Sarah J. Hawkins

The rise of fire: Fossil charcoal in late Devonian marine shales as an indicator of expanding terrestrial ecosystems, fire, and atmospheric change

Fossil charcoal provides direct evidence for fire events that, in turn, have implications for the evolution of both terrestrial ecosystems and the atmosphere. Most of the ancient charcoal record is known from terrestrial or nearshore environments and indicates the earliest occurrences of fire in the Late Silurian. However, despite the rise in available fuel through the Devonian as vascular land plants became larger and trees and forests evolved, charcoal occurrences are very sparse until the Early Mississippian where extensive charcoal suggests well-established fire systems. We present data from the latest Devonian and Early Mississippian of North America from terrestrial and marine rocks indicating that fire became more widespread and significant at this time. This increase may be a function of rising O2 levels and the occurrence of fire itself may have contributed to this rise through positive feedback. Recent atmospheric modeling suggests an O2 low during the Middle Devonian (around 17.5%), with O2 rising steadily through the Late Devonian and Early Mississippian (to 21–22%) that allowed for widespread burning for the first time. In Devonian-Mississippian marine black shales, fossil charcoal (inertinite) steadily increases up-section suggesting the rise of widespread fire systems. There is a concomitant increase in the amount of vitrinite (preserved woody and other plant tissues) that also suggests increased sources of terrestrial organic matter. Even as end Devonian glaciation was experienced, fossil charcoal continued to be a source of organic matter being introduced into the Devonian oceans. Scanning electron and reflectance microscopy of charcoal from Late Devonian terrestrial sites indicate that the fires were moderately hot (typically 500–600 °C) and burnt mainly surface vegetation dominated by herbaceous zygopterid ferns and lycopsids, rather than being produced by forest crown fires. The occurrence and relative abundance of fossil charcoal in marine black shales are significant in that these shales may provide a more continuous record of fire than is preserved in terrestrial environments. Our data support the idea that major fires are not seen in the fossil record until there is both sufficient and connected fuel and a high enough atmospheric O2 content for it to burn.

A Framework for Quantitative Assessment of Impacts Related to Energy and Mineral Resource Development

Natural resource planning at all scales demands methods for assessing the impacts of resource development and use, and in particular it requires standardized methods that yield robust and unbiased results. Building from existing probabilistic methods for assessing the volumes of energy and mineral resources, we provide an algorithm for consistent, reproducible, quantitative assessment of resource development impacts. The approach combines probabilistic input data with Monte Carlo statistical methods to determine probabilistic outputs that convey the uncertainties inherent in the data. For example, one can utilize our algorithm to combine data from a natural gas resource assessment with maps of sage grouse leks and piñon-juniper woodlands in the same area to estimate possible future habitat impacts due to possible future gas development. As another example: one could combine geochemical data and maps of lynx habitat with data from a mineral deposit assessment in the same area to determine possible future mining impacts on water resources and lynx habitat. The approach can be applied to a broad range of positive and negative resource development impacts, such as water quantity or quality, economic benefits, or air quality, limited only by the availability of necessary input data and quantified relationships among geologic resources, development alternatives, and impacts. The framework enables quantitative evaluation of the trade-offs inherent in resource management decision-making, including cumulative impacts, to address societal concerns and policy aspects of resource development.

Assessment of undiscovered oil and gas resources in the Lower Indus Basin, Pakistan, 2017

The U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable oil and gas resources within the Lower Indus Basin, Pakistan (fig. 1). The Lower Indus Basin is on the Indian-Pakistan plate, and as part of the supercontinent Gondwana during the Permian to Middle Jurassic, it underwent multiple phases of extension culminating in the separation of the Indian-Pakistan plate from Somalia in the Late Jurassic to Early Cretaceous (Robison and others, 1999; Zaigham and Mallick, 2000; Ahmad and others, 2012a). Subsequent separation of the Madagascar and Seychelles blocks from the IndianPakistan plate in the Late Cretaceous to Paleogene led to further extension and the initial formation of conventional structural traps that have been the focus of petroleum exploration (fig. 2) (Naeem and others, 2016). The western margin of the Indian-Pakistan plate was passive from the Early Cretaceous to Eocene, and petroleum source rocks of the Lower Goru and Sembar Formations were deposited along the west-facing passive margin during the Early Cretaceous. Beginning in the Eocene, the IndianPakistan plate collided with Eurasia, which led to the formation of the Kirthar fold belt and the adjacent foreland basin. The Eocene collision also resulted in inversion, uplift, and erosion across the Indus Basin area, but deformation was focused within the fold belt. Geologic Models for Assessment

Assessment of continuous oil and gas resources of the Maracaibo Basin Province of Venezuela and Colombia, 2016

