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Paul C. Hackley

Publications and source records attributed to Paul C. Hackley.

At least 127 records · Page 7Linked to original sources
USGS2014

Organic petrology of the Aptian-age section in the downdip Mississippi Interior Salt Basin, Mississippi, USA: Observations and preliminary implications for thermal maturation history

This study identifies a thermal maturity anomaly within the downdip Mississippi Interior Salt Basin (MISB) of southern Mississippi, USA, through examination of bitumen reflectance data from Aptian-age strata (Sligo Formation, Pine Island Shale, James Limestone, and Rodessa Formation). U.S. Geological Survey (USGS) reconnaissance investigations conducted in 2011–2012 examined Aptian-age thermal maturity trends across the onshore northern Gulf of Mexico region and indicated that the section in the downdip MISB is approaching the wet gas/condensate window (R o ~1.2%). A focused study in 2012–2013 used 6 whole core, one sidewall core, and 49 high-graded cutting samples (depth range of 13,000–16,500 ft [3962.4–5029.2 m] below surface) collected from 15 downdip MISB wells for mineralogy, fluid inclusion, organic geochemistry, and organic petrographic analysis. Based on native solid bitumen reflectance (R o generally > 0.8%; interpreted to be post-oil indigenous bitumens matured in situ), R o values increase regionally across the MISB from the southeast to the northwest. Thermal maturity in the eastern half of the basin (R o range 1.0 to 1.25%) appears to be related to present-day burial depth and shows a gradual increase with respect to depth. To the west, thermal maturity continues to increase even as the Aptian section shallows structurally on the Adams County High (R o range 1.4 to > 1.8%). After evaluating the possible thermal agents responsible for increasing maturity at shallower depths (i.e., igneous activity, proximity to salt, variations in regional heat flux, and uplift), we tentatively propose that either greater paleoheat flow or deeper burial coupled with uplift in the western part of the MISB could be responsible for the thermal maturity anomaly. Further research and additional data are needed to determine the cause(s) of the thermal anomaly.

International Journal of Coal Geology↗
USGS2014

Geologic assessment of undiscovered oil and gas resources in Aptian carbonates, onshore northern Gulf of Mexico Basin, United States

Carbonate lithofacies of the Lower Cretaceous Sligo Formation and James Limestone were regionally evaluated using established U.S. Geological Survey (USGS) assessment methodology for undiscovered conventional hydrocarbon resources. The assessed area is within the Upper Jurassic–Cretaceous–Tertiary Composite total petroleum system, which was defined for the assessment. Hydrocarbons reservoired in carbonate platform Sligo-James oil and gas accumulations are interpreted to originate primarily from the Jurassic Smackover Formation. Emplacement of hydrocarbons occurred via vertical migration along fault systems; long-range lateral migration also may have occurred in some locations. Primary reservoir facies include porous patch reefs developed over paleostructural salt highs, carbonate shoals, and stacked linear reefs at the carbonate shelf margin. Hydrocarbon traps dominantly are combination structural-stratigraphic. Sealing lithologies include micrite, calcareous shale, and argillaceous lime mudstone. A geologic model, supported by discovery history analysis of petroleum geology data, was used to define a single regional assessment unit (AU) for conventional reservoirs in carbonate facies of the Sligo Formation and James Limestone. The AU is formally entitled Sligo-James Carbonate Platform Oil and Gas (50490121). A fully risked mean undiscovered technically recoverable resource in the AU of 50 million barrels of oil (MMBO), 791 billion cubic feet of natural gas (BCFG), and 26 million barrels of natural gas liquids was estimated. Substantial new development through horizontal drilling has occurred since the time of this assessment (2010), resulting in cumulative production of >200 BCFG and >1 MMBO.

Cretaceous Research↗
USGS2014

Standardization of vitrinite reflectance measurements in shale petroleum systems: How accurate are my Ro data?

