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 Late Triassic Taylorsville basin is an onshore continental rift basin along the US Central Atlantic margin. The basin is one member of the early Mesozoic North American rift basin system that trends north–south from the southern US into maritime Canada and has formed within a wide rift zone between Early Triassic collapse of the Appalachian orogen and Jurassic initiation of Atlantic sea floor spreading. The basin, mostly buried under the Cretaceous and younger Atlantic Coastal Plain, is a half-graben having a western border fault. It was a target of conventional exploration drilling >25 years ago, although recent interest is in unconventional gas exploitation. Difference in kerogen type, basement and advective heat flow, and stratigraphic/hydrologic architecture among the Late Triassic–Early Jurassic rift basins is predictable when paleolatitude, paleoclimate, and position within the late Paleozoic Appalachian orogen are considered. For example, the Taylorsville basin, which formed in a humid equatorial climate, is a gasprone overfilled-lake-type basin, in contrast to the temperate oil-prone balanced- to underfilled Newark rift-lake basin. Downhole vitrinite reflectance data and maturation modeling show that the Taylorsville basin, along the axis of Appalachian metamorphism/orogenic collapse, experienced long-term elevated heat flow modified by synrift gravity-driven cross-basin fluid flow (40–55°C/km), compared to the off-axis Newark basin (≤35°C/km). Postrift structural inversion resulted in variable (<1 to >3 km) erosion of Taylorville synrift strata. Duration of sedimentation modeling suggests basin synrift sedimentation likely ended before the Jurassic, unlike sister basins to the north with extant earliest Jurassic formations.

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 Two continuous gas assessment units (AU’s) are present in the Late Triassic (Norian) onshore rift basins of North Carolina and south-central Virginia. Continuous AU’s are the USGS classification/nomenclature for the oil and gas rich resource plays industry has been pursuing and exploiting throughout the continental United States. “Continuous gas assessment units” include tight gas sandstone as well as two resource plays—coal-bed methane and shale gas/oil. The USGS assessed the East Coast Mesozoic rift basins as continuous gas AU’s primarily as tight gas AU’s because oil and gas have been found (although not produced) from tight ( i.e. , low porosity and permeability) sandstones, coal beds, and shale beds/intervals. The source rocks are lacustrine shales that were deposited in freshwater lakes that were near the paleo-equator after the onset of Pangea rifting. These two rift basins, the Deep River basin wholly within North Carolina, and the Dan River-Danville basin, located in north-central North Carolina and south-central Virginia have been assessed numerically as part of the USGS’s National Petroleum Resource Assessment ( Fig. 1 ). The name ‘Dan River-Danville basin’ is used by the U.S. Geological Assessment team for assessment, and the name, ‘Dan River basin’ is used herein following stratigraphic revision and formal basin naming in 2015 ( Olsen et al. , 2015 ). These two rift basins are part of a series of larger continental series rift basins that formed during the Permian to Early Jurassic extension in central Pangea as the supercontinent began to fragment. Figure 1. Map of the Eastern United States showing the location of the five quantitatively (volumetrically) assessed East Coast Mesozoic basins (in red), the nine basins that were not volumetrically assessed (in orange), and the U.S. Geological Survey province boundaries. Each basin includes a single continuous gas assessment unit ( Milici et al. , 2012 ). These continuous gasprone AUs each have a single total petroleum system (TPS). The Deep River basin continuous AU has an estimated mean gas content of 1,660 billion cubic feet of gas (BCFG) and an estimated mean of 83 million barrels of natural gas liquids (MMBNGL). Noble gases have been documented from two shut-in wells in the Deep River basin by the North Carolina Geological Survey in a separate study ( Reid et al. , 2015c ). The Dan River-Danville basin continuous AU has an estimated mean gas content 49 BCFG and no natural gas liquids from data available in 2011 assessed by the U.S. Geological Survey ( Milici et al. , 2012 ) ( Table 1 ). Table 1. East Coast Mesozoic basin assessment results ( Milici et al. , 2012 ). The Deep River basin composite TPS and the Dan River-Danville basin composite TPS assessment results and data for other basins. Note - MMBO, millions of barrels of oil; BCFG, billion cubic feet of gas; MMBNGL, million barrels of natural gas liquids; TPS total petroleum system; AU, assessment unit. Results in the table are fully risked estimates. For gas accumulations, all liquids are included as NGL (natural gas liquids). F95 represents a 95-percent chance of at least the amount tabulated; other fractiles are defined similarly. Fractiles are additive under the assumption of perfect positive correlation. Gray shading indicates not applicable ( Milici et al. , 2012 ). The Dan River basin stratigraphy has been clarified by Olsen et al. (2015) . A continuous 1,477-foot-deep stratigraphic core hole drilled in 2015 by the North Carolina Geological Survey penetrated a 323-ft-thick unconventional lacustrine shale reservoir containing a 3-ft-thick coal having gas shows in the coal and lower siltstone and then drilled through an underlying siliciclastic formation containing previously unknown thin organic strata, to basement at a depth of 1,451.2 ft below the surface. The Cumberland-Marlboro ‘basin,’ a large, strike-parallel and seaward negative aeromagnetic anomaly that is buried beneath thin unconsolidated coastal plain sediments, also was drilled and cored (three Rotasonic holes) in 2015 by the North Carolina Geological Survey. Metasedimentary Paleozoic(?) basement rock was recovered; no Triassic strata were present. Additional information that accompanies this extended abstract is found in Appendices 1–3.

