistry

In the Colorado part of the Paradox Basin, the Gothic shale produces hydrocarbon shale gas. To understand the Gothic’s effec- tiveness as a seal, a full understanding of any hydrocarbon potential as well as the long-term reactivity of organic content with CO2 is required. Meaningful estimates of shale gas-in-place reserves—and subsequent deliverability of this gas—require ac- curate formation evaluation. These data are obtained by measuring the volume and rate of gas released by laboratory isotherm adsorption measurements. Lost gas analysis is then made to esti- mate original gas-in-place. Gas analysis and geochemical characterization provide fundamental complementary information for gas composition, organic content, kerogen type, and kerogen maturity. The following tests were conducted on the Aneth Unit No. H-117 core: (1) programmed pyrolysis (Rock-Eval™), (2) total organic component analysis, (3) calculated vitrinite reflectance, and (4) adsorption isotherms (tables 1 and 2).

In the Aneth Unit No. H-117 core, the Gothic shale has a TOC between 2.2% and 4.4%. The content of free hydrocarbons (gas and oil, S1) in the Gothic ranges from 1.9 to 2.4 mg/g, and the amount of hydrocarbons generated through thermal cracking of nonvolatile organic matter (S2) ranges from 5.2 to 9.5 mg/g. The Figure 9. Kerogen type determination of the Gothic shale from TOC and programmed pyrolysis data. The data indicate amount of CO (in milligrams CO per gram of rock) produced 2 2 the Gothic contains type II and mixed type II/III kerogen. The during pyrolysis of kerogen (S3) ranges from 0.6 to 0.8 mg/g, hydrogen index (HI) represents the amount of hydrogen relative and has important implications for geologic storage of CO2 in to the amount of organic carbon present in a sample. It is a ratio the underlying Desert Creek zone, briefly discussed later. Kero- determined by the formula: HI = (S2/TOC) x 100, where S2 is gen type determination from TOC and programmed pyrolysis the amount of hydrocarbons (HC) generated by the pyrolytic data shows the Gothic contains type II and mixed type II-III degradation of kerogen (mg HC/g rock) and TOC is the total organic carbon, in grams. The oxygen index (OI) represents kerogen (figure 9), whereas kerogen quality analysis suggests the amount of oxygen relative to the amount of organic carbon it is gas prone (figure 10). Types II and III will generate oil and present in a sample. It is a ratio determined by the formula: OI = gas, respectively. Isotherm methane adsorption and Langmuir (S3/TOC) x 100, where S3 is the amount of carbon dioxide (CO2 ) measurements (table 2 and figure 11) show gas versus pressure produced during pyrolysis of kerogen (mg CO2 /g rock) and TOC to evaluate adsorbed and interstitial gas content. Gas content is the total organic carbon, in grams. The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 11

Table 2. Methane adsorption isotherm for the Gothic shale at 5390.8 feet (1643.1 m), Aneth Unit No. H-117 well. See figure 11 for gas versus pressure plots of methane adsorption data.

Dry Basis TOC = 4.42%

Sample Weight = 224.61 g As-Received Moisture = 1.35% Particle Size = < 12 Mesh Temperature = 121.0ºF (49.4ºC)

Methane Adsorption

Pressure Gas Content (Dry Basis) (psia) (MPa) (scf/ton) (scc/gm) 37 0.26 6.9 0.22 75 0.52 12.1 0.38 124 0.85 17.7 0.55 201 1.39 25.5 0.80 287 1.98 32.8 1.02 376 2.59 40.2 1.25 471 3.25 45.0 1.40 561 3.87 49.0 1.53 662 4.56 51.2 1.60

Langmuir Coefficients VL = 89.1 * PL / (PL + 475.7)

PL VL (Dry Basis) (psia) (MPa) (scf/ton) (scc/gm) 475.7 3.28 89.1 2.8

Figure 10. Kerogen quality determination of the Gothic shale from total organic carbon (TOC) and programmed pyrolysis data. The data indicate the Gothic contains gas-prone kerogen. 12 Utah Geological Survey

Dry Basis Temperature = 121.0oF (49.4oC) As-Received Moisture = 1.35% V = 89 P / (P + 476)

Dry Basis Temperature = 121.0oF (49.4oC) As-Received Moisture = 1.35% P/V = 0.0112 P + 5.33

Figure 11. Methane adsorption for the Gothic shale, sample from 5390.8 feet (1643.1 m), Aneth Unit No. H-117 well. A. Methane adsorption isotherm. B. Adsorption Langmuir plot. Volume (V) = standard cubic feet per ton (scf/ton); pressure (P) = pounds per square inch absolute (psia). The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 13

ranges from 6.9 to 51.2 standard cubic feet per ton (0.22–1.60 intervals was used to define clay composition and clay scc/gm) at pressures from 37 to 662 psia (0.26–4.56 MPa). expandability, and to build log correlations. Certain shale lithofacies can only be verified by XRD analysis. XRD X-ray fluorescence (XRF) and X-ray diffraction (XRD) results from bulk and oriented (clay fraction dominant) analyses were also performed on the Gothic core. XRF samples are shown on figure 12. All data are referenced to data for 2-foot (0.6 m) intervals over the length of the the magnitude of the quartz peak. Offsets are imposed on core (seven samples) show averages of 41% silicon diox- the data for the purpose of comparison. The bulk analysis ide, 26% calcium oxide, 10% aluminum oxide, 7% iron (powder) plot (left) shows the consistency of mineralogi- oxide, 5% magnesium oxide, 4% potassium oxide, and cal composition over the range of the core. The indistinct 3% sulfur trioxide plus various small amounts of trace ox- illite peak is consistent as are the strong quartz, calcite, ides. Semi-quantitative XRD analysis from five selected and dolomite peaks. The individual sample plots (right),

