URTeC 1922696 Aptian ‘Shale Gas’ Prospectivity in the Downdip Mississippi Interior Salt Basin, Gulf Coast, USA Paul C. Hackley, Brett J. Valentine, Catherine B. Enomoto, Celeste D. Lohr, Krystina R. Scott, Frank T. Dulong, Alana M. Bove, U.S. Geological Survey Copyright 2014, Unconventional Resources Technology Conference (URTeC)

This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 25-27 August 2014.

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Abstract This study evaluates regional ‘shale gas’ prospectivity of the Aptian section (primarily Pine Island Shale) in the downdip Mississippi Salt Basin (MSB). Previous work by the U.S. Geological Survey estimated a mean undiscovered gas resource of 8.8 trillion cubic feet (TCF) in the chronostratigraphic-equivalent Pearsall Formation in the Maverick Basin of south Texas, where industry has established a moderately successful horizontal gas and liquids play. Wells penetrating the downdip MSB Aptian section at depths of 12,000-15,000 ft were used to correlate formation tops in a 15-well cross-section extending about 200 miles (mi) east-southeastward from Adams Co. to Jackson Co. Legacy cuttings from these wells were analyzed for thermal maturity and source rock quality. Bitumen reflectance (n=53) increases with increasing present-day burial depth in the east-central study area from 1.0% to 1.7%. As the Aptian section shallows in Adams Co. to the west, bitumen Ro values are higher (1.7-2.0%), either from relatively greater heat flux or greater mid-Cenomanian uplift and erosion in this area. Total organic carbon (TOC) content ranges 0.01-1.21 and averages 0.5 wt.% (n=51); pyrolysis output (S2; n=51) averages 0.40 mg HC/g rock, indicating little present-day hydrocarbon-generative potential. Bitumen reflectance is preferred as a thermal maturity parameter as Tmax values are unreliable. Normalized X-ray diffraction (XRD) mineral analyses (n=26) indicate high average clay abundance (53 wt.%) relative to quartz (29%) and carbonate (18%). Mineral content shows a spatial relationship to an Appalachian orogen clastic sediment source, with proximal high clay and quartz and distal high carbonate content. Clastic influx from the Appalachian orogen is confirmed by detrital zircon U-Pb ages with dominant Grenville and Paleozoic components [105 ages from a Rodessa sandstone and 112 ages from a Paluxy (Albian) sandstone]. Preliminary information from fluid inclusion microthermometry (41 aqueous measurements from calcite cements in one argillaceous James Limestone sample) indicates homogenization temperatures (Th) of 120-135°C, consistent with present-day bottom-hole conditions and measured bitumen Ro values towards the western end of the MSB. Downdip in the central MSB, microthermometry (26 aqueous measurements from quartz dust rims in one Paluxy sandstone sample) and measured bitumen Ro values indicate maximum temperatures may have been significantly higher (~25°C) than present-day conditions. High inclusion salinities (15-25 wt.% salt) at both locations suggest interaction of pore fluids with evaporites. Mercury injection capillary pressure (MICP) analyses (n=3) indicate porosity ranges 1.3-2.1% and permeability 0.006-0.02 µD for Pine Island and Rodessa shales. Overall, results from this work indicate generally poor ‘shale gas’ prospectivity compared to other shale reservoirs based primarily on depth, low organic content, low porosity, and high clay content. However, thickness and thermal maturity are appropriate, moderate reservoir pressures are present, and petroleum systems modelling by others has indicated high undiscovered gas potential for the basin as a whole. Introduction Domestic natural gas production from shale reservoirs is forecast to grow over 100% in the years 2011-2040 and will ultimately fulfill fifty percent of United States production (U.S. Energy Information Administration, 2013). The U.S. Geological Survey (USGS) is tasked with estimation of undiscovered shale gas resources and is actively engaged in research efforts to support this mission (U.S. Geological Survey, 2007). However, in many areas