The U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable continuous oil and gas resources within the Maracaibo Basin Province of Venezuela and Colombia (fig. 1). The Maracaibo Basin Province is a structurally complex region encompassing approximately 58,000 square kilometers between the Sierra de Perijá and Cordillera de Mérida, with the northern boundary generally placed at the Oca-Ancón fault (Mann and others, 2006). More than 30 billion barrels of conventional oil have been produced from the basin, which ranks it as one of the top petroleum-producing basins in the world. Organicrich shales of the Upper Cretaceous La Luna Formation are the main petroleum source rock, and La Luna shales have reached adequate thermal maturity for oil and gas generation throughout much of the basin (Talukdar and others, 1986; Talukdar and Marcano, 1994; Escalona and Mann, 2006). The purposes of this study are (1) to estimate the volumes of recoverable continuous oil and gas remaining in La Luna Formation source rocks following two phases of petroleum generation and expulsion and (2) to postulate the presence of gas resources in low-permeability (tight) sandstones. Although the La Luna Formation is mapped as being partly in the gas generation window, little information is available on potential gas resource distribution and the possible presence of gas resources remaining in the La Luna source rock or in deeply buried, tight sandstones.

Assessment of coalbed gas resources of the Kalahari Basin Province of Botswana, Zimbabwe, and Zambia, Africa, 2016

The U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable continuous (unconventional) coalbed gas resources within the Kalahari Basin Province (fig. 1), a geologically complex region of approximately 648,670 square kilometers in Botswana, Zambia, and Zimbabwe. As much as 1,500 meters (m) of Lower Permian sedimentary rocks are present in the Kalahari Basin Province. Coals are present in the Permian Ecca Group. Thickness of the coal-bearing zone ranges from 500 to 550 m with net coal thickness ranging from 55 to 125 m. Individual coalbeds range from 1 m to as much as 30 m thick. Twenty-six coalbed gas exploration wells have been drilled in the Kalahari Basin Province, and several test wells in Botswana and Zimbabwe reported recoverable gas content or production (IHS MarkitTM, 2015; McConachie, 2015; Dowling, 2016). Gas contents are as much as 9.5 cubic meters per ton (334 standard cubic feet per ton) with gas content increasing with depth.

Assessment of undiscovered oil and gas resources in the Cuyo Basin Province, Argentina, 2017

The U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable continuous (unconventional) and conventional oil and gas resources within the Cuyo Basin (or Cuyana Basin) Province of Argentina (fig. 1). The Cuyo Basin Province encompasses a group of Triassic extensional subbasins that formed in a transtensional environment as South America began to separate from Africa (Uliana and others, 1989; Milani and Fihlo, 2000; Barredo, 2012; Barredo and others, 2012). The lithologies of the Triassic synrift to early postrift sediments of these basins range from volcanics to fluvial-lacustrine sandstones and shales. Organicrich lacustrine shales of the late synrift to early postrift Middle Triassic Cacheuta Formation are the petroleum source rocks in the Cuyo Basin Province (Lopez-Gamundi, 2010; Legarreta and Villar, 2011). Andean compression in the Miocene served to invert many of the Triassic extensional structures (Dellape and Hegedus, 1995), and the resulting foreland orogenic clastic wedge buried the lacustrine shales of the Cacheuta subbasin into the oil generation window in late Miocene to Pliocene time.

Assessment of Permian coalbed gas resources of the Karoo Basin Province, South Africa and Lesotho, 2016

The U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable coalbed gas resources within the Karoo Basin Province of South Africa and Lesotho (fig. 1). The Karoo Basin is a Permian retroarc foreland basin that formed as the Cape fold belt developed by subduction-related compression (Cadle and others, 1993). As the Cape fold belt developed, thrust loading caused lithospheric subsidence, forming an asymmetric foreland basin that was deepest in the south and shallower to the north. In the southern foredeep, the Permian section is dominated by deep-water shales and sandstones, whereas to the north and northeast the Permian section contains fluvial-deltaic conglomerates, sandstones, shales, and coals (Cairncross, 2001; Hancox and Götz, 2014). The focus of this study is the potential for coalbed gas resources in the coal-bearing sequences of the Vryheid Formation of the Ecca Group (fig. 2). The Vryheid Formation contains several coarsening-upward sequences with coals in the upper part of each sequence, and the coals can be traced throughout the study area (Hancox and Götz, 2014). Coal thickness is variable, but individual coals can be as much as 10-meters thick. Coal rank is reported to be highto low-volatile bituminous with higher rank in the eastern part of the study area. Permian sedimentation in the Karoo Basin Province ended with extensive volcanism related to the breakup of the Gondwana supercontinent. Dolerites associated with volcanism might have had a negative impact on potential coalbed gas resources, although there are differing interpretations as to the impact of the intrusives (Gröcke and others, 2009; Hancox and Götz, 2014). Distal Ecca Group shales include the Whitehill and Prince Albert Formations, which contain potential shale-gas resources (Brownfield and others, 2016), but the resource potential of shale gas may also have been affected by local thermal maturation and loss of gas by the emplacement of widespread intrusives.

