Abstract Limited exploratory drilling based on relatively sparse seismic data has occurred since at least 1890 in onshore Late Triassic–Early Jurassic rift basins of the eastern United States (U.S.). Although rich source rocks and thermally generated hydrocarbons have been documented, commercial petroleum accumulations have not been found. Consequently, in 2012 the U.S. Geological Survey (USGS) assessed these basins as having potentially modest volumes of primarily continuous (unconventional) resources. Using these findings and interpretations, what then is the prospectivity of similar age undrilled rift basins in the offshore of the U.S. Central Atlantic? Are there any indications of differences between the offshore and onshore basins in the apparent mode of formation, structural style, amount of inversion, etc. , documented, or suggested by seismic data in these undrilled offshore basins? What do we know, and what can we speculate regarding petroleum system elements and processes in these unexplored basins? Seismic data interpretation suggests most offshore rift basins are generally similar to the Late Triassic–Early Jurassic rift basins onshore. The amount of eroded synrift strata predicted by geohistory modeling in the seismically defined Norfolk basin, offshore Virginia, is similar to that of onshore basins. However, seismic data interpretation also shows differences among some of the offshore basins; e.g. , a rift system northwest of the Yarmouth arch in the northern Georges Bank basin, offshore New England, appears to have less synrift section eroded than most basins in the U.S. Central Atlantic and contains inversion features that appear seismically similar to productive structures found offshore Indonesia.

Abstract Immediately prior to the opening of the Atlantic Ocean in the Mesozoic Era, numerous extensional and transtensional basins developed along the eastern margin of North America from Florida to Canada and from the Appalachian Piedmont eastward to the edge of the present-day continental shelf. Using a petroleum system-based methodology, the U.S. Geological Survey examined 13 onshore Mesozoic synrift basins and estimated a mean undiscovered natural gas resource of 3.86 trillion cubic feet (TCF; 109 billion cubic meters, BCM) of gas and a mean undiscovered natural gas liquids resource of 135 million barrels (MMBNGL; 21.5 million cubic meters, MMCM) in continuous accumulations within five of these basins: the Deep River, Dan River-Danville, Richmond, Taylorsville basins, and the southern part of the Newark Basin. The other eight basins were examined, but not assessed due to insufficient data. An additional 26 basins in the East Coast Mesozoic synrift basins trend were examined here for further insights into the development and evolution of a large, but short-lived set of petroleum systems in Mesozoic synrift basins. An individual composite total petroleum system is contained within each of the assessed basins. Small amounts of oil and natural gas have been recovered from many of the basins, yet no commercial production has been established. Potential and identified source rocks are present as shale and (or) coal. Potential reservoir rocks are low porosity and permeability sandstones as well as shale, siltstone, coal, and fractured igneous rocks. Examination of data indicates that many of these rift basins have undergone substantial uplift (greater than 4,000 ft, 1200 m), and one or more episodes of water washing have affected oil accumulations. Drilling for conventionally trapped structural and (or) stratigraphic prospects has not been successful. Remaining potential appears to be in continuous (unconventional) gas and natural gas liquid accumulations in a variety of reservoir types.

Abstract The Hartford-Deerfield basin, a Late Triassic to Early Jurassic rift basin located in central Connecticut and Massachusetts, is the northernmost basin of the onshore Mesozoic rift basins in the eastern United States. The presence of asphaltic petroleum in outcrops indicates that at least one active petroleum system has existed within the basin. However, to-date oil and gas wells have not been drilled in the basin to test any type of petroleum trap. There are good to excellent quality source rocks (up to 3.8% present day total organic carbon) within the Jurassic East Berlin and Portland formations. While these source rock intervals are fairly extensive and at peak oil to peak gas stages of maturity, individual source rock beds are relatively thin (typically less than 1 m) based solely on outcrop observations. Potential reservoir rocks within the Hartford-Deerfield basin are arkosic conglomerates, pebbly sandstones, and finer grained sandstones, shales, siltstones, and fractured igneous rocks of the Triassic New Haven and Jurassic East Berlin and Portland formations (and possibly other units). Sandstone porosity data from 75 samples range from less than 1% to 21%, with a mean of 5%. Permeability is equally low, except around joints, fractures, and faults. Seals are likely to be unfractured intra-formational shales and tight igneous bodies. Maturation, generation, and expulsion likely occurred during the late synrift period (Early Jurassic) accentuated by an increase in local geothermal gradient, igneous intrusions, and hydrothermal fluid circulation. Migration pathways were likely along syn- and postrift faults and fracture zones. Petroleum resources, if present, are probably unconventional (continuous) accumulations as conventionally accumulated petroleum is likely not present in significant volumes.