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previously unconsidered for shale gas prospectivity, such as the downdip Mississippi Salt Basin (MSB), key parameters such as thermal maturity, organic richness, and reservoir thickness (e.g., Curtis, 2002) are sparse or unavailable. Aptian strata are current industry targets for unconventional development in the Maverick Basin of south Texas, where a mean undiscovered gas resource of 8.8 trillion cubic feet (TCF) was estimated by the USGS for the Pearsall Formation (Dubiel et al. 2011). Thermal maturity reaches the dry gas window in the Aptian of south Texas (Hackley, 2012) and decreases updip towards the outcrop. Reconnaissance studies of the Aptian section across the greater Gulf of Mexico Basin showed that the Aptian section was immature or only marginally mature for hydrocarbon generation in most locations, with the exception of the downdip MSB (Enomoto et al., 2012). Valentine et al. (in press) evaluated thermal maturity in the downdip MSB via detailed bitumen reflectance analysis; results of their study are summarized herein. Overall, the Mesozoic section in the central and eastern Gulf coastal plain has high potential for gas resources as interpreted from previous petroleum systems modeling by Mancini et al. (2008). The current study provides an overview of new data necessary to assess shale gas prospectivity in the Lower Cretaceous (Aptian) Pine Island Shale in the southern MSB, and rates the reservoir on the ‘shale scorecard’ of Miller (2014), and in the ‘shale reservoir properties’ ternary diagram of Ottman and Bohacs (2014). These ratings indicate poor overall prospectivity for the Pine Island Shale in the downdip MSB as an unconventional reservoir. Geologic Setting and Stratigraphy The MSB extends from southwestern Alabama to northeastern Louisiana and is characterized by salt diapir and pillow structures formed from the underlying Jurassic Louann Salt (Figure 1).

The Aptian section includes the Sligo Formation (Hauterivian at base), Pine Island Shale, James Limestone, and the Rodessa Formation (Albian at top) (Figure 2). These units and their chronostratigraphic equivalents were deposited throughout the northern Gulf of Mexico Basin on a stable rimmed carbonate shelf during tectonic quiescence in the

Figure 1. Study area showing well sample locations. From Valentine et al. (in press).

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Early Cretaceous (Yurewicz et al., 1993). In Mississippi, sediment influx diluted the carbonate system and proximal clastic rocks grade downdip basinward into carbonates on the outer shelf. The Sligo Formation consists of shallow marine sandstones and shales deposited in shoreface and proximal shelf environments (Devery, 1982). The overlying Pine Island Shale consists of dark gray and black shales interbedded with minor limestone (Goddard, 2001). The James Limestone, a fossiliferous limestone (shelf) and dense micrite (deeper waters) formed during

recommencement of carbonate deposition over Pine Island Shale (Forgotson, 1963). The overlying Rodessa is comprised of interbedded clastics and limestone with some anhydrite deposited in semi-restricted lagoonal environments (Nunnally and Fowler, 1954; Forgotson, 1963; Dinkins, 1969). The James and Pine Island are not continuously present in Mississippi and in some locations the Rodessa directly overlies the Sligo (Dockery, 1996). Methods Fifteen wells crossing the southern MSB from southeast-northwest (Figure 1) were sampled (primarily cuttings) from the Aptian section at the Mississippi Core Repository in Jackson, MS, in 2012. Samples ranged in depth from 13,320-16,440 ft. A limited number of Aptian core samples also were collected in 2013. Cuttings were high-graded for analysis by selecting dark-gray to grayish black fragments. Samples were analyzed by Rock-Eval II and Leco total organic carbon (TOC) at Weatherford Laboratories by methods described in Barker (1974) and Espitalié et al. (1977). X-ray diffraction (XRD) of low temperature ash residues was performed at USGS via techniques described in Hosterman and Dulong (1989). Bitumen reflectance (Ro) at USGS was according to ASTM (2013). Three core samples were evaluated via fluid inclusion petrography and microthermometry at Fluid Inclusion Technologies, Inc. by standard techniques (e.g., Sheperd et al., 1985). Mercury injection capillary pressure analyses were by

Figure 2. Cretaceous stratigraphic column for the downdip Mississippi Salt Basin. From Valentine et al. (in press).

Figure 3. Histogram of total present-day organic carbon values for Aptian samples in the Mississippi Salt Basin. From Valentine et al. (in press).

Figure 4. Ternary plot of XRD mineralogy for Aptian samples in the MSB. From Valentine et al. (in press).

