Abstract: While coalbed methane (CBM) is a significant source of natural gas production globally, uncertainties regarding the proportions of biogenic and thermogenic natural gas in CBM reservoirs still remain. We integrate major gases, hydrocarbon composition, hydrocarbon stable isotopes and noble gases in fluids from 20 producing CBM wells to more accurately constrain the genetic source of natural gases in the eastern Illinois Basin, USA. Previous studies have indicated primarily biogenic production of methane (>99.6%) with negligible contributions from thermogenic natural gases. However, by integrating noble gases, we identify quantifiable (up to 19.2%) contributions of exogenous thermogenic gas in produced gases from the Seelyville and Springfield coal seams. Thermogenic gases are distinguished by a positive relationship between methane, ethane and helium-4, lower C 1 /C 2 +, heavier δ 13 C-CH 4 , more radiogenic noble gases ( 4 He, 21 Ne*, 40 Ar*), and lower abundances of atmospherically derived gases ( 20 Ne, 36 Ar). Biogenic gases displayed lighter δ 13 C-CH 4 , higher C 1 /C 2 +, higher levels of atmospheric gases and lower abundances of radiogenic noble gases. Our data suggest that natural gases from a deeper, exogenous thermogenic source likely migrated to the Pennsylvanian-aged coals at an unknown time and later mixed with biogenic methane diluting the geochemical signature of the thermogenic methane within the Springfield and Seelyville coal seams.

Abstract The UK Department of Energy and Climate Change (DECC) commissioned the British Geological Survey (BGS) to summarize the available geological knowledge, integrate new seismic mapping and well analysis, and make preliminary in-place resource assessments for the three most prospective areas onshore Britain to foster a greater understanding of the unconventional shale resource potential in advance of the 14th Landward Licensing Round. The first study, published in June 2013, reviewed the Carboniferous Bowland–Hodder shales across central Britain where a large volume of in-place gas was assessed to be present. The second study, of the Jurassic shale of the Weald Basin in southern England, published in May 2014, concluded that owing to insufficient burial there was no significant Jurassic shale gas potential, but there could still be shale oil resources at several levels in the centre of the basin. The third study, published in June 2014, covered the Midland Valley of Scotland where both oil and gas potential in Carboniferous shales was identified. A large volume of in-place gas and oil resource has been assessed to be present. However, not enough is known at the time of writing to estimate a recovery factor or to estimate potential producible reserves. This paper summarizes the results of the BGS reports and their impact on the subsequent licensing process in England.

Convergent orogenic systems pose challenges for the prospector seeking to predict oil and gas reservoirs, as these regions are often data poor. Explorationists, therefore, must often rely on conceptual models to predict the occurrence of oil and gas, and to choose the most favorable exploration areas. This paper examines how different conceptual models of hinterland evolution can influence predictions of hydrocarbon systems in an adjacent foreland. A one-dimensional (1-D) method was developed for assessing incremental hydrocarbon yield during progressive fold-belt deformation and source rock burial and maturation. This method was employed to evaluate the way in which hydrocarbon yield is affected by two different scenarios for the timing of uplift of the Puna Plateau and subsequent burial of the adjacent Metán region of northwestern Argentina. In the first scenario, plateau growth and burial of the Metán region begin in the early Miocene and progress to the present day. In the second scenario, plateau growth and basin formation occur predominantly in the Eocene, with minor deformation from middle Miocene to present. The later load timing decreases the relative volume of liquid hydrocarbons available to fill structural traps. The differences in charge volume and timing between the two scenarios are enhanced in this region as a result of thinned crust and relatively high heat flow that linger from a Cretaceous rifting event. The results of the study provide an example of how boundary conditions obtained from studies of an orogenic hinterland can be used to calculate risk for exploring a potential play within a basin where data are incomplete or inconclusive. They also yield general insights on the use of regional genetic concepts to predict thermal history and source rock maturation and yield in data-poor areas.

Abstract Coastal exposures of Mesozoic sediments in the Wessex basin and Channel subbasin (southern UK), and the Lusitanian basin (Portugal) provide keys to the petroleum systems being exploited for oil and gas offshore Atlantic Canada. These coastal areas have striking similarities to the Canadian offshore region and provide insight to controls and characteristics of the reservoirs. Outcrops demonstrate a range of depositional environments from terrigenous and non-marine, shallow siliciclastic and carbonate sediments, through to deep marine sediments, and clarify key stratigraphic surfaces representing conformable and non-conformable surfaces. Validation of these analog sections and surfaces can help predict downdip, updip, and lateral potential of the petroleum systems, especially source rock and reservoir.

Abstract A synthesis of the knowledge about the Lusitanian Basin is presented here, focusing on its stratigraphic record, sedimentary infill, evolution, and petroleum systems. Petroleum system elements are characterized, including Palaeozoic and Mesozoic source rocks, siliciclastic and carbonate reservoirs, and Mesozoic and Tertiary seals and traps. Related processes, such as organic matter maturation and hydrocarbons migration are also discussed. The characteristics of these elements and processes are analysed and implications for deep offshore exploration are discussed.