Bulk Samples

Figure 12. Graph of X-ray diffraction data from the Gothic shale, Aneth Unit No. H-117 well. 14 Utah Geological Survey

except for the sample from 5377 feet (1639 m), illustrate throat characterization. Thin-section and SEM analyses the difference between the glycol-treated samples and non- show the Gothic shale contains abundant carbonates and treated samples. Glycol is used only to enhance the peaks clays combined with substantial cementation/compaction of clay minerals, particularly smectites. XRD analysis of creating a high-quality seal. the glycol-treated samples in some cases resulted in a defi- nite illite peak whereas in other cases increased the existing Two other techniques used are laser scanning confocal illite peak. For example, the non-treated plot for the sample microscopy (LSCM) and backscattered electron imaging from 5391 feet (1643 m) shows only a slight hint of an illite (BSE). LSCM is a technique for obtaining high-resolution peak; however, the glycol-treated sample shows a small but optical images with depth selectivity. The key feature of distinct illite peak. The other samples show well-defined, confocal microscopy is its ability to acquire in-focus images non-glycol-treated illite peaks that are enhanced when they from selected depths, a process known as optical sectioning. were treated with glycol, especially the sample from 5393 Images are acquired point-by-point and reconstructed with feet (1644 m). In all cases the presence of a small percent- a computer, allowing 3-D reconstructions of topologically age (approximately 10%) of illite as well as chlorite and complex objects. For opaque specimens this is useful for expandable clays (smectites) is inferred. surface profiling (Fredrich, 1999). The BSE is a technique for obtaining high-resolution electron images that show Petrography compositional contrast and structural details (De Winter and others, 2009). Backscattered electrons have higher energies Petrographic analysis of the Gothic shale of the Aneth Unit than secondaries and are produced when electrons from the No. H-117 core reveal four principal lithotypes: (1) argil- primary beam are "bounced" back out of the sample by elas- laceous shale, (2) argillaceous mudstone (mudstone by defi- tic collisions with atoms. The number of electrons a given nition lacks the fine laminations or fissility of shale though material backscatters is proportional to the mean atomic having the same texture and composition), (3) silty calcare- number of the component elements. Materials composed of ous-argillaceous mudstone, and (4) phosphatic argillaceous larger, heavier atoms backscatter more electrons, producing mudstone (Mary Milner, formerly with TerraTek – A Sch- brighter gray tones in the images than less dense materials lumberger Company, written communication, 2009). Al- (differences in average atomic mass of 0.1 amu can be re- though micropores and fractures are present, these lithotypes solved). Backscattered electrons thus produce an image that provide an excellent seal for the hydrocarbons in the Desert is related to material composition, providing both spatial and Creek reservoir below. Argillaceous shale and mudstone de- chemical information on mineral and organic matter distri- posited in offshore marine environments are the best seals, bution. Additional details on BSE methods and Gothic shale whereas the shallow, nearshore silt-rich mudstones tend to examples are provided in Heath and others (2011). be more brittle. The silt-rich mudstones are thin compared to the argillaceous shale and mudstone lithotypes, but because Argillaceous Shale of their brittle nature they have potential for shale-gas and shale-oil production in the region (Chidsey, 2016). Finally, Argillaceous shale in the Gothic shale shows weak lamina- hydrocarbons generated in the Gothic may have charged tions defined by micas and compacted cherty microfossils adjacent, isolated porous dolomite units in the lower Ismay (figure 13A). Shale contains silt-sized calcite particles. The (Bereskin and others, 2010). argillaceous shale matrix also supports dispersed, medium silt grains and compacted cherty microfossils. Such forms Petrographic Methods are characteristic throughout this interval of Gothic shale, and commonly indicate microcrystalline quartz as a matrix Thin-section and scanning electron microscope (SEM) cement. Reflected ultraviolet (UV) light display swarms of analyses are fundamental to petrological description. intercrystalline micropores (figure 13B). SEM images of Thin-section analyses of Gothic shale samples were used argillaceous shale display distinct grain orientation (figure for petrological description of the lithofacies and to estab- 13C). Compacted packets of clays are the main textural lish a baseline correlation of petrophysical properties re- feature, separated by planar parting surfaces. The clay-rich lated to the geologic/petrologic descriptions. They served matrix hosts numerous micropores; authigenic pyrite is as a screening tool for important seal-parameter investi- ubiquitous. Shale matrix has wavy parting planes between gations such as diagenetic alteration, cementation, and clay packets (figure 13D). Replaced microfossils are lined fracture fills. SEM analysis involves high-magnification with kerogen residue. Matrix clays are likely illite and/or imaging of small, representative samples, and is used to mixed layer illite-smectite. The matrix also shows unal- identify clay morphology, kerogen location, and pore- tered and altered carbonaceous material (figure 13D). The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 15