Vitrinite reflectance generally is considered the most robust thermal maturity parameter available for application to hydrocarbon exploration and petroleum system evaluation. However, until 2011 there was no standardized methodology available to provide guidelines for vitrinite reflectance measurements in shale. Efforts to correct this deficiency resulted in publication of ASTM D7708-11: Standard test method for microscopical determination of the reflectance of vitrinite dispersed in sedimentary rocks. In 2012-2013, an interlaboratory exercise was conducted to establish precision limits for the measurement technique. Six samples, representing a wide variety of shale, were tested in duplicate by 28 analysts in 22 laboratories from 14 countries. Samples ranged from immature to overmature (Ro 0.31-1.53%), from organic-rich to organic-lean (1-22 wt.% total organic carbon), and contained Type I (lacustrine), Type II (marine), and Type III (terrestrial) kerogens. Repeatability values (difference between repetitive results from same operator, same conditions) ranged from 0.03-0.11% absolute reflectance, whereas reproducibility values (difference between results obtained on same test material by different operators, different laboratories) ranged from 0.12-0.54% absolute reflectance. Repeatability and reproducibility degraded consistently with increasing maturity and decreasing organic content. However, samples with terrestrial kerogens (Type III) fell off this trend, showing improved levels of reproducibility due to higher vitrinite content and improved ease of identification. Operators did not consistently meet the reporting requirements of the test method, indicating that a common reporting template is required to improve data quality. The most difficult problem encountered was the petrographic distinction of solid bitumens and low-reflecting inert macerals from vitrinite when vitrinite occurred with reflectance ranges overlapping the other components. Discussion among participants suggested this problem could not be corrected via kerogen concentration or solvent extraction and is related to operator training and background. Poor reproducibility (0.54% absolute reflectance, related to increased anisotropy?) in the highest maturity sample (Ro 1.53%) suggests that vitrinite reflectance is not a highly reliable parameter in such rocks. Future work will investigate opportunities to improve reproducibility in similar high maturity, organic-lean shale varieties.

Conference Paper↗
USGS2014

U.S. Geological Survey unconventional petroleum systems research in south Mississippi: Observations on burial history and thermal maturity in the Cretaceous

Shale hydrocarbon ‘resource’ plays have revolutionized the United States energy mix over the last 5 years. These plays are diverse in lithology and age but share the common feature of occurring in ‘tight’ formations which require hydraulic (hydro-) fracturing for economic flow rates. In general, economic success requires an organic-rich reservoir with a quartz- or carbonate-rich mineralogy that responds to artificial stimulation by fracturing. The U.S. Geological Survey (USGS) is tasked with estimating the quantity and quality of undiscovered hydrocarbons reservoired in shales. In support of that mission, we began an investigation of unconventional petroleum systems in the southern part of the Mississippi Salt Basin in 2012, building on earlier reconnaissance work that identified this area as potentially prospective for ‘shale’ gas (Enomoto et al., 2012). While our recent studies (Valentine et al., 2014a; Hackley et al., 2014) have suggested poor ‘shale’ gas prospectivity (due to low organic content, low porosity, high clay content, and significant depth), at least for the Aptian section, they also have generated a wealth of new information about thermal maturity in the Cretaceous of south Mississippi. In addition, our work to-date has set the stage for future USGS evaluation of unconventional hydrocarbons reservoired in the Upper Cretaceous Tuscaloosa Marine Shale (TMS). Here, we summarize recent USGS thermal maturity studies in the south Mississippi Salt Basin.

Mississippi↗
USGS2013

Development of web-based organic petrology photomicrograph atlases and internet resources for professionals and students

With advances in web applications, organic petrography and other related disciplines are in need of updated online resources and educational tools to aid professionals and students in the identification and interpretation of macerals. The U.S. Geological Survey (USGS) Organic Petrology Laboratory along with USGS Eastern Energy Resources Science Center Information Technology staff have developed five web atlases containing images of organic matter in geologic materials: 1. an American Society for Testing and Materials (ASTM) Atlas, 2. an Organic Petrology Taxonomy for International Classification (OPTIC) of Coal Macerals Atlas, 3. an Interactive Gulf Coast Photomicrograph Web Atlas (I-Map), 4. an Organic Material in Shales Atlas (Shale), and 5. an interactive Blue/White/Ultraviolet (UV) Light Atlas (Light). Each web atlas contains images of macerals with associated sample and petrographic data collected by the USGS. These webpages will provide means to preserve and circulate petrographic data collected by the USGS for coal and shale samples from all over the world.