Assessment of undiscovered oil and gas resources in the Ventura Basin Province, California, 2016

The U.S. Geological Survey (USGS) completed a geology-based assessment of undiscovered, technically recoverable conventional and continuous oil and gas resources in the part of the Ventura Basin Province that lies onshore or within State waters (within 3 miles of the shoreline) of California (fig. 1). Conventional oil and gas resources are those that have migrated upward into structural or stratigraphic traps from deep zones where the oil and gas is generated; water is present below the oil or gas. Continuous accumulations, in contrast, are those in which oil or gas is pervasively present in essentially all wells that penetrate them, that may not be structurally or stratigraphically trapped, and that typically lack oil-water or gas-water contacts. They are commonly produced with well-stimulation technology, such as hydraulic fracturing, referred to as “unconventional.” The same stimulation technology, however, is also used in many conventionally trapped accumulations. We estimated both the likely range of oil and gas volumes remaining to be discovered in accumulations similar to existing conventional oil and gas fields in the Ventura Basin Province (previously assessed by Keller [1995] as 1,060 million barrels of oil [MMBO], 1,900 billion cubic feet of gas [BCFG], and 60 million barrels of natural gas liquids [MMBNGL]), and the potential for oil and gas that might be present in a continuous accumulation at extreme depth in the floor of the basin.

Assessment of continuous oil and gas resources of the South Sumatra Basin Province, Indonesia, 2016

The U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable continuous oil and gas resources within the South Sumatra Basin Province (fig. 1), one of a series of backarc basins associated with subduction along the western margin of Sumatra, Indonesia. The Sumatra backarc realm underwent extension and rifting in the Eocene to early Oligocene that formed a series of horsts and grabens (Pulunggono, 1986; Ginger and Fielding, 2005). The grabens were filled with typical synrift nonmarine facies, including fluvial, deltaic, marginal lacustrine sandstones, and shallow to deep water lacustrine shales. The thickest petroleum source rocks are found within the graben system. One of the petroleum source rocks in the South Sumatra Basin Province is within the synrift Eocene-Oligocene Lemat Formation, which includes organic-rich lacustrine shale of the Benakat member (Rashid and others, 1998; Bianchi and others, 2007). Following cessation of rifting, regional thermal relaxation led to a sag phase with increased accommodation space and deposition. Petroleum source rocks reached thermal maturity for oil and gas generation beginning in the Miocene (Sarjono and Sardjito, 1989; Reksalegora and Riadinjo, 2013). Compression from middle Miocene to Pliocene related to subduction dynamics resulted in numerous structures within the basin, many of which formed traps for conventional oil and gas accumulations. For this assessment, a continuous source-reservoir rock system contains (1) greater than 2 weight percent total organic carbon, (2) the proper thermal maturity window for oil or gas generation, (3) greater than 15 meters of organic-rich shale, and (4) Type I or Type II organic matter. The assessment unit (AU) areas outlined in figure 1 represent continuous oiland gas-prone areas that are interpreted to satisfy these geologic criteria. The range of uncertainty on assessment unit areas (table 1) reflects uncertainty on the extent and thickness of source-rock facies within the grabens and the extent and level of thermal maturation of the source rock.

Assessment of continuous oil and gas resources of the Cooper Basin, Australia, 2016

Acknowledgments We thank Tony Hill, Elinor Alexander, and Dominic Pepicelli from the South Australia Division for Manufacturing, Innovation, Trade, Resources, and Energy (DMITRE) and Anthony Budd and Lisa Hall (Geoscience Australia) for providing critical data and discussions on the Cooper Basin that formed the geologic foundation for this assessment. Introduction The U.S. Geological Survey (USGS) quantitatively assessed the potential for technically recoverable, continuous oil and gas resources in the Cooper Basin of Australia (fig. 1). The Cooper Basin is within the Eromanga Basin Province as defined by the USGS (Klett and others, 1997). For this assessment, the USGS defined a Cooper-Eromanga Composite Total Petroleum System (TPS) with Permian-age coal as the primary source rock for oil and gas in the Cooper Basin (Menpes and others, 2013). Seven continuous assessment units (AUs) were defined within this composite TPS to encompass the continuous oil and gas accumulations. They are (1) Patchawarra Trough Tight Gas AU, (2) Nappamerri Trough Tight Gas AU, (3) Queensland Troughs Tight Gas AU, (4) Patchawarra Trough Coal Oil AU, (5) Nappamerri Trough Coal Oil AU, (6) Queensland Troughs Coal Oil AU, and (7) Weena Trough Coalbed Gas AU.