A B

C D

Figure 13. Argillaceous shale lithotype in the Gothic shale from 5382.8 feet (1640.7 m), Aneth Unit No. H-117 well. A. Photomicrograph of argillaceous shale lithotype showing weak laminations defined by micas and compacted cherty microfossils (white, lower right) (plane light). Pink specks in the matrix are stained, silt-sized calcite particles. B. Reflected UV light with rhodamine filter showing a compacted cherty microfossil (grain at center) in the argillaceous shale matrix and swarms of orange pinpoints that indicate intercrystalline micropores. Brighter fluorescence inside the microfossil is attributed to mineral fluorescence.C. SEM overview of argillaceous shale highlighting distinct grain orientation. D. SEM matrix detail showing unaltered and altered carbonaceous material. The smooth particle at lower right (uo) represents a discrete carbonaceous grain with little alteration. At top center, a particle representing a different class of organics, embedded between clay flakes (ao), displays an unclear, rough texture. 16 Utah Geological Survey A Argillaceous Mudstone

Argillaceous mudstone lithotypes in Gothic shale show a clay matrix supporting a few elongate chert stringers (figure 14A). These likely represent microfossils, scattered pyrite, and silt, as well as silt-sized calcite crystals. Pyrite is concentrated parallel to bedding (figure 14B). The SEM overview of this texture shows uniform, non-laminated argillaceous shale (figure 14C). A few siliceous and calcareous fragments float in a matrix of crenulated clays. LSCM images of a surface perpendicular to bedding in argillaceous mudstone show topography in corresponding oblique and map views on figure 15. The map view shows green, yellow-orange, and red fluorescing material at different magnifications. Red material is typically spherical and probably co-located with pyrite framboids. Green fluorescing material is the most abundant organic material, reflective of a primary depositional process that distribut- B ed the organic material. BSE images of argillaceous mudstone show the presence and distribution of pyrite, dolomite, calcite, smectite, illite, chlorite, and plagioclase (figure 16).

B C

Figure 14. Argillaceous mudstone lithotype in the Gothic shale from 5379.4 feet (1639.6 m), Aneth Unit No. H-117 well. A. Photomicrograph of argillaceous mudstone shown at low Figure 15. Medium magnification of corresponding LSCM images of magnification (plane light). The magenta lines at the bottom of a surface broken perpendicular to bedding in the Gothic shale from the image are induced stress-release fractures. B. Same image 5380.0 feet (1638.8 m), Aneth Unit No. H-117 well. A. Image showing as 14A at slightly higher magnification. Black streaks are pyrite topography in an oblique view. B. A relatively high-resolution image concentrated parallel to bedding. C. SEM overview of texture in of green, yellow-orange, and red fluorescing material. uniform, non-laminated argillaceous mudstone. The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 17

A Silty Calcareous-Argillaceous Mudstone Silty calcareous-argillaceous mudstone consists of finely disseminated carbonaceous material and abundant silt grains (figure 17A). The dominant textural components in the matrix are quartz silt, silt-sized calcite, mica flakes, and authigenic pyrite, which “float” in a predominantly clay matrix (figure 17B). SEM images of calcareous-argillaceous mudstone confirm the presence of many calcite particles and quartz silt grains. Cement-coated clay flakes preserve the microporous structure (figure 17C). Elongate pores are parallel to parting planes. The micropore network consists of pores having sizes from 2 to 10 microns, which are flattened in shape. Carbonaceous material is often preserved and commonly associated with pyrite (figure 17D). Intercrystalline porosity developed through alteration of organics.

Phosphatic Argillaceous Mudstone B Phosphatic argillaceous mudstone is a typical component of the Gothic shale. Flattened, amalgamated phosphate pellets are common (figure 18A). Phosphatic argillaceous mudstone also includes compacted chert, siliceous fossils, detrital micas, and flattened pellets in a mixed siliceous/argillaceous matrix with a siliceous cement component (figures 18B). Significant and abundant micropores may also be present within this matrix. Micropores appear under UV light (figure 18B). SEM images of phosphatic, argillaceous mudstone show the clay packets that make up the matrix are separated along parting surfaces, contributing to a fissile texture (figure 18C). Flattened phosphatic/organic pods have granular internal textures along horizontal parting planes (figure 18D). BSE images of phosphatic argillaceous mudstone show pyrite, dolomite, calcite, quartz, smectite, and illite/ smectite (figure 19). C Analysis of Natural Fractures

