Paul C. Hackley

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, Ro = 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 (Tmax) 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.

Vitrinite reflectance versus pyrolysis Tmax data: Assessing thermal maturity in shale plays with special reference to the Duvernay shale play of the Western Canadian Sedimentary Basin, Alberta, Canada

In unconventional, self-sourced sedimentary rocks, organic matter type and maturity and therefore the hydrocarbon production potential, are the most critical parameters when evaluating unconventional hydrocarbon resources. Several methods exist that determine the maturity level of sedimentary rocks and the organic matter. organic maturity is commonly determined by vitrinite reflectance (%Ro). Vitrinite is a type of maceral that is derived from higher order plants. In rock with little or no vitrinite, bitumen or other organic matter type reflectances are measured and calculated to a normalized reflectance value (%Ro). measuring vitrinite/bitumen reflectance is time-consuming and subject to the interpretation of the analysts. Alternatively, organic matter type and maturity are also measured using Rock Eval or equivalent pyrolysis techniques. The temperature (Tmax) at which thermal cracking of heavy hydrocarbons and kerogen reaches the maximum depends on the nature and maturity of the kerogen and indicates the level of thermal maturity. Pyrolysis results are independent of an operator although the data output may still require validation. In order to compare data from these two techniques, a study from the Barnett in 2001 produced a conversion formula to calculate %Ro from Tmax data. The conversion formula (calculated Ro = 0.0180 x Tmax 7.16) has been used extensively in basins worldwide despite the fact that the correlation was produced for the Barnett shale. Here we present new maturity data (>100) (%Ro and Tmax) within the duvernay formation in Alberta, Canada, which is compared to data using the conversion formula. The duvernay formation of the Western Canada Sedimentary Basin is an Upper devonian (~360 ma) source rock which has been praised as one of the most promising oil/gas resource plays in Canada. Since late 2009, land sale activity has seen over

Organic petrology of peak oil maturity Triassic Yanchang Formation lacustrine mudrocks, Ordos Basin, China

1.4 Bn spent in Alberta with land purchases focused in the Pembina and Kaybob areas. The total organic carbon (ToC) content of the duvernay formation can exceed 20 wt% in areas of low maturity but on average, the dark shales have ToC contents ranging between 4-11 wt%. ToC is a key indicator of hydrocarbon generation potential. In this study, we discuss the details of both analytical techniques, findings of the organic petrography, bitumen reflectance data and corresponding Tmax data. The data is also compared to calculated Ro values and problems using the formula are highlighted. In addition, the data is put into perspective of production information and the hydrogengenerative models (initial production data). The results show that inherent problems are manyfold and conversion calculations should be avoided in new formations where a conversion formula has not been established. To order the full paper, visit https://www.onepetro.org/conference-paper/SPE-167031-MS

Nanoscale geochemical and geomechanical characterization of organic matter in shale

AbstractAn organic petrology evaluation and a determination of solid bitumen reflectance BRo were completed for organic-rich Triassic Yanchang Formation mudrocks (n=15) from the Ordos Basin, north-central China, as part of a larger investigation of “shale gas” resources. These data were integrated with information from Rock-Eval programmed pyrolysis to show that the samples are in the peak oil window of thermal maturity and that organic matter is dominated by solid bitumen with minor amounts of type III kerogen (vitrinite and inertinite) from vascular land plants. Describing a “kerogen type” for these rocks based strictly on parameters determined from programmed pyrolysis is misleading because the original organic matter has converted to hydrocarbons (present as solid bitumen), a large proportion of which may have been expelled into adjacent reservoir facies. However, based on the comparison with immature-early mature lacustrine mudrock (Garden Gulch Member of Green River Formation) and marine shale (Boqu...