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PoroTechnology, Inc. (Shafer and Neasham, 2000). Detrital zircon U-Pb analyses by laser ablation ICP-MS were at A2Z, Inc., according to standard techniques (e.g., Gehrels, 2012). Results The Pine Island Shale is present at depths of 12,000-15,000 ft below surface across southern Mississippi. Wireline electric logs show the Pine Island is approximately 100-400 ft thick, whereas a James Limestone interval of 100-200 ft is discontinuous and not present in all wells correlated for this study (n=24). The James was identified by a more negative spontaneous potential (SP) and higher resistivity log values whereas the Pine Island was identified by higher SP and lower resistivity. Pine Island cuttings had a gross lithology of 70-90% gray to medium-dark gray to black lime mudstone and siltstone, with 10-30% of cuttings consisting of light-gray to yellow, green, and red lime mudstone and siltstone. TOC content (Figure 3) of high-graded cuttings ranges 0.01-1.21 wt.% and averages 0.5 wt.% (n=51). S2 ranges from 0.14-2.33 mg HC/g rock, averaging 0.40, indicating little present-day hydrocarbon generative potential (Valentine et al., in press). Only 11 pyrolysis analyses had reasonable Tmax values, presumably due to low TOC content. The pyrolyzable carbon is interpreted to reside almost exclusively in solid bitumens, based on organic petrographic analysis. Organic carbon is presumed to be insoluble native pyrobitumen which thermally decomposes during pyrolysis to non-volatile char. Because Tmax is unreliable, the pyrolysis approach to characterizing thermal maturity in these mature-overmature organic-lean rocks is discounted. Valentine et al. (in press) summarized the results of detailed organic petrography and bitumen reflectance analyses (n=53), showing Aptian thermal maturity increases with burial depth into the wet gas/condensate window on the eastern side of the MSB (Ro 1.0-1.25%), but continues to increase into the dry gas window as the section shallows on the Adams County structural high on the west side of the MSB (Ro 1.7-2.0%). This is presumed due to either relatively greater heat flux or greater mid-Cenomanian uplift and erosion on the western margin of the MSB. Organic matter content predominantly is solid bitumen with subordinate amounts of inertinite and vitrinite. Cuttings and core samples analyzed by XRD show a clear distinction between shale and limestone units in the Aptian section (Valentine et al., in press). Normalized quartz, carbonate and clays (Figure 4) shows mean quartz content of Pine Island and Rodessa shales of 29 wt.% compared to 20 wt.% in the James Limestone. Normalized carbonate averages 46 wt.% in the James compared to 18 wt.% in the shales with clay content of 34 wt.% compared to 53 wt.% in carbonates and shales respectively. Other minerals (e.g., pyrite <10 wt.%; feldspar <5 wt.%) are present in minor concentrations and the average non-normalized sum of clays plus carbonate plus quartz was 94 wt.%. The clear shale/limestone distinction in the average normalized compositions occurs despite that the most shaly sections from James Limestone core were sampled. Clay mineral composition is dominated by illite with minor contributions from chlorite, kaolinite and traces of a mixed layer illite/smectite clay in 3 samples, consistent with high maturity (Frey, 1987). Mineral content shows a spatial relationship to an Appalachian orogen clastic sediment source, with proximal high clay and quartz updip and distal high carbonate content downdip (Figure 5).

Figure 6. Thin section of Pine Island Shale in crossed polars. QTZ = quartz; FLD = feldspars

Figure 5. Spatial variation in XRD mineralogy.

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Limited thin section observation confirms mineralogy determined by XRD for Pine Island Shale. Figure 6 shows a shale thin section in crossed polars, illustrating the clay-rich matrix with disrupted quartz- plus feldspar-rich laminations. Traces of sulfide, terrestrial organoclasts, and heavy minerals also are present. In order to help constrain sediment origin and dispersal patterns two samples from the MSB were collected for detrital zircon U-Pb analysis. For a discussion of detrital zircon U-Pb analyses and their use in sedimentary provenance studies see Park et al. (2010). A Rodessa Formation sandstone sample collected updip in the MSB, near the Jackson Dome, from the Helmerich and Payne #1-25 Loper well at 10,372-10,373’ (Figure 7) shows a dominant Grenville crustal source. Farther downdip, detrital zircons from a Paluxy Formation sandstone in the Humble Oil and Refining #1 Knoxo G.U. 2 at 12,532-12,534' show a dominant Paleozoic component. As a cursory first-pass interpretation of this limited dataset, the Rodessa sample may have been sourced from a primarily Taconic provenance whereas the Paluxy sample has a signature more indicative of an Acadian source.

Limited fluid inclusion microthermometry data from 2 samples shows differences in burial and hydrocarbon migration history dependent on location in the MSB. Towards the western end of the MSB, fluid inclusion microthermometry (41 aqueous measurements from calcite cements in one argillaceous James Limestone sample) indicates homogenization temperatures of 120-135°C, consistent with present-day bottom-hole conditions and measured bitumen Ro values, suggesting this sample is at maximum burial depth. No hydrocarbon inclusions were observed. Downdip in the central MSB, microthermometry on a Paluxy sandstone sample (26 aqueous measurements from quartz dust rims) and measured bitumen Ro values indicate maximum temperatures were significantly higher (~25°C) than present-day conditions. These data suggest that significant uplift has occurred in this location in the downdip MSB. Some white-fluorescent, 38-41° gravity oil inclusions are present in low

Figure 7. Relative age frequency distributions for detrital zircons in two MSB samples.