Fractures that could connect Desert Creek reservoir rock through the Gothic shale are a potential concern for hydrocarbon and CO2 leakage. Fracture analysis includes the evaluation of natural and induced fracture systems, fracture orientation (vertical, inclined, or horizontal), and mineral composition of fracture fill. Typical tabulated data from the fracture analysis include general fracture type, fracture dip orientation, type of mineral fill, type of oil stain, apparent fracture dip, fracture porosity, fracture spacing, and fracture intensity. Fractures present in the Gothic will be an important factor in CO2 containment. Natural fractures in the Aneth Unit No. H-117 core include three individual inclined shear fractures or fracture zones and one horizontal shear fracture. Fractures are slickensided and partially mineralized. Figure 16. Backscattered electron images of the Gothic shale from 5387.1 feet (1642.0 m), Aneth Unit No. H-117 well, from low (A) to Flat, horizontal disc fractures were observed in the Gothic medium (B), to high magnification (C), showing various mineral shale. These fractures are induced during the drilling process constituents (cal = calcite, dol = dolomite, plg = plagioclase, il = and exhibit a radial plume pattern indicating there is likely not illite, chl = chlorite, sm = smectite, py = pyrite). a large differential stress. Disc fractures that have plumes with 18 Utah Geological Survey

A B

C D

Figure 17. Silty calcareous-argillaceous mudstone lithotype in the Gothic shale from 5386.9 feet (1641.9 m), Aneth Unit No. H-117 well. A. Photomicrograph of silty calcareous-argillaceous mudstone with induced fracture at the top of the image (magenta) (plane light). Finely disseminated carbonaceous material is visible in the matrix, as are abundant silt grains, calcite crystals (pink), and pyrite. Note cherty microfossil at bottom of image. B. Photomicrograph showing matrix detail highlighting dominant textural components (plane light). Quartz silt, silt-sized calcite (red), mica flakes, and authigenic pyrite float in a predominantly clay matrix.C. This medium magnification SEM view of the matrix shows elongate pores parallel to parting planes (arrows). The micropore network is also visible, consisting of voids with sizes from 2 to 10 microns, and flattened in shape.D. Image illustrates a common association of pyrite with carbonaceous material. The perforated flakes of organics (o) surround pyrite crystals (py). Intercrystalline porosity (arrows) is believed to have developed through alteration of organics. The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 19

A B

C D

Figure 18. Phosphatic argillaceous mudstone lithotype in the Gothic shale from 5390.8 feet (1643.1 m), Aneth Unit No. H-117 well. A. Photomicrograph (plane light) of overview showing flattened, amalgamated pellets (lighter brown), which SEM show to be phosphatic. The matrix overview highlights compacted siliceous forms (white) composed of chert, and flattened pellets in a mixed siliceous/argillaceous matrix. The lighter brown matrix color and abundance of siliceous fossils, as well as phosphatic pellets suggest a siliceous matrix cement component. B. Closer view showing microfossils, micas, a pellet (pe) and a conodont (co) supported by argillaceous matrix under reflected UV light. Note the matrix micropores appearing as bright orange dots. Dull orange is mineral fluorescence. (Reflected UV light with zcrhodamine filter).C. Medium magnification SEM view of phosphatic, argillaceous mudstone. Clay packets that make up the matrix are separated along parting surfaces, contributing to a fissile texture. The sample splits easily along closely spaced (<1 mm), brittle, wavy partings. The boxed area is enlarged in the image 18D. D. SEM detail of part of the image 18C highlighting two flattened phosphatic/organic pods (po) with granular internal texture arranged along horizontal parting planes (arrows). 20 Utah Geological Survey

A significant directionality are indicative of high differential stresses; this was not observed in these cores. The plumes on the disc fractures do not seem to be exceptionally asymmetric, sometimes without orientation and without a strongly defined axis of propagation. These characteristics usually suggest that the present-day horizontal stress anisotropy is not strong, and therefore, hydraulic fractures in the formation could be divert- ed by larger fracture systems and structural heterogeneities. A limited number of inclined disc fractures suggest that the stress axes are not aligned with present-day gravity; however, we infer that these are likely caused by the influence of local bedding deformation rather than stress realignment.

Inclined shear fracture zones (figure 20), possible permeability pathways, are undulous and contain multiple fracture surfaces; overall dip ranges from 30° to 44°. Slickenlines rake obliquely across the dip of the shear planes, and are probably B parallel on successive planes. They suggest significant horizontal tectonic compression at some point during the geologic history of the strata. These sub-horizontal shear planes were observed in both the Gothic shale and upper Desert Creek zone. The inference is that this may be a zone of incipient or limited displacement.

Thin sections and LSCM images reveal both extension and shear fractures (figure 21). Dilational jogs and crack-seal textures are visible in the images. Maximum principal compressive stress is vertical and the sense of shear is dextral.

Fluorescent organics are co-located with mineralization in fractures. Microprobe analysis indicates that carbonates and sulfates dominate fracture mineralization (see BSE images on figure 21). Fracture mineralization contains microporosity and does not show strong crystal orientation. Vertical fractures are extensional. Cross-cutting relationships be- C tween vertical and subhorizontal shear fractures could not be discerned; perhaps the mineralization occurred synchro- nously in the two types of fractures.