Utilization of integrated correlative light and electron microscopy (iCLEM) for imaging sedimentary organic matter

Solid organic matter (OM) plays an essential role in the generation, migration, storage, and production of hydrocarbons from economically important shale rock formations. Electron microscopy images have documented spatial heterogeneity in the porosity of OM at nanoscale, and bulk spectroscopy measurements have documented large variation in the chemical composition of OM during petroleum generation. However, information regarding the heterogeneity of OM chemical composition at the nanoscale has been lacking. Here we demonstrate the first application of atomic force microscopy-based infrared spectroscopy (AFM-IR) to measure the chemical and mechanical heterogeneity of OM in shale at the nanoscale, orders of magnitude finer than achievable by traditional chemical imaging tools such as infrared microscopy. We present a combination of optical microscopy and AFM-IR imaging to characterize OM heterogeneity in an artificially matured series of New Albany Shales. The results document the evolution of individual organic macerals with maturation, providing a microscopic picture of the heterogeneous process of petroleum generation.Solid organic matter (OM) plays a key role in the production of hydrocarbons in shale formations, yet information on OM heterogeneity at a nanoscale is lacking. Here, the authors use atomic force microscopy-based infrared spectroscopy to document the evolution of individual organic macerals with maturation.

Organic Geochemical Investigation and Coal-bed Methane Characteristics of the Guasare Coals (Paso Diablo Mine, Western Venezuela)

We report here a new microscopic technique for imaging and identifying sedimentary organic matter in geologic materials that combines inverted fluorescence microscopy with scanning electron microscopy and allows for sequential imaging of the same region of interest without transferring the sample between instruments. This integrated correlative light and electron microscopy technique is demonstrated with observations from an immature lacustrine oil shale from the Eocene Green River Mahogany Zone and mid‐oil window paralic shale from the Upper Cretaceous Tuscaloosa Group. This technique has the potential to allow for identification and characterization of organic matter in shale hydrocarbon reservoirs that is not possible using either light or electron microscopy alone, and may be applied to understanding the organic matter type and thermal regime in which organic nanoporosity forms, thereby reducing uncertainty in the estimation of undiscovered hydrocarbon resources.

Assessment of undiscovered conventional oil and gas resources, onshore Claiborne Group, United States part of the northern Gulf of Mexico Basin

Abstract The aim of this work was to carry out a geochemical study of channel samples collected from six coal beds in the Marcelina Formation (Zulia State, western Venezuela) and to determine experimentally the gas content of the coals from the Paso Diablo mine. Organic geochemical analyses by gas chromatography-mass spectrometry and isotopic analyses on-line in coalbed gas samples were performed. The results suggest that the Guasare coals were deposited in a continental environment under highly dysoxic and low salinity conditions. The non-detection of 18α(H)-oleanane does not preclude that the organic facies that gave rise to the coals were dominated by angiosperms. In addition, the presence of the sesquiterpenoid cadalene may indicate the subordinate contribution of gymnosperms (conifers) in the Paleocene Guasare mire. The average coalbed gas content obtained was 0.6 cm3/g. δ13C and δD values indicate that thermogenic gas is prevalent in the studied coals.

Assessment of Thermal Maturity Trends in Devonian–Mississippian Source Rocks Using Raman Spectroscopy: Limitations of Peak-Fitting Method

The middle Eocene Claiborne Group was assessed for undiscovered conventional hydrocarbon resources using established U.S. Geological Survey assessment methodology. This work was conducted as part of a 2007 assessment of Paleogene–Neogene strata of the northern Gulf of Mexico Basin, including the United States onshore and state waters (Dubiel et al., 2007). The assessed area is within the Upper Jurassic–Cretaceous–Tertiary composite total petroleum system, which was defined for 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 Formation and the Haynesville and Bossier shales, 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 currently ongoing. Primary reservoir sandstones 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. 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 (AUs) with three distinctive structural and depositional settings. The three structural and depositional settings are (1) stable shelf, (2) expanded fault zone, and (3) slope and basin floor; the seven AUs are (1) lower Claiborne stable-shelf gas and oil, (2) lower Claiborne expanded fault-zone gas, (3) lower Claiborne slope and basin-floor gas, (4) lower Claiborne Cane River, (5) upper Claiborne stable-shelf gas and oil, (6) upper Claiborne expanded fault-zone gas, and (7) upper Claiborne slope and basin-floor gas. Based on Monte Carlo simulation of justified input parameters, the total estimated mean undiscovered conventional hydrocarbon resources in the seven AUs combined are 52 million bbl of oil, 19.145 tcf of natural gas, and 1.205 billion bbl of natural gas liquids. This article describes the conceptual geologic model used to define the seven Claiborne AUs, the characteristics of each AU, and the justification behind the input parameters used to estimate undiscovered resources for each AU. The great bulk of undiscovered hydrocarbon resources are predicted to be nonassociated gas and natural gas liquids contained in deep (mostly 12,000-ft [3658 m], present-day drilling depths), overpressured, structurally complex outer shelf or slope and basin-floor Claiborne 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.