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abundance in the Paluxy sample, suggesting a migration event. High inclusion salinities (15-25 wt.% salt) at both locations suggest interaction of pore fluids with evaporites. Limited MICP analyses (n=3) on non-extracted samples indicate porosity ranges 1.3-2.1% and permeability 0.006-0.02 µD for Pine Island and Rodessa shales. This places the Pine Island Shale at the low end of the porosity range for shales and below the average of 3.9% (n=2,400) in the Olson and Grigg (2008) dataset of North American shales. Permeability values of 0.006-0.02 µD place the Pine Island among the tighter reservoirs measured in the Olson and Grigg (2008) study, which identified reservoirs with average permeability <0.1 µD as ‘permeability-challenged.’ Shale Gas Prospectivity The objective of this study and the work of Valentine et al. (in press) was to generate new data and information which can be used to address shale gas prospectivity of the Pine Island Shale in the south MSB. Below, the Pine Island Shale is rated via the ‘shale scorecard’ of Miller (2014) and its properties are graphically illustrated in the ‘shale reservoir properties’ ternary diagram of Ottman and Bohacs (2014). It should be noted that our work is preliminary, based on a limited number of analyses from a non-representative sample set, and is subject to update pending the results of ongoing work. Organic richness (0.5 wt.% avg. TOC) is low compared to other shales; for example, Hammes et al. (2011) indicated an average TOC content of 2.8 wt.% in the Haynesville play. Low TOC (<1.0%) is a ‘shale killer’ in the Miller (2014) scorecard (Figure 8).

Thermal maturity is appropriate for thermogenic shale gas, with bitumen Ro values ranging 0.93-2.00 %, for the Aptian section throughout the downdip MSB, similar to other shale plays in the Gulf of Mexico Basin, e.g., the Eagle Ford, Haynesville and Pearsall formations. Gross thickness of the base of Pine Island to top of Rodessa section ranges 630-1,104 ft and averages 767 ft (n=24 interpreted wells; Valentine et al., in press), similar to other shale plays (National Energy Technology Laboratory, 2013). Porosity is low (<2.0%), also a ‘shale killer’ in the Miller (2014) classification. Reservoir pressures in the Aptian interval are variable based on evaluation of mud weights available for 11 of the 15 sampled wells, ranging 0.48-0.75 psi/ft, and averaging 0.53 psi/ft, comparable to other shale plays. Average clay content (53 wt.%) of Pine Island and Rodessa shale samples in this study is high and may negatively impact artificial stimulation techniques which apply best to more brittle quartz and carbonate-rich rocks (Passey et al. 2010). A mineralogy-based brittleness index was calculated based on a modification of the formula of Wang and Gale (2009):

Figure 8. Gas shale scorecard of Miller (2014) for MSB Aptian shales. Gray shading indicates parameter range and score for MSB Aptian shales.

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𝐵𝐼 = (𝑄𝑡𝑧 + 𝐶𝑎𝑟𝑏)/(𝑄𝑡𝑧 + 𝐶𝑎𝑟𝑏 + 𝐶𝑙𝑎𝑦 + 𝑇𝑂𝐶) resulting in overall low average values of 0.47 for Pine Island and Rodessa samples and 0.66 for shaly core and cuttings from the James Limestone. No data are available for the current study on abundance of natural fractures, tectonic stress, or fluid compatibility, which are other important criteria in the Miller (2014) scorecard.

Scoring the MSB Aptian section in the shale reservoir properties ternary (Figure 10) of Ottman and Bohacs (2014) suggests these rocks are poor reservoirs compared to established shale plays, primarily on the basis of low organic and high clay content. The average shale (including shaley facies of James Limestone) of this study plots in the ‘organically-lean claystone’ field, whereas the average reservoir composition of established shale plays is in the ‘organically-rich mudstone’ quadrant. Low organic content and low ‘hardness percentage’ in the MSB Aptian section are partially offset by moderate reservoir pressures, but low porosity and significant depths of 12,000-15,000 ft probably confirm the ‘shale killer’ designation of the Miller (2014) scorecard, based on current technologies and economics. Conclusions Overall, results from this work indicate generally poor shale gas prospectivity for the Aptian section in the downdip MSB. This conclusion is based on low organic content, low porosity, and high clay content. However, thermal maturity is appropriate, the Aptian section is thick with moderate reservoir pressures, and petroleum system modelling by others has indicated high undiscovered gas potential for the basin as a whole. Future work will investigate sediment provenance and burial history in the MSB through specialized analyses (apatite fission track, detrital zircon U-Pb, and fluid inclusion microthermometry) of core samples. This work will help to constrain the timing of hydrocarbon generation, migration, and accumulation for the basin as a whole, improving future assessments of undiscovered conventional and unconventional hydrocarbon resources. Acknowledgments This paper benefited from reviews by Peter Warwick and Matt Merrill of USGS. The authors also thank Jim Coleman (USGS) and David Dockery (Mississippi Office of Geology) for helpful discussions in support of this

Figure 10. Shale reservoir primary properties plot of Ottman and Bohacs (2014) for MSB Aptian shales.

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