International Journal of Coal Geology↗
USGS2013

Thermal maturity of northern Appalachian Basin Devonian shales: Insights from sterane and terpane biomarkers

To better estimate thermal maturity of Devonian shales in the northern Appalachian Basin, eleven samples of Marcellus and Huron Shale were characterized via multiple analytical techniques. Vitrinite reflectance, Rock–Eval pyrolysis, gas chromatography (GC) of whole rock extracts, and GC–mass spectrometry (GCMS) of extract saturate fractions were evaluated on three transects that lie across previously documented regional thermal maturity isolines. Results from vitrinite reflectance suggest that most samples are immature with respect to hydrocarbon generation. However, bulk geochemical data and sterane and terpane biomarker ratios from GCMS suggest that almost all samples are in the oil window. This observation is consistent with the presence of thermogenic gas in the study area and higher vitrinite reflectance values recorded from overlying Pennsylvanian coals. These results suggest that vitrinite reflectance is a poor predictor of thermal maturity in early mature areas of Devonian shale, perhaps because reported measurements often include determinations of solid bitumen reflectance. Vitrinite reflectance interpretations in areas of early mature Devonian shale should be supplanted by evaluation of thermal maturity information from biomarker ratios and bulk geochemical data.

Maryland, New York, Ohio, Pennsylvania, West Virgi↗
USGS2012

Review and update of the applications of organic petrology: Part 1, geological applications

Organic petrology developed as coal petrology at the beginning of the 20th century dedicated mainly to the study of coals because of their utilization in industry. Coal petrology was then considered a branch of coal science. Later, with the development of specialized nomenclature, classification of coal components, and the standardization and improvement of analytical (microscopical) methods, this discipline expanded in interests and name, becoming organic petrology. Organic petrology carries a broader context, being as well a tool applied in the study of dispersed organic matter in sedimentary rocks due to its importance in exploration for fossil fuel resources. At present, organic petrology is a discipline widely recognized for its role in fundamental and applied research with respect to both coal utilization and in geosciences. Throughout the 20th century several important monographs have been published on the discipline of organic petrology, including “Stach's textbook of coal petrology” (1st edition 1935, 2nd 1975, 3rd 1982), updated as the more general “Organic petrology” by Taylor et al. (1998). More recently, the text “Applied coal petrology: the role of petrology in coal utilization” was published by Suárez-Ruiz and Crelling (2008). This review is the first in a two-part review series that describes and updates the role of organic petrology in geosciences. A second part complementing this one and focused on the applications of organic petrology to other scientific fields will follow.

International Journal of Coal Geology↗
USGS2012

Review and update of the applications of organic petrology: Part 2, geological and multidisciplinary applications

The present paper is focused on organic petrology applied to unconventional and multidisciplinary investigations and is the second part of a two part review that describes the geological applications and uses of this branch of earth sciences. Therefore, this paper reviews the use of organic petrology in investigations of: (i) ore genesis when organic matter occurs associated with mineralization; (ii) the behavior of organic matter in coal fires (self-heating and self-combustion); (iii) environmental and anthropogenic impacts associated with the management and industrial utilization of coal; (iv) archeology and the nature and geographical provenance of objects of organic nature such as jet, amber, other artifacts and coal from archeological sites; and (v) forensic science connected with criminal behavior or disasters. This second part of the review outlines the most recent research and applications of organic petrology in those fields.

International Journal of Coal Geology↗
USGS2012

The nature of porosity in organic-rich mudstones of the Upper Jurassic Kimmeridge Clay Formation, North Sea, offshore United Kingdom