Abstract Over the past decade, discoveries of super-giant, multibillion barrel presalt oil fields in Brazil’s offshore basins and related discoveries in its African conjugates highlighted the great importance of synrift/prebreakup fluvial-lacustrine successions to the success and efficiency of their petroleum systems. Improvements in seismic acquisition and processing technologies were keys in imaging the architecture of the underlying rift basins, and interpreting the basin fill and internal depositional facies later confirmed by drilling. Middle Triassic to Early Jurassic synrift basins are exposed onshore eastern North America and extend into adjacent offshore areas, including equivalent basins in Northwest Africa. Organic-rich lacustrine successions occur in a number of the U.S. basins and although no commercial discoveries have been made, hydrocarbon shows in outcrops and wells confirm that a working petroleum system exists in virtually every basin. The basin-fill model for these extensional basins’ sedimentary successions defines four tectonostratigraphic (TS) units. In the Fundy-Chignecto rift basin complex, TS I is an unconformity-bounded, early synrift fluvial-eolian sequence of Late Permian age. TS II is a dominantly fluvial (with some lacustrine) sequence believed representative of an underfilled, hydrologically open basin (subsidence < sedimentation). This is followed by either a closed basin or one in hydrological equilibrium (subsidence ≥ sedimentation) dominated by lacustrine (TS III), and later playa/lacustrine (and basal CAMP volcanics) successions (TS IV). The climate sensitive lacustrine facies—especially in TS III—are exquisite recorders of paleoclimate, and with paleomagnetic data refine the determination of the basins’ age and paleolatitudinal positions. Seismic profiles in the Fundy-Chignecto (Canada) and Newark (USA) basin reveal high-amplitude, laterally continuous reflections adjacent to the respective border faults. In the Newark basin, these are calibrated against academic and industry wells revealing a correlation with large scale climatic cycles and lacustrine facies in TS III. In both basins, similar reflections are observed in the undrilled distal portion of TS II fluvial successions and are interpreted as indicating similar lacustrine successions. This architecture departs from the original TS II model (subsidence < sedimentation) by inferring high levels of tectonically driven extension resulting in the basins being closed from their inception (subsidence ≥ sedimentation) thus facilitating lake formation. During TS II deposition (approximately Late Anisian to Early Carnian), paleomagnetic data positions these basins within the north equatorial humid belt. This is a favorable setting for the evolution of lakes; i.e. , elevated precipitation coupled with tectonic extension, and most importantly, under conditions for organic matter creation and preservation. If correct, this interpretation would have a significant impact on the potential for hydrocarbons sourced from Late Triassic lacustrine successions in presalt synrift basins offshore Nova Scotia and Morocco. Importantly, a potential new oil-rich resource play may exist beneath the shallow waters of Chignecto Bay. In the deep water portion of the offshore Scotian basin, presalt synrift basins having similar lacustrine source rock potential may also exist.