This evaluation shows that organic material is co-located with fracture mineralization, as well as in the argillaceous mudstone (figure 15), in the Gothic shale. Organics and carbonate might be affected geochemically by CO2-rich fluids. Within the matrix, micropores, and fractures, CO2 generated from within the Gothic or as part of the CO2-rich fluid phase migrating from the Desert Creek reservoir may cause (1) organics to become mobilized on a microscale/molecular scale, (2) carbonates to dissolve, (3) creation of new fractures, or (4) the precipitation of the carbon-bearing mineral dawson- ite (NaAlCO3(OH)2). These processes would be dependent on the temperature, pressure, and other conditions within the Gothic and Desert Creek. Figure 19. Backscattered electron images of the Gothic shale from 5392.4 feet (1643.6 m), Aneth Unit No. H-117 well, from low (A) to medium (B), to high magnification (C), showing various mineral Induced dehydration features/fractures are not present in the constituents (cal = calcite, dol = dolomite, q = quartz, i/s = illite/ Aneth Unit No. H-117 core. However, if they are present else- smetite, sm = smectite, py = pyrite). where in the Gothic shale the potential exists for creation of The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 21

fracture zones if separate or dissolved phase CO2 can affect surface forces of the clay particles and their expanded versus collapsed texture (Andreani and others, 2008). No fractures connecting the Desert Creek reservoir from which CO2-rich fluids could migrate into the Gothic shale were observed in the Aneth Unit cores.

Petrophysical Properties

Shales are heterogeneous and strongly anisotropic. Sampling along the entire Gothic core interval was of fundamental importance for analysis of any future hydraulic fracturing (that could be required for later CO2 storage) containment from the Desert Creek zone below.

Basic Reservoir Parameters Figure 20. Inclined shear fracturing (various views) with slickensides in the Gothic shale core, 5392.5 feet (1643.6 m), Aneth Unit No. H-117 well Petrophysical measurements were conducted to determine (shown in the detailed images, on figure 21, generated from an assortment the density, porosity, permeability, saturations (gas, oil, and of microscopic techniques). water), and bound water of the Gothic shale (table 3) (Chid- sey, 2016). These measurements are fundamental for seal capacity, as well as gas-in-place and gas productivity evalu- ations for potential gas shale reservoirs. The tests character- ize the gas-filled and the effective porosities, the fluid saturations including mobile hydrocarbons (such as condensates), and the “as received” matrix permeability to gas. Pressure decay permeability measures to 10 nanodarcy accuracy under reservoir net confining stress conditions and permits effective permeability to be measured at residual fluid pressure without moving fluid in the pore system.

Porosity ranges from 2.7% to 3.4% and pressure-decay permeability is no greater than 0.000146 mD. These and other basic matrix petrophysical parameters indicate the Gothic shale is a highly effective reservoir seal.

Mercury Injection Capillary Pressure and Pore Aperture Distributions

Figure 21. Inclined shear fracture zone from 5392.30 to 5392.50 feet The seal capacity of the Gothic shale—the CO column (1643.57–1643.63 m) (core shown on figure 20) displayed on various 2 heights retained by capillary pressure—was quantified by backscattered electron (BSE), crossed-polars thin section photomicrograph (XPL), and laser scanning confocal microscopy (LSCM) images at different mercury injection capillary pressure measurements to under- magnifications derived from the thin section shown on the left. stand and predict variations in seal capacity. Capillary pres-

Table 3. Summary of petrophysical measurements from the Gothic shale, Aneth Unit No. H-117 well.

As As Gas Filled Bound Dry Porosity Water Gas Mobile Oil Bound Pressure- Received Received Porosity Hydrocarbon Depth Grain (% of Saturation Saturation Saturation Clay Water Decay Bulk Grain (% of Saturation (ft) Density Bulk (% of Pore (% of Pore (% of Pore (% of Bulk Permeability Density Density Bulk (% of Bulk (g/cm3) Volume) Volume) Volume) Volume) Volume) (mD) (g/cm3) (g/cm3) Volume) Volume)

5379.40 2.570 2.623 2.648 3.35 19.55 60.61 19.84 2.03 1.14 6.56 0.000146

5382.80 2.561 2.597 2.621 2.72 24.73 50.88 24.39 1.38 1.33 7.01 0.000133

5386.90 2.572 2.615 2.649 3.51 30.07 47.71 22.22 1.67 0.90 7.42 0.000138

5390.80 2.522 2.573 2.614 4.30 36.18 46.05 17.77 1.98 1.47 7.46 0.000141 22 Utah Geological Survey

sure data applications used in our study included (1) determi- A nation of pore throat size distribution, and (2) cap rock–seal Depth Range of Directional Plugs capacity analysis to predict the height of CO2 and hydrocarbon columns that can be retained by the seal. 5378–5393 ft Horiontal Vertical The Gothic shale has very high seal capacity based on mercury injection capillary pressure and pore aperture distributions analysis (figure 22A and 22B). These data show that clay content and high carbonate cementation and/or compaction lead to small pore throat diameters. The Gothic shale should support very large CO2 or hydrocarbon columns (1500 to 2600 feet [500–860 m]). The sample (the outlier) with the highest seal capacity was from the depth of 5378 feet (1639 m). Heath and others (2011) provide mercury intrusion porosity saturation curves and cumulative and incremental volumetric pore- density distribution curves for the Gothic (and other seals). Compared to other seals in their study, the Gothic shale curves have the highest pressure values for corresponding mercury 1 1 1 1 1 1 saturations and the highest breakthrough pressure.