Analyses of organic-rich mudstones from wells that penetrated the Upper Jurassic Kimmeridge Clay Formation, offshore United Kingdom, were performed to evaluate the nature of both organic and inorganic rock constituents and their relation to porosity in this world-class source rock. The formation is at varying levels of thermal maturity, ranging from immature in the shallowest core samples to mature in the deepest core samples. The intent of this study was to evaluate porosity as a function of both organic macerals and thermal maturity. At least four distinct types of organic macerals were observed in petrographic and SEM analyses and they all were present across the study area. The macerals include, in decreasing abundance: 1) bituminite admixed with clays; 2) elongate lamellar masses (alginite or bituminite) with small quartz, feldspar, and clay entrained within it; 3) terrestrial (vitrinite, fusinite, semifusinite) grains; and 4) Tasmanites microfossils. Although pores in all maceral types were observed on ion-milled surfaces of all samples, the pores (largely nanopores with some micropores) vary as a function of maceral type. Importantly, pores in the macerals do not vary systematically as a function of thermal maturity, insofar as organic pores are of similar size and shape in both the immature and mature Kimmeridge rocks. If any organic pores developed during the generation of hydrocarbons, they were apparently not preserved, possibly because of the highly ductile nature of much of the rock constituents of Kimmeridge mudstones (clays and organic material). Inorganic pores (largely micropores with some nanopores) have been observed in all Kimmeridge mudstones. These pores, particularly interparticle (i.e., between clay platelets), and intraparticle (i.e., in framboidal pyrite, in partially dissolved detrital K-feldspar, and in both detrital and authigenic dolomite) are noteworthy because they compose much of the observable porosity in the shales in both immature and mature samples. The absence of a systematic increase in organic porosity as a function of either maceral type or thermal maturity indicates that such porosity was probably unrelated to hydrocarbon generation. Instead, much of the porosity within mudstones of the Kimmeridge appears to be largely intraparticle and interparticle (adjacent to inorganic constituents), so the petroleum storage potential in these organic-rich mudstones largely resides in inorganic pores.

International Journal of Coal Geology↗
USGS2012

Organic geochemistry and petrology of subsurface Paleocene-Eocene Wilcox and Claiborne Group coal beds, Zavala County, Maverick Basin, Texas, USA

Coal samples from a coalbed methane exploration well in northern Zavala County, Maverick Basin, Texas, were characterized through an integrated analytical program. The well was drilled in February, 2006 and shut in after coal core desorption indicated negligible gas content. Cuttings samples from two levels in the Eocene Claiborne Group were evaluated by way of petrographic techniques and Rock–Eval pyrolysis. Core samples from the Paleocene–Eocene Indio Formation (Wilcox Group) were characterized via proximate–ultimate analysis in addition to petrography and pyrolysis. Two Indio Formation coal samples were selected for detailed evaluation via gas chromatography, and Fourier transform infrared (FTIR) and 13 C CPMAS NMR spectroscopy. Samples are subbituminous rank as determined from multiple thermal maturity parameters. Elevated rank (relative to similar age coal beds elsewhere in the Gulf Coast Basin) in the study area is interpreted to be a result of stratigraphic and/or structural thickening related to Laramide compression and construction of the Sierra Madre Oriental to the southwest. Vitrinite reflectance data, along with extant data, suggest the presence of an erosional unconformity or change in regional heat flow between the Cretaceous and Tertiary sections and erosion of up to >5 km over the Cretaceous. The presence of liptinite-rich coals in the Claiborne at the well site may indicate moderately persistent or recurring coal-forming paleoenvironments, interpreted as perennially submerged peat in shallow ephemeral lakes with herbaceous and/or flotant vegetation. However, significant continuity of individual Eocene coal beds in the subsurface is not suggested. Indio Formation coal samples contain abundant telovitrinite interpreted to be preserved from arborescent, above-ground woody vegetation that developed during the middle portion of mire development in forested swamps. Other petrographic criteria suggest enhanced biological, chemical and physical degradation at the beginning and end of Indio mire development. Fluorescence spectra of sporinite and resinite are consistent and distinctly different from each other, attributed to the presence of a greater proportion of complex asphaltene and polar molecules in resinite. Gas chromatography of resinite-rich coal shows sesquiterpenoid and diterpenoid peaks in the C 14–17 range, which are not present in resinite-poor coal. Quantities of extracts suggest bitumen concentration below the threshold for effective source rocks [30–50 mg hydrocarbon/g total organic carbon (HC/g TOC)]. Saturate/aromatic and pristane/phytane (Pr/Ph) ratios are different from values for nearby Tertiary-reservoired crude oil, suggesting that the Indio coals are too immature to source liquid hydrocarbons in the area. However, moderately high HI values (200–400 mg HC/g rock) may suggest some potential for naphthenic–paraffinic oil generation where buried more deeply down stratigraphic/structural dip. Extractable phenols and C 20+ alkanes are suggested as possible intermediates for acetate fermentation in microbial methanogenesis which may, however, be limited by poor nutrient supply related to low rainfall and meteoric recharge rate or high local sulfate concentration.