Abstract Drilling and geophysical data demonstrate that the Mississippi Valley graben, the Rough Creek graben, and the Rome trough are fault-bounded graben structures filled with as much as 27,000 feet of Cambrian sediments. Data including stratigraphic tops from 1,764 wells, 106 seismic profiles, aeromagnetic and gravity surveys, and mapped surface geology at a 1:24,000 scale have been used to study seven stratigraphic packages resolvable in both wells and seismic profiles across parts of Kentucky, Ohio, Indiana, Illinois, Missouri, and Tennessee. Detailed analyses of the thickness patterns of these stratigraphic packages have been used to interpret the locations and timing of movements along major faults systems in the study area. Active rifting of the Precambrian crystalline bedrock began by the Early Cambrian, and resulted in thick, sand-rich deposits of the Reelfoot Arkose in the Mississippi Valley graben and Rough Creek graben, and the Rome Formation in the Rome trough. Subsidence continued in these grabens during the Middle to Late Cambrian, leading to an alternating succession of shales and carbonates being deposited (Eau Claire Formation of the Illinois basin and Conasauga Group of the Appalachian basin) on top of the coarse clastic Reelfoot Arkose and Rome Formation. Although the tectonic extension that formed these features ended by the Late Cambrian, fault zone reactivation during the Taconic, Acadian, and Alleghenian Orogenies altered fault block orientations and produced areas of basin inversion, creating the possibility of numerous deep structural traps for hydrocarbons sourced by the Cambrian shales of the Eau Claire Formation and Conasauga Group.

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 The geological understanding of the opening of the Western Black Sea Basin appears to be quite far from being reasonably resolved. The main faults used in the existing map-view reconstruction schemes are either very poorly defined (West Black Sea fault) or simply nonexistent as interpreted earlier (West Crimean fault) and therefore they need be redefined or replaced by other structural elements. Various kinematic elements and facies boundaries on the conjugate margins of the Western Black Sea ( i.e. , the Bulgarian, Romanian and Ukrainian margin in the northwest versus the Turkish margin in the southeast) appear to be a key in constraining the opening geometry of the basin. The along-strike changes in the synrift structural pattern of the Bulgarian-Romanian margin, reflecting contrasting crustal rheologies inherited from prerift deformational phases, do appear to have their counterparts in the offshore part of the conjugate Turkish margin including the Pontides. A correlation of regional 2D reflection seismic and well data, and the critical review of the relevant onshore geology did provide some preliminary corresponding tie-points to constrain the kinematics of the basin opening. If the European margin is fixed in a kinematic reconstruction, the clockwise opening of the rift basin occurred along northwest–southeast trending transform faults around an Euler rotation pole positioned to the southwest of the present Black Sea. The rotational element in the opening of the Western Black Sea Basin, as opposed to the dominantly translational kinematics used in some of the existing kinematic models, is also supported by the broadly triangular shape of oceanic crust imaged in the basin center.

Abstract A regional, long-offset 2D reflection seismic grid that images the basin to a depth of ~30–40 km has been studied across the entire Western Black Sea Basin (WBSB). Mapping the structure and the stratigraphy of the basin on these transects provides valuable insights into the basin dynamics. An approximately 50–150 km wide zone (Turkish margin and Ukrainian sector, respectively) that roughly agrees with the present-day shallow shelf area corresponds to unstretched continental crust having a thickness of 35 km. Normal faults detach at a depth of about 15–20 km, marking the brittle-ductile transition zone. Some of the rift-related normal faults can be shown to be a re-activation of the older structural grain. Basinward, there is a distinct segment of the margin consisting of stretched continental crust and the interpreted Moho reflection located at about 20 km. The width of this zone is fairly uniform in the Bulgarian-Romanian-Ukrainian sector (80–110 km) but is much less on the Turkish side (30 km). In the central part of the basin, we interpret two distinct basement types. In the East, between the Ukraine and Turkey, there is a transparent 7 km thick seismic facies interpreted to consist of oceanic crust. The zone occupied by this crust has a broadly triangular shape. The center of the basin in the Bulgaria-Turkish sector shows a strikingly different seismic facies: rotated fault blocks, fault planes, magmatic intrusions, and large paleo-volcanoes representing extremely stretched continental crust, very much akin to that described in other passive margins ( i.e. , offshore Iberia). Assuming plane strain deformation and constant crustal area on the 2D lines during and after the rifting, we calculate approximately 250 km of extension in the eastern part of the WBSB, and progressively smaller values to the west; i.e. , ~110 km at the westernmost seismic line. High extension values also correlate well with the position of the oceanic crust. This systematic variation in stretching values and crustal types is best explained by assuming clockwise rotation of Turkey away from the conjugate margins on the northwest.