Heath and others (2011) also summarized the frequencies of B Gothic pore throat areas and equivalent circular radii from the Depth Range of connected pore networks, pore body volumes, and ratios of Directional Plugs pore throat to pore body equivalent circular radii. Peak fre- 5378–5393 ft quencies occur for the smallest values for pore throat area, Horiontal radii, and pore body volume, indicating that most of the con- Vertical nections in the pore networks are controlled by the smallest pore throats (Heath and others, 2011).

Geomechanics

Rock mechanic tests were performed to assess the variability of elastic properties and in situ stresses. Shales, in particular, are strongly heterogeneous and anisotropic, and thus their elastic properties are different in the vertical and horizontal directions. This contrast in elastic properties is not directly measured by geophysical well logs, but can have a dominant impact on pre- dictions of in situ stress. Therefore, the evaluation of anisotropic material properties and the in situ stress throughout the core (for example, in situ stress variations with respect to reservoir units and seals) is of fundamental importance. In situ stress analysis of the Gothic shale was conducted to obtain a reasonable profile Figure 22. Mercury injection capillary pressure and pore aperture of the in situ stress tensor (magnitude and orientation). In situ distributions. A. Cumulative mercury saturation versus injection pressure. B. Mercury saturation versus pore-aperture diameter. All test data and stress analysis and mechanical property measurements provide graphs are available from the Utah Geological Survey project files. fundamental data for evaluation of fracture containment when the Desert Creek reservoir below is hydraulically fractured for CO2 storage. Multistress anisotropy measurements are summarized in table 4 (Chidsey, 2016). plays vertical dynamic Young’s modulus as a function of vertical static Young’s modulus (A) and horizontal dynamic Young’s Young’s Modulus and Poisson’s Ratio modulus as a function of horizontal static Young’s modulus (B).

Young’s modulus is a measure of the stiffness of an isotropic Poisson’s ratio compares the contraction or transverse strain elastic material. It is defined as the ratio of the uniaxial stress (normal to the applied load) to the extension of axial strain (in over the uniaxial strain in the range of stress in which Hooke’s the direction of the applied load). Figure 24 displays vertical Law holds. Young’s modulus is the ratio of stress, which has dynamic Poisson’s ratio as a function of vertical static Pois- units of pressure, to strain, which is dimensionless; therefore, son’s ratio (A) and horizontal dynamic Poisson’s ratio as a Young’s modulus itself has units of pressure. Figure 23 dis- function of horizontal static Poisson’s ratio (B). The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 23

Table 4. Summary of multistress anisotropy measurements from the Gothic shale, Aneth Unit No. H-117 well.

AR Bulk Effective Young's Young's Poisson's Poisson's Shear Modulus – Depth (ft) Orientation Density Mean Stress Modulus – Modulus – Ratio – Ratio – Transverse (psi) (g/cm3) (psi) Transverse (psi) Axial (psi) Transverse Axial 5381.20 V 2.568 1994 2.897E+06 5.680E+06 0.186 0.274 1.156E+06 5381.20 45 2.569 1994 2.926E+06 5.648E+06 0.167 0.268 1.164E+06 5381.15 H 2.574 1994 2.913E+06 5.849E+06 0.161 0.273 1.126E+06 5398.80 V 2.283 1994 3.516E+06 3.601E+06 0.191 0.191 1.503E+06 5399.00 45 2.316 1994 3.466E+06 3.638E+06 0.179 0.181 1.458E+06 5398.75 H 2.258 2004 3.597E+06 3.475E+06 0.148 0.150 1.470E+06 Note: transverse – perpendicular to bedding plane, axial – parallel to bedding plane

y = 2.0512E+00x R2 = 0.99

y = 1.6597E+00x R2 = 0.95

Figure 23. Young’s modulus plots; depth 5381.18 to 5398.85 feet (1643.23–1645.57 m), Aneth Unit No. H-117 well. A. Vertical dynamic Young’s modulus as a function of vertical static Young’s modulus. B. Horizontal dynamic Young’s modulus as a function of horizontal static Young’s modulus. 24 Utah Geological Survey

y = 1.0507E+00x R2 = 1.0

y = 1.0045E+00x R2 = 1.0

Figure 24. Poisson’s ratio plots; depth 5381.18 to 5398.85 feet (1643.23–1645.57 m), Aneth Unit No. H-117 well. A. Vertical dynamic Poisson’s ratio as a function of vertical static Poisson’s ratio. B. Horizontal dynamic Poisson’s ratio as a function of horizontal static Poisson’s ratio. The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 25