Texas↗
USGS2012

Geological and geochemical characterization of the Lower Cretaceous Pearsall Formation, Maverick Basin, south Texas: A future shale gas resource?

As part of an assessment of undiscovered hydrocarbon resources in the northern Gulf of Mexico onshore Mesozoic section, the U.S. Geological Survey (USGS) evaluated the Lower Cretaceous Pearsall Formation of the Maverick Basin, south Texas, as a potential shale gas resource. Wireline logs were used to determine the stratigraphic distribution of the Pearsall Formation and to select available core and cuttings samples for analytical investigation. Samples used for this study spanned updip to downdip environments in the Maverick Basin, including several from the current shale gas-producing area of the Pearsall Formation. The term shale does not adequately describe any of the Pearsall samples evaluated for this study, which included argillaceous lime wackestones from more proximal marine depositional environments in Maverick County and argillaceous lime mudstones from the distal Lower Cretaceous shelf edge in western Bee County. Most facies in the Pearsall Formation were deposited in oxygenated environments as evidenced by the presence of biota preserved as shell fragments and the near absence of sediment laminae, which is probably caused by bioturbation. Organic material is poorly preserved and primarily consists of type III kerogen (terrestrial) and type IV kerogen (inert solid bitumen), with a minor contribution from type II kerogen (marine) based on petrographic analysis and pyrolysis. Carbonate dominates the mineralogy followed by clays and quartz. The low abundance and broad size distribution of pyrite are consistent with the presence of oxic conditions during sediment deposition. The Pearsall Formation is in the dry gas window of hydrocarbon generation (mean random vitrinite reflectance values, R o = 1.2–2.2%) and contains moderate levels of total organic carbon (average 0.86 wt. %), which primarily resides in the inert solid bitumen. Solid bitumen is interpreted to result from in-situ thermal cracking of liquid hydrocarbon generated from original type II kerogen that was prevented from expulsion and migration by low permeability. The temperature of maximum pyrolysis output ( T max ) is a poor predictor of thermal maturity because the pyrolysis (S2) peaks from Rock-Eval analysis are ill defined. Vitrinite reflectance values are consistent with the dry gas window and are the preferred thermal maturity parameter. A Maverick Basin Pearsall shale gas assessment unit was defined using political and geologic boundaries to denote its spatial extent and was evaluated following established USGS hydrocarbon assessment methodology. The assessment estimated a mean undiscovered technically recoverable natural gas resource of 8.8 tcf of gas and 3.4 and 17.8 tcf of gas at the F95 and F5 fractile confidence levels, respectively. Significant engineering challenges will likely need to be met in determining the correct stimulation and completion combination for the successful future development of undiscovered natural gas resources in the Pearsall Formation.

AAPG Bulletin↗
USGS2012

Geologic assessment of undiscovered conventional oil and gas resources--Middle Eocene Claiborne Group, United States part of the Gulf of Mexico Basin

