Assessment of Appalachian basin oil and gas resources: Devonian gas shales of the Devonian Shale-Middle and Upper Paleozoic Total Petroleum System

Milici, Robert C.; Swezey, Christopher S.

doi:10.3133/pp1708g.9

Cited by 24 publications

(37 citation statements)

References 17 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…For workers evaluating thermally mature unconventional Paleozoic petroleum systems such as the Mississippian Barnett Shale in the Fort Worth Basin or the Devonian Appalachian Basin shales where solid bitumen is the dominant organic-matter component (Hackley and Cardott, 2016), assuming that the entrance to the oil window occurs at 0.60% R o may decrease the areas in which self-sourced reservoirs are predicted. The USGS and other organizations (e.g., oil companies) sometimes use spatial extent (among other criteria) of 0.60% R o conditions to estimate the volumes of undiscovered self-sourced petroleum resources reservoired in shale (Milici and Swezey, 2006;Coleman et al, 2011). If boundaries are underestimated because R o measurements mistakenly include measurements of BR o , then estimated volumes of undiscovered HCs also will be underestimated.…”

Section: Implications To Petroleum Assessmentmentioning

confidence: 99%

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Hackley

Lewan

2018

Bulletin

View full text Add to dashboard Cite

Solid bitumen is a common organic component of thermally mature shales and typically is identified by embayment against euhedral mineral terminations and by groundmass textures. However, because these textures are not always present, solid bitumen can be easily misidentified as vitrinite. Hydrous-pyrolysis experiments (72 hr, 300°C-360°C) on shale and coal samples show that solid-bitumen reflectance (BR o) in shales is less responsive to thermal stress than vitrinite reflectance (R o) in coal. This effect is most pronounced at lower experimental temperatures (300°C-320°C), whereas reflectance changes are more similar at higher temperatures (340°C-360°C). Neither a "vitrinitelike" maceral nor "suppressed vitrinite" was identified or measured in our sample set; instead, the experiments show that solid bitumen matures slower than vitrinite. The data may explain some reports of "R o suppression," particularly at lower thermal maturity (R o £ 1.0%), as a simple case of solid bitumen being mistaken for vitrinite. Further, the experimental results confirm previous empirical observations that R o and BR o are more similar at higher maturities (R o > 1.0%). It is suggested that R o suppression, commonly reported from upper Paleozoic marine shales of early to midoil window maturity, is a misnomer. This observation has important implications to petroleum exploration models and resource assessment, because it may change interpretations for the timing and spatial locations of kerogen maturation and petroleum generation.

show abstract

Section: Implications To Petroleum Assessmentmentioning

confidence: 99%

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Hackley

Lewan

2018

Bulletin

View full text Add to dashboard Cite

show abstract

“…Tioga County, New York State, from which the cuttings for this study were obtained, is outlined in red. Modified after Milici and Swezey (2006) and Kolesar Kohl et al (2014).…”

Section: Introductionmentioning

confidence: 99%

“…The section continues upward into Upper Devonian and Lower Mississippian shales and conventional hydrocarbon-bearing sandstones. Oil and gas in these units is thought to be sourced primarily from the underlying Marcellus Shale (Milici and Swezey, 2006;Zagorski et al, 2012). The units underlying the Marcellus Formation include the hydrocarbon-bearing Ordovician Utica Shale, as well as Silurian Salina Series evaporites in the north, which transition to limestones, shales and sandstones in the south-southwestern part of the play (Carter, 2007).…”

Section: Introductionmentioning

confidence: 99%

Origin of brines, salts and carbonate from shales of the Marcellus Formation: Evidence from geochemical and Sr isotope study of sequentially extracted fluids

Stewart

Chapman

Capo

et al. 2015

Applied Geochemistry

View full text Add to dashboard Cite

Fluids co-produced with methane from hydraulically fractured organic-rich shales of the Marcellus Formation (USA) are characterized by high total dissolved solids (TDS), including elevated levels of Ba, Sr and Br. To investigate the source and geologic history of these high-TDS fluids and their dissolved constituents, we carried out a series of sequential extraction experiments on dry-drilled cuttings extracted within, below and above the Marcellus Shale from a well in Tioga County, New York State. The experiments were designed to extract (1) water soluble components, (2) exchangeable cations, (3) carbonate minerals, and (4) hydrochloric acidsoluble constituents. The geochemistry of the resultant leachates highlights the different geochemical reservoirs for extractable elements within the shale; notably, Na and Br were largely water-soluble, while Ba was extracted primarily from exchangeable sites, and Ca and Sr were found both in exchangeable sites and carbonate. Strontium isotope ratios measured on the leachates indicate that each of the element reservoirs has a distinct value. Measured 87 Sr/ 86 Sr ratios in the water soluble component are similar to those of Marcellus produced water, while the ion exchange reservoir yields lower ratios, and carbonate Sr is lower still, approaching Devonian-Silurian seawater values. Despite the isotopic similarity of water leachates and produced water, the total water chemistry argues against generation of produced water by interaction of hydraulic fracturing fluid with "dry" shale. The high-TDS produced water is most likely trapped formation water (within and/or adjacent to the shale) that is released by hydraulic fracturing. The formation water was affected by multiple processes, possibly including basin scale, tectonically-driven fluid flow. Significant chemical and isotopic differences between Marcellus Shale produced water and overlying Upper Devonian/Lower Mississippian produced waters suggests a hydrologic barrier has been maintained in parts of the Appalachian Basin since the late Paleozoic.

show abstract

“…The Marcellus Shale reaches a thickness of about 1,000 ft in central Pennsylvania and thins to the north, west, and south (DeWitt and others, 1993). However, the net thickness of organic-rich black shales within the Marcellus is considerably less-approximately 250 ft in eastern Bradford County, Pa., and Tioga County, N.Y., and only about 150 ft thick in Delaware County (Milici and Swezey, 2006 (fig 6). The base of the Marcellus Shale conformably overlies the Onondaga Limestone (Rickard, 1975).…”

Section: Marcellus Shalementioning

confidence: 99%

Hydrogeology of the West Branch Delaware River basin, Delaware County, New York

Reynolds¹

2013

Scientific Investigations Report

View full text Add to dashboard Cite

show abstract

Assessment of Appalachian basin oil and gas resources: Devonian gas shales of the Devonian Shale-Middle and Upper Paleozoic Total Petroleum System

Cited by 24 publications

References 17 publications

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Origin of brines, salts and carbonate from shales of the Marcellus Formation: Evidence from geochemical and Sr isotope study of sequentially extracted fluids

Hydrogeology of the West Branch Delaware River basin, Delaware County, New York

Contact Info

Product

Resources

About