Abstract Sedimentary basins in the eastern United States (U.S.) contain strata ranging in age from Neoproterozoic to Holocene and have been the source of petroleum and coal that fueled much of the initial growth and development of the U.S. as a major industrial power. It is estimated that at least 87 billion barrels of oil (BBO) and natural gas liquids (BBNGL) and 664 trillion cubic feet of natural gas (TCFG) have been produced to-date from these basins. These basins developed on continental and transitional oceanic-continental crust ranging in age from the Paleoproterozoic to Triassic. Many of these basins have undergone structural readjustment and uplift, some being nearly completely inverted. The oldest of these basins considered here are Mesoproterozoic to Early Cambrian in age. They include the Midcontinent rift, Reelfoot rift, Rough Creek graben, and Rome trough. These basins are dominantly rift basins, which formed within the North American craton, presumably as a result of plate tectonic forces associated with the rifting of the Rodina supercontinent and the opening of the Iapetus Ocean. Petroleum systems have been identified or postulated in these four basins. Overlying these basins are the three large Paleozoic-aged sag-foreland basins of the eastern U.S.: the Michigan, Illinois, and Appalachian basins. Additionally included are the eastern extent of the Arkoma-Ouachita-Black Warrior foreland basin and a relict Gondwanan basin that was left behind in present-day north Florida following the Mesozoic rifting of Pangea. A mixed siliciclastic–carbonate–evaporite sedimentary section includes reservoirs and seal facies for many play types. Multiple petroleum systems have been identified or postulated in all of these basins. Succeeding these large Paleozoic sag and foreland basins are the Late Permian(?) to Early Jurassic rift basins that rim the eastern continental margin of the U.S. These basins have formed as a result of plate tectonic forces associated with the opening of the Atlantic Ocean and the Gulf of Mexico. Basin-fill sequences are generally lacustrine and continental-playa siliciclastic strata containing locally significant coals and minor carbonates. Petroleum systems have been identified or postulated in several of these basins, including the Dan River-Danville, Deep River, Newark, Richmond, and Taylorsville basins. Finally, overlying this complex stack of Proterozoic, Paleozoic, and early Mesozoic basins are the great Gulf of Mexico and Atlantic margin basins. The Gulf of Mexico Basin is distinguished by the dominating structural control of the salt and shale tectonics on a mobile substrate, whereas the basins of the western Atlantic margin are associated mainly with faulting associated with the opening of the Atlantic Ocean. Only the Carolina Trough of the western Atlantic margin basins has mobile salt structures. The sedimentary sequences of both basins are a mixed siliciclastic–carbonate interval containing coal and lignite in variable quantities in the updip portions of the basins. A composite total petroleum system has been identified in the Gulf of Mexico basin that incorporates several Mesozoic and Cenozoic petroleum source rocks with many reservoir rocks and seals throughout the sedimentary sequence. A combination of cultural and tectonic setting, sediment provenance and delivery systems, and paleo-oceanographic conditions have made the Gulf of Mexico basin one of the most prolific petroleum provinces on the planet. The current understanding of the Atlantic margin basin suggests that it does not appear to have a similar accumulation of petroleum resources as the Gulf of Mexico Basin. Correlated and potential petroleum source rock intervals have been penetrated in several of the offshore post-rift Atlantic margin subbasins; however, in many places on the shallow shelf, these intervals are generally too organically lean and (or) too immature to be major source rocks. A single petroleum system has been locally demonstrated in the offshore Atlantic by a non-commercial gas-condensate discovery. Additional petroleum systems in the western Atlantic may be identified as research continues. Source rock intervals penetrated by Deep Sea Drilling Project and Ocean Drilling Program cruises farther off-shore have generative potential, but data from these projects are too sparse to identify petroleum systems connecting these source rocks with potential reservoir targets.

Abstract It is widely recognized that shale resource plays such as the Bakken Petroleum System, in the Williston Basin, North America, are significantly more spatially complex over nearly every geological parameter than previously understood. For example, closely spaced Bakken wells can have much different production rates over their lifetime, despite very similar completion strategies. In ultra-low porosity and permeability regimes typical of shale resources plays, the variations in rock characteristics from well to well may be below the resolvable scales of seismic reflection and well data. These undetectable variations can lead to variations in organic content or elasticity that in turn affect production. I attempt to address differences in first year cumulated production from wells in the Red Sky survey area of the Ross Field, North Dakota, using results from core studies on bulk mineralogy, clay content, thermal maturity, and in situ stress. These data allow me to make assessments of brittleness and ultimate fracability of wells having differing production histories of closely spaced wells within Ross Field.