The Middle Eocene Claiborne Group was assessed using established U.S. Geological Survey (USGS) assessment methodology for undiscovered conventional hydrocarbon resources as part of the 2007 USGS assessment of Paleogene-Neogene strata of the United States part of the Gulf of Mexico Basin including onshore and State waters. The assessed area is within the Upper Jurassic-Cretaceous-Tertiary Composite total petroleum system, which was defined as part of the assessment. Source rocks for Claiborne oil accumulations are interpreted to be organic-rich downdip shaley facies of the Wilcox Group and the Sparta Sand of the Claiborne Group; gas accumulations may have originated from multiple sources including the Jurassic Smackover and Haynesville Formations and Bossier Shale, the Cretaceous Eagle Ford and Pearsall(?) Formations, and the Paleogene Wilcox Group and Sparta Sand. Hydrocarbon generation in the basin started prior to deposition of Claiborne sediments and is ongoing at present. Emplacement of hydrocarbons into Claiborne reservoirs has occurred primarily via vertical migration along fault systems; long-range lateral migration also may have occurred in some locations. Primary reservoir sands in the Claiborne Group include, from oldest to youngest, the Queen City Sand, Cook Mountain Formation, Sparta Sand, Yegua Formation, and the laterally equivalent Cockfield Formation. Hydrocarbon traps dominantly are rollover anticlines associated with growth faults; salt structures and stratigraphic traps also are important. Sealing lithologies probably are shaley facies within the Claiborne and in the overlying Jackson Group. A geologic model, supported by spatial analysis of petroleum geology data including discovered reservoir depths, thicknesses, temperatures, porosities, permeabilities, and pressures, was used to divide the Claiborne Group into seven assessment units (AU) with distinctive structural and depositional settings. The AUs include (1) Lower Claiborne Stable Shelf Gas and Oil (50470120), (2) Lower Claiborne Expanded Fault Zone Gas (50470121), (3) Lower Claiborne Slope and Basin Floor Gas (50470122), (4) Lower Claiborne Cane River (50470123), (5) Upper Claiborne Stable Shelf Gas and Oil (50470124), (6) Upper Claiborne Expanded Fault Zone Gas (50470125), and (7) Upper Claiborne Slope and Basin Floor Gas (50470126). Total estimated mean undiscovered conventional hydrocarbon resources in the seven assessment units combined are 52 million barrels of oil, 19.145 trillion cubic feet of natural gas, and 1.205 billion barrels of natural gas liquids. A recurring theme that emerged from the evaluation of the seven Claiborne AUs is that the great bulk of undiscovered hydrocarbon resources comprise non-associated gas and condensate contained in deep (mostly >12,000 feet), overpressured, structurally complex outer shelf or slope and basin floor reservoirs. The continuing development of these downdip objectives is expected to be the primary focus of exploration activity for the onshore Middle Eocene Gulf Coast in the coming decades.

Arkansas;Alabama;Florida;Georgia;Kentucky;Louisian↗
USGS2012

Database of the United States Coal Pellet Collection of the U.S. Geological Survey Organic Petrology Laboratory

The Organic Petrology Laboratory (OPL) of the U.S. Geological Survey (USGS) Eastern Energy Resources Science Center in Reston, Virginia, contains several thousand processed coal sample materials that were loosely organized in laboratory drawers for the past several decades. The majority of these were prepared as 1-inch-diameter particulate coal pellets (more than 6,000 pellets; one sample usually was prepared as two pellets, although some samples were prepared in as many as four pellets), which were polished and used in reflected light petrographic studies. These samples represent the work of many scientists from the 1970s to the present, most notably Ron Stanton, who managed the OPL until 2001 (see Warwick and Ruppert, 2005, for a comprehensive bibliography of Ron Stanton's work). The purpose of the project described herein was to organize and catalog the U.S. part of the petrographic sample collection into a comprehensive database (available with this report as a Microsoft Excel file) and to compile and list published studies associated with the various sample sets. Through this work, the extent of the collection is publicly documented as a resource and sample library available to other scientists and researchers working in U.S. coal basins previously studied by organic petrologists affiliated with the USGS. Other researchers may obtain samples in the OPL collection on loan at the discretion of the USGS authors listed in this report and its associated Web page.

Open-File Report↗
USGS2012

Preliminary evaluation of the shale gas prospectivity of the Lower Cretaceous Pearsall Formation in the onshore Gulf Coast region, United States

Recent work by the U.S. Geological Survey indicated that the Lower Cretaceous Pearsall Formation contains an estimated mean undiscovered, technically recoverable unconventional gas resource of 8.8 trillion cubic ft in the Maverick Basin, South Texas. Cumulative gas production from horizontal wells in the core area of the emerging play has exceeded 5 billion cubic ft since 2008. However, very little information is available to characterize the Pearsall Formation as an unconventional gas resource beyond the Maverick Basin in the greater Gulf Coast region. Therefore, this reconnaissance study examines spatial distribution, thickness, organic richness and thermal maturity of the Pearsall Formation in the onshore U.S. Gulf states using wireline logs and drill cuttings sample analysis. Spontaneous potential and resistivity curves of approximately forty wireline logs from wells in five Gulf Coast states were correlated to ascertain the thickness of the Pearsall Formation and delineate its three members: Pine Island Shale, James Limestone or Cow Creek Limestone, and Bexar Shale, in ascending stratigraphic order. In Florida and Alabama the Pearsall Formation is up to about 300 ft thick; in Mississippi, Louisiana, Arkansas, and East Texas, thickness is up to as much as 800 ft. Drill cuttings sampled from 11 wells at depths ranging from 4600 to 19,600 feet subsurface indicate increasingly oxygenated depositional environments (predominance of red shale) towards the eastern part of the basin. Cuttings vary widely in lithology but indicate interbedded clastics and limestones throughout the Pearsall Formation, consistent with previous regional studies. Organic petrographic and geochemical analyses of 17 cutting samples in the Pearsall Formation indicate a wide range in thermal maturity, from immature (0.43% Ro [vitrinite reflectance]) in paleo-high structural locations to the peak oil window (0.99% Ro) in the eastern portion of the Gulf Coast Basin. This is in contrast to dry gas thermal maturity throughout the Pearsall Formation in the South Texas Maverick Basin. Organic carbon content is low overall, even in immature samples, with a range of 0.17 to 1.08 wt.% by Leco in 22 Pearsall Formation samples. The pyrolysis output range was 0.23 to 2.33 mg hydrocarbon/g rock. The thermal maturity and Rock-Eval pyrolysis data and organic petrologic observations from this study will be used to better focus specific areas of investigation where the Pearsall Formation may be prospective as an unconventional hydrocarbon source and reservoir.