New Technique for Imaging Geologic Materials via Integrated Correlative Light and Electron Microscopy (iCLEM)

The thermal maturity of shale is often measured by vitrinite reflectance (VRo). VRo measurements for the Devonian-Mississippian black shale source rocks evaluated herein predicted thermal immaturity in areas where associated reservoir rocks are oil-producing. This limitation of the VRo method led to the current evaluation of Raman spectroscopy as a suitable alternative for developing correlations between thermal maturity and Raman spectra. In this study, Raman spectra of Devonian-Mississippian black shale source rocks were regressed against measured VRo or sample-depth. Attempts were made to develop quantitative correlations of thermal maturity. Using sample-depth as a proxy for thermal maturity is not without limitations either, as thermal maturity as a function of depth depends on thermal gradient, which can vary through time, subsidence rate, uplift, lack of uplift, and faulting. Correlations between Raman data and thermal maturity metrics were quantified by peak-fitting the spectra. Various peak-fitting procedures were evaluated to determine the effects of the number of peaks and maximum peak widths on correlations between spectral metrics and thermal maturity. Correlations between D-frequency, G-band full-width-at-half-maximum (FWHM) and band separation between the G- and D- peaks and thermal maturity provided some degree of linearity throughout most peak-fitting assessments; however, these correlations and those calculated from the G-frequency, D/G FWHM ratio, and D/G peak area ratio also revealed a strong dependence on peak-fitting processes. This dependency on spectral analysis techniques raises questions about the validity of peak-fitting, particularly given the amount of subjective analyst involvement necessary to reconstruct spectra. This research shows how user interpretation and extrapolation affected the comparability of different samples, the accuracy of generated trends, and therefore, the potential of the Raman spectral method to become an industry benchmark as a thermal maturity probe. A Raman method devoid of extensive operator interaction and data manipulation is quintessential for creating a standard method.

Petrographic and Vitrinite Reflectance Analyses of a Suite of High Volatile Bituminous Coal Samples from the United States and Venezuela

We describe an integrated correlative light and electron microscopy (iCLEM) approach for sequential imaging of geologic materials (shale and mudstone) utilizing both microscope techniques without sample transfer. By avoiding sample transfer this technique identifies low maturity organic matter at micron-scale (1,000x magnifications) and can be followed by characterization at nano-scale (25,000-100,000x magnifications), potentially benefiting studies of organic nano-porosity, which is thought to control hydrocarbon storage and migration in shale petroleum systems [1]. Organic matter in shale, e.g., kerogen vs. solid bitumen, is easily identified by standard optical microscopy techniques such as epifluorescence and incident white light microscopy under oil immersion [2]. However, optical microscopy is diffraction-limited to resolutions of about 1 micron in practice, prohibiting nano-scale observation. Scanning electron microscopy (SEM) allows resolution of features <10 nm, thereby enabling study of organic nano-porosity [3]. Although organic matter is easily identified in SEM by its characteristic low backscatter electron (BSE) intensity, SEM is poorly suited to identify individual organic matter types. Therefore, correlative microscopy [4] or iCLEM studies are necessary to identify organic matter types in which organic nano-porosity develops and the thermal regime of formation.