Abstract The Richmond basin, a rift basin of Late Triassic to Early Jurassic age in east-central Virginia, produced the first coal mined in the United States in the early 1700s. These Triassic coal beds are thick and gas-rich, and fatal explosions were common during the early history of exploitation. Since 1897, at least 38 confirmed oil, natural gas, and coal tests have been drilled within the basin. Although shows of asphaltic petroleum and natural gas indicate that active petroleum systems existed therein, no economic hydrocarbon accumulations have been discovered to-date. The Richmond basin has been assessed by the U. S. Geological Survey (USGS) as one composite total petroleum system, in which the hydrocarbon potential of the source beds (both coal and dark shale) and potential reservoirs have been combined into a single continuous tight gas assessment unit within the Chesterfield and Tuckahoe groups (Upper Triassic). Sandstone porosities are generally low (<1 % to 14 %). Thick, dark-colored shales have total organic carbon (TOC) values that range from <1% to 10%, and vitrinite reflectance (%R O ) values that range generally from about 0.3 to 1.1%, which indicates that the submature to super mature shales appear to be the source of the hydrocarbons recovered from some of the boreholes. The stratigraphic combination of these potential source rocks, tight sandstones, and hydrocarbon shows are the basis for the current USGS assessment of the technically recoverable undiscovered hydrocarbon resources of the basin. Mean values for these resources are 211 billion cubic feet of gas (BCFG) and 11 million barrels of natural gas liquids (MMBNGL).

Abstract The Taylorsville basin is a rift basin of Late Triassic to Early Jurassic age in east-central Virginia and adjacent Maryland. The basin has been a target for oil and gas exploration by Texaco and partners in the 1980s, when six continuous cores were drilled followed by three deeper exploratory wells. Currently, no hydrocarbon production has been established from the basin. Relatively thick sequences of dark-colored shale that may serve both as source rocks and self-sourced reservoirs for hydrocarbons have been encountered near the basin’s center. The current USGS assessment concludes that the mean values for undiscovered hydrocarbons in the basin are 1,064 billion cubic feet of gas (BCFG) and 37 million barrels of natural gas liquids (MMBNGL). The Taylorsville basin contains one composite total petroleum system, in which the hydrocarbon potential of the source beds and potential reservoirs were combined and assessed together as a single continuous gas assessment unit. Potential source rocks within the Taylorsville basin include coals and shales of the Triassic Falling Creek and Port Royal formations. Vitrinite reflectance data indicate that the source rocks range from pre-peak oil to peak gas thermal maturity. Potential reservoir rocks are continuous accumulations in shales, coal beds, and tight sandstones as well as possible conventional accumulations in porous and permeable strata within the Triassic Dowell and King George groups. However, well log based sandstone porosity values are generally low. Potential seals may be present in shale beds or igneous intrusions within the basin or by pore-throat restrictions within the continuous reservoir bodies.