Alabama;Arkansas;Louisiana;Mississippi;Oklahoma;Te↗
USGS2012

Definition of Greater Gulf Basin Lower Cretaceous and Upper Cretaceous lower Cenomanian Shale Gas Assessment Unit, United States Gulf of Mexico basin onshore and state waters

An assessment unit (AU) for undiscovered continuous “shale” gas in Lower Cretaceous (Aptian and Albian) and basal Upper Cretaceous (lower Cenomanian) rocks in the USA onshore Gulf of Mexico coastal plain recently was defined by the U.S. Geological Survey (USGS). The AU is part of the Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System (TPS) of the Gulf of Mexico Basin. Definition of the AU was conducted as part of the 2010 USGS assessment of undiscovered hydrocarbon resources in Gulf Coast Mesozoic stratigraphic intervals. The purpose of defining the Greater Gulf Basin Lower Cretaceous Shale Gas AU was to propose a hypothetical AU in the Cretaceous part of the Gulf Coast TPS in which there might be continuous “shale” gas, but the AU was not quantitatively assessed by the USGS in 2010.

Search and Discovery↗
USGS2011

Reply to Effect of concentration of organic matter on optical maturity parameters. Interlaboratory results of the organic matter concentration working group of the ICCP. Discussion by Vinay K. Sahay

This reply is motivated by Sahay's comments on the paper published by Mendonça Filho et al. (2010) dealing with the effect of concentration of an organic matter on optical maturity parameters. Four points were raised by Sahay: suggestion to use of chemical parameters to assess the effect of isolation, indication that suppression of vitrinite reflectance in liptinite-rich rocks was insufficiently addressed, discussion on the way to deal with the existence of multiple vitrinite populations in a dispersed organic matter, and contradictory explanation of results involving the influence of isolation procedure on fluorescence properties but no effect on vitrinite reflectance. The four points were separately addressed being the two first ones out of the scope of the paper. The existence of multiple vitrinite populations is a well-recognized problem whose importance in the results could be addressed because the participants provided individual records of vitrinite reflectance. These results indicated that election of different populations was not a major problem in the results. The influence of isolation procedure on the fluorescence spectra of alginite while the vitrinite reflectance remains unaltered is not considered contradictory because both parameters are measured on different components which may have a different response to the acid treatment.

International Journal of Coal Geology↗
USGS2011

A review of the lignite resources of Arkansas

This review of the lignite resources of Arkansas is a part of the U.S. Geological Survey's (USGS) National Coal Resource Assessment (NCRA) of the Gulf Coastal Plain Coal Province, which also includes coal-bearing areas in the states of Texas, Louisiana, Alabama, Mississippi, Tennessee, and Kentucky (see Ruppert et al., 2002 ; Dennen, 2009 ; and other chapters of this publication). Lignite mining is not planned in Arkansas in the immediate future, and the lignite resources of the state were not assessed in detail as part of the NCRA. This chapter includes reviews of the geology of the lignite-bearing units, historical mining, previous investigations of lignite resources, and coal quality. Palynological data for lignite samples collected in Arkansas as part of this work are presented in Table 1 .

Arkansas↗