These graphs and analysis from Young’s modulus and Pois- and gas from carbonate reservoir rocks in the Desert Creek son’s ratio suggest that the Gothic shale in the Aneth Unit is zone of the Pennsylvanian (Desmoinesian) Paradox Forma- not brittle. Therefore, the Gothic is less likely to respond to tion. Greater Aneth field is divided into four drilling units. The hydraulic fracturing of the underlying Desert Creek zone. Aneth Unit is located in the northwestern part of the field. Production in the Aneth Unit had declined by 50% over the Compressional Testing past 20 years as the waterflood operations and horizontally drilled wells have matured, but has improved due to a rela- Figure 25A is a plot of axial stress difference versus radial and tively recent CO2 flood program. The Greater Aneth field has axial strains, measured during unconfined compression test- produced over 483 million BO of the estimated 1100 million ing. The plot shows the evolution of rock deformation (that is, bbls of OOIP within the field; the Aneth Unit has produced axial and radial strains) and failure (that is, yield stress, peak more than 160 million BO of the estimated 386 million barrels stress, and residual strength, when available) during uncon- of OOIP within the unit (Babcock, 1978a; Utah Division of fined compression loading. Figure 25B is a plot of axial stress Oil, Gas and Mining, 2017a). The large amount of remaining difference versus volumetric strain, measured during uncon- oil at Greater Aneth field (and in the Aneth Unit in paricular) fined compression testing. The plot shows the evolution of the made it ideal to demonstrate both EOR by CO2 flooding and rock deformation (dilation versus compaction) and the yield CO2 storage capacity. stress during unconfined compression loading. Axial stress difference versus axial strain, measured during unconfined The Gothic shale within the Paradox Formation is the pri- compression testing, is displayed on figure 25C. The plot mary seal for the Desert Creek reservoir in Greater Aneth shows the evolution of the axial modulus (Young’s modulus) field. Geochemical, petrological, petrophysical, and geome- during unconfined compression loading. The averaged radial chanical analyses determined the (1) geologic controls on strain versus axial strain, measured during unconfined com- sealing effeciency, (2) effects of pressure changes on seal pression testing, is shown on figure 25D. The plot shows the efficiency due to CO2 injection and storage, and (3) chemical evolution of the transverse modulus (Poisson’s ratio) during interaction between CO2 and the seal at its contact with the unconfined compression loading. reservoir through time. The major findings of these analyses are as follows. High-resolution, continuous strength profiling provides a continuous unconfined compressive strength (UCS) measurement • The Gothic shale is an effective seal above the Des- along the length of the Aneth Unit No. H-117 core to determine ert Creek reservoir, despite micropores and frac- the rock heterogeneity, assess fracture density (if fractures tures. The Gothic ranges in thickness from 7 to 26 were present), and provide quantitative data to locate zones of feet (2–8 m), averaging 15 feet (4.6 m) thick. The potential weakness in the Gothic shale. A continuous strength lateral extent and shape of the underlying Desert profile was conducted on the Gothic using the TerraTek TSI™ Creek carbonate buildup complex is reflected as scratch test system. The system consists of a moving cart with elevated areas on the structural map of the top of a sample holder and a loading fixture capable of “scratching” the Gothic. The integrity of the seal is unaffected in the rock sample and measuring the horizontal force (in the areas of thin Gothic shale based on high cumulative cutting direction) and the vertical force (normal to the cutting oil production from wells there. In addition, much surface) under conditions of constant depth of cut (0.5 mm) of the overlying lower Ismay and uppermost Desert and constant cut velocity (5 mm/second). The UCS profiles Creek are non-reservoir rock. along the core show a relatively uniform homogenous Gothic shale package ~20,000 psi (137,900 kPa) (figure 26). A few • The core from the Aneth Unit No. H-117 well is an fractures, likely induced, show up as distinct shifts on the pro- excellent representation of the Gothic shale. The files. Compressional testing suggests the potential for some Gothic core is a remarkably uniform mudstone-shale degree of hydraulic fracture containment. The relatively high with grain size ranging between clay and silt depos- UCS indicates that throughout the geologic past the Gothic ited in low-energy, deep-water offshore marine to has been able to withstand “high loads” without sustaining shallow, nearshore environments. The quartz silt in significant natural fractures. Thus, the Gothic would likely some intervals is from a source to the west-south- also withstand the impact of hydraulic fracturing should it be west. Accessories and biological constituents consist conducted in the Desert Creek zone below. of ubiquitous authigenic pyrite, microfossils, shell fragments, conodonts, and conulariids. The other few cores in the Aneth Unit that include the Gothic SUMMARY AND CONCLUSIONS show little lateral variability from what was observed in the Aneth Unit No. H-117 core. Greater Aneth oil field, Utah’s largest oil producer, is a mature, major western U.S. oil field. Located in the Paradox Ba- • The Gothic may also be a self-sourcing shale-gas sin of southeastern Utah, Greater Aneth is a stratigraphic trap, or oil-shale reservoir. Total organic carbon ranges with minor fractures and small faults. The field produces oil from 2.2% to 4.4% with type II kerogen. Hydro- 26 Utah Geological Survey