Abstract Predicting potential sandstone reservoir character of deep-water sedimentation units in the postrift subsurface section of the Morocco Atlantic coast is problematic as there are only a few deep wells in the area. Two key control points for uppermost Jurassic to Lower Cretaceous deposition in this area are the Deep Sea Drilling Project (DSDP) Leg 41, Site 370 (1975), and DSDP Leg 50 Site 416 (1976) cores. Sites 370 and 416 are located approximately 150 kilometers from the coast of Morocco, and are in 4,200 m of water, at the base of the continental slope. Sedimentologic characterization of cored strata in the 1978 and 1980 DSDP volumes is generalized, and only a few restricted intervals are described in detail. This study presents results from a new lithologic description of 440 meters of conventional core from Sites 370 and 416. Strata range from Tithonian to Albian in age. Claystone and siltstone are the dominant lithofacies and comprise 91% of the cores. The cores also contain 6.8% sandstone, 1.7% fine-textured carbonate, and 0.6% carbonate grainstone. The focus here is on the sandstone and grainstone. Sandstone beds are either Bouma turbidites (26.4%) or contourites (73.6%). Sandstone turbidite beds range from centimeter to several decimeters thick, and are not preferentially distributed within the Mesozoic section. Contourite beds are ≤4 cm. Carbonate grainstones occur in Valanginian to Aptian strata. They were deposited as calciturbidites, and contain platform derived carbonate grains. The presence of numerous turbidite beds (>200) distributed throughout the Tithonian to Albian strata suggests the repeated occurrence of throughgoing turbidite fairways on the Morocco Atlantic slope.

Abstract In 2012, Beglinger et al . (2012a , b, and c) published a series of papers in which they systematically made analogous comparisons between the West African and Brazilian South Atlantic salt basins in order to identify new exploration opportunities. They believed that although every basin in the world is unique, they can still be classified according to their structural genesis and evolutionary history. This classification was based on breaking basins down into their tectonostratigraphic basin cycles or megasequences. By defining their characteristics with respect to the development of source, reservoir, and seal rocks, a data set of potential analogs can be compiled. This data set allowed for the identification of key combinations of elements and processes that resulted in an effective exploitable petroleum system, and assist in the evaluation of exploration opportunities in un- and under-explored basins ( Beglinger et al ., 2012a , b , and c ). Several tools can be used in such an analysis: the trajectory plot, tectonostratigraphies, the petroleum system flow diagram, events charts, creaming curves, field size distribution diagrams ( Beglinger et al ., 2012a , b , and c ), and areal field distribution maps. In this paper, the most recent exploration results in the Gabon Coastal basin will be reviewed in light of the framework that was established for the basin by Beglinger et al . (2012a , b ).

Abstract Coupled thermal-kinematic finite-element modeling done in 3D is used to study spatial and temporal distribution patterns of the lower crustal viscosity at transform margins during their continent-ocean transform development and passive margin stages. Modelled scenarios combine different pre-rift thermal regimes and lower crustal rheologies. The outcome indicates that substantial parts of the lower crust have the potential to flow at geologically appreciable strain rates. This discovery can lead to our better understanding of lateral variations in uplift/subsidence, upper and lower crustal thicknesses, and Moho depth. Modeled low viscosity zones having effective viscosities below 1018 Pa s make up ductility distributions, which vary spatially and temporally during the entire margin evolution. Thermal history-related ductility patterns can be divided into three categories, including: (1) reduced lower crustal viscosities controlled by continental rifting and break-up in extensional and pull-apart terrains near transforms; (2) reduced lower crustal viscosities along the transform caused be the migrating ridge and oceanic crust; and (3) the background reduced viscosity resulting from the equilibrium temperature field. Superposition of these ductility patterns and the complex interaction of the underlying perturbations of the temperature