Abstract The Reelfoot rift is one segment of a late Proterozoic(?) to early Paleozoic intracontinental rift complex in the south-central United States. The rift complex is situated beneath Mesozoic to Cenozoic strata of the Mississippi embayment of southeastern Missouri, northeastern Arkansas, and western Tennessee and Kentucky. The rift portion of the stratigraphic section consists primarily of synrift Cambrian and Ordovician strata, capped by a postrift sag succession of Late Ordovician to Cenozoic age. Potential synrift source rocks have been identified in the Cambrian Elvins Shale. Thermal maturity of Paleozoic strata within the rift ranges from the oil window to the dry gas window. Petroleum generation in Elvins source rocks likely occurred during the middle to late Paleozoic. Upper Cretaceous sedimentary rocks unconformably overlie various Paleozoic units and define the likely upper boundary of the petroleum system. No production has been established in the Reelfoot rift. However, at least nine of 22 exploratory wells have reported petroleum shows, mainly gas shows with some asphalt or solid hydrocarbon residue. Regional seismic profiling shows the presence of two large inversion structures (Blytheville arch and Pascola arch). The Blytheville arch is marked by a core of structurally thickened Elvins Shale, whereas the Pascola arch reflects the structural uplift of a portion of the entire rift basin. Structural uplift and faulting within the Reelfoot rift since the late Paleozoic appear to have disrupted older conventional hydrocarbon traps and likely spilled any potential conventional petroleum accumulations. The remaining potential resources within the Reelfoot rift are likely shale gas accumulations within the Elvins Shale; however, reservoir continuity and porosity as well as pervasive faulting appear to be significant future challenges for explorers and drillers.

Abstract Following its middle Miocene inception, numerous basins of varying lengths and depths developed along the Dead Sea fault zone, a large continental transform plate boundary. The modern day left-lateral fault zone has an accumulated left-lateral offset of 105 to 110 km (65 to 68 mi). The deepest basin along the fault zone, the Lake Lisan or Dead Sea basin, reaches depths of 7.5 to 8.5 km (24,500 ft to 28,000 ft), and shows evidence of hydrocarbons. The basins are compartmentalized by normal faulting associated with rapid basin subsidence and, where present, domal uplift accompanying synrift salt withdrawal. The stratigraphy of the fault zone is composed of a thick pre-wrench interval of early Tertiary to Precambrian strata overlain by a syn-wrench section of Miocene to Recent sediments. The main potential source rock is the pre-wrench Cretaceous Maastrichtian Ghareb Formation (and equivalents), which has a total organic carbon (TOC) content measurement of 8 to 18%. Lesser potential source rocks may also be found in the Pleistocene, Cretaceous (Turonian), Jurassic (Oxfordian–Callovian), and Triassic (Ladinian–Carnian). Geochemical analyses indicate that the source of all oils, asphalts, and tars recovered in the Lake Lisan basin is the Ghareb Formation. Geothermal gradients along the Dead Sea fault zone vary from basin to basin. Syn-wrench potential reservoir rocks are highly porous and permeable, whereas pre-wrench strata commonly exhibit lower porosity and permeability. Biogenic gas has been produced from Pleistocene reservoirs. Potential sealing intervals may be present in Neogene evaporites and tight lacustrine limestones and shales. Simple structural traps are not evident; however, subsalt traps may exist. Unconventional source rock reservoir potential has not been tested.

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 During the past 25 yr, several different tight-gas sandstone reservoirs have been brought into the nation’s productive natural-gas inventory. These include reservoirs of many different ages in many different basinal settings. In this chapter, reservoir discovery and management efforts at select fields in the Silurian Tuscarora, Devonian Oriskany, Pennsylvanian Pottsville and Jackfork, Jurassic Cotton Valley, Cretaceous Frontier and Almond, and Eocene Wilcox sandstones are reviewed, compared, and contrasted. Each of these target reservoirs is unique and both simple and complex. However, from a general understanding of the characteristics and variety of tight-gas reservoirs, a set of common generalities can be developed that may even be developed into rules for discovery. Although many tight-gas sandstone reservoirs may be classified as continuous-type reservoirs, (i.e., unconventional gas accumulations lacking well-defined field boundaries), tight-gas sandstone reservoirs are complexly subtle, with reservoir properties that are anything but continuous across their extent. Intentional discovery and development of tight-gas sandstone reservoirs requires knowledge, planning, careful execution, flexibility, and patience. A discovery model for the exploration and development of tight-gas sandstone reservoirs is proposed: (1) locate wells within a dry, gas-prone basin or part of the basin to avoid liquid (water, crude oil, or condensate) production, which will hurt gas-production rates; (2) select as intended targets depositionally heterogeneous reservoirs (i.e., channel systems), which are close to organic-rich intervals; (3) target slightly higher-shale-content sandstones instead of lower-shale-content sandstones (quartz arenites) to avoid loss of reservoir storage volume caused by cementation; (4) take advantage of whatever structure there is, and drill as high up on that structure as possible; (5) consider how you plan to manage a fractured, tight-gas reservoir (if fractures are anticipated to be present); (6) try to avoid sandstones with the potential for high water flow and low gas flow; (7) develop a clear petrophysical understanding of the reservoir early in the life of the field; and (8) plan on infill drilling once the initial spacing unit design is approved and implemented.

Abstract This report presents a review of the U.S. Geological Survey ( USGS ) 2007 assessment of the undiscovered oil and gas resources in Paleogene strata underlying the U.S. Gulf of Mexico Coastal Plain and state waters. Geochemical, geologic, geophysical, thermal maturation, burial history, and paleontologic studies have been combined with regional cross sections and data from previous USGS petroleum assessments have helped to define the major petroleum systems and assessment units. Accumulations of both conventional oil and gas and continuous coal-bed gas within these petroleum systems have been digitally mapped and evaluated, and undiscovered resources have been assessed following USGS methodology. The primary source intervals for oil and gas in Paleogene (and Cenozoic) reservoirs are coal and shale rich in organic matter within the Wilcox Group (Paleocene-Eocene) and Sparta Formation of the Claiborne Group (Eocene); in addition, Cretaceous and Jurassic source rocks probably have contributed substantial petroleum to Paleogene (and Cenozoic) reservoirs. For the purposes of the assessment, Paleogene strata have divided into the following four stratigraphic study intervals: (1) Wilcox Group (including the Midway Group and the basal Carrizo Sand of the Claiborne Group; Paleocene-Eocene); (2) Claiborne Group (Eocene); (3) Jackson and Vicksburg Groups (Eocene-Oligocene); and (4) the Frio-Anahuac Formations (Oligocene). Recent discoveries of coal-bed gas in Paleocene strata confirm a new petroleum system that was not recognized in previous USGS assessments. In total, 26 conventional Paleogene assessment units are defined. In addition, four Cretaceous-Paleogene continuous (coal-bed gas) assessment units are included in this report. Initial results of the assessment will be released as USGS Fact Sheets (not available at the time of this writing). Comprehensive reports for each assessment unit are planned to be released via the internet and distributed on CD-ROMs within the next year.

ABSTRACT Seismic stratigraphy and its more generic cousin, sequence stratigraphy, have revolutionized stratigraphic and depositional environment study in this decade. While seismic stratigraphy enables a broad view, translating the specific wiggle to a bedding plane contact has been (and remains) a subject of strong controversy. Recently published seismic and paleontologic work have emphasized a need for a bridge from the basin wide seismic line to the sample bag. The application of sequence stratigraphy to electric log cross sections is such a bridge. A study of the Tertiary of southwest Alabama well illustrates this technique. The Paleogene of southwest Alabama has been divided into four and a half supercycles from seismic sequence analysis and seventeen unconformity-bounded depositional sequences or cycles from outcrop and paleontologic study. Sequence stratigraphic analysis of an electric log cross section perpendicular to sedimentary strike and parallel to a regional seismic line reveals the geologic processes hidden by scale and resolution limits on the seismic line between the major bounding megasequence boundaries at the Cretaceous - Paleocene unconformity and the lower Miocene unconformity. Low-stand fans and wedges suggested by outcrop studies and too thin for seismic resolution become apparent. Condensed section shales dominate the downdip intervals and extend updip as thin, distinctive sections which punctuate the highstand, regressive deposits. Shelf margin buildups and their updip and downdip facies equivalents also become apparent.