Figure 25. Results of unconfined compression testing.A. Axial stress difference versus radial and axial strains. B. Axial stress difference versus volumetric strain. The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 27

Figure 25 continued. C. Axial stress difference versus axial strain. D. Averaged radial strain versus axial strain. 28 Utah Geological Survey Figure 26. Continuous unconfined compressive strength(red profile line in psi [no scaleprovided]) of the Gothic shalefrom core the Aneth Unit No. well. H-117 Scale bars = (showing tenths of a foot increments). 2 feet The Gothic shale of the Pennsylvanian Paradox Formation, Greater Aneth field, southeastern Utah 29

carbons generated in the Gothic may have also ACKNOWLEDGMENTS charged adjacent, isolated porous dolomite units in the lower Ismay zone. This research was performed under the direction of the New Mexico Institute of Mining and Technology, Brian McPher- • The Gothic consists of four principal lithotypes: son, Project Manager and Principal Investigator, as part of argillaceous shale, argillaceous mudstone, silty cal- the Southwest Regional Partnership on Carbon Sequestra- careous-argillaceous mudstone, and phosphatic ar- tion—Phase II: Field Demonstrations Project. This project gillaceous mudstone. Lithology consists of argilla- was funded by the U.S. Department of Energy through the ceous or calcareous shale and mudstone composed National Energy Technology Laboratory, Contract No. DE- of a clayey to siliceous matrix with weak lamina- FC26-05NT42591. Support was also provided by the Utah tions defined by micas. Within the matrix, calcite Geological Survey (UGS). Sandia is a multi-mission labora- crystals, pyrite, quartz, microfossils, flakes of - or tory operated by Sandia Corporation, a wholly owned subsid- ganics, and swarms of intercrystalline micropores iary of Lockheed Martin Company, for the U.S. Department are common. Argillaceous shale and mudstone, of Energy’s National Nuclear Security Administration under representing the deeper water, offshore marine en- contract DE-ACOC4-94AL85000. vironments are the best seals whereas the minor shallow, nearshore silt-rich mudstone will be more James Parker (deceased) and Cheryl Gustin of the UGS and brittle. However, Young’s modulus and Poisson’s Susan Heath (of New Mexico Tech at the time) prepared ratio analyses suggest that the Gothic shale overall some figures; Michael Laine (retired), Ammon McDonald in the Aneth Unit is not brittle. (now with the Utah Division of Oil, Gas and Mining), and Thomas Dempster of the UGS assisted with sample prepara- • Inclined and horizontal shear fractures or fracture tion and core photography. Geochemical, petrophysical, pe- zones are found in the Gothic shale. Near the base trographic, and geomechanical analyses were conducted by of the Gothic section, vertical to subvertical exten- TerraTek – A Schlumberger Company, Salt Lake City, Utah; sional fractures are present. Mineralization within Sandia National Laboratories, Albuquerque, New Mexico; these natural fractures is most likely dominated by and Poro-Technology, Houston, Texas. carbonates and organics. Fractures that could connect Desert Creek reservoir rock through the Gothic This study was carefully reviewed by David Tabet (retired), shale into the Ismay zone are a low potential con- Craig Morgan, and Kimm Harty (retired) of the UGS; and Samuel M. Hudson of the Department of Geological Sciences, cern for hydrocarbon and CO2 leakage. Brigham Young University. Their suggestions and construc- • Porosity ranges from 2.7% to 3.4% and pressure- tive criticism greatly improved the manuscript. Finally, we decay permeability is no greater than 0.000146 mD. thank Vicky Clarke, Jen Miller, and the UGS editorial produc- These and other basic matrix petrophysical param- tion team for their efforts in producing this publication. eters indicate the Gothic shale to be a highly effective reservoir seal. REFERENCES • The Gothic shale should support very large CO2 or hydrocarbon columns based on mercury injec- Amateis, L.J., 1995, Application of sequence stratigraphic tion capillary pressure and pore aperture distribu- modeling to integrated reservoir management at Aneth tion analyses. Unit, Greater Aneth field, Utah: Society of Petroleum En- gineers, SPE Paper 030534, p. 35–49. • Continuous unconfined compressive strength - pro files show a relatively uniform homogenous shale Andreani, M., Gouze, P., Luquot, L., and Jouanna, P., 2008, package. Compressional testing suggests some de- Changes in seal capacity of fractured claystone caprocks gree of hydraulic fracture containment. induced by dissolved and gaseous CO2 seepage: Geophysi- cal Research Letters, v. 35, p. 6. We conclude that the Gothic shale within the Aneth Unit, Aplin, A.C., and Larter, S.R., 2005, Fluid flow, pore pressure, as well as the entire Greater Aneth field, has provided the wetability, and leakage in mudstone cap rocks, in Boult, P., seal for the hydrocarbons stored in the Desert Creek zone and Kaldi, J., editors, Evaluating fault and cap rock seals: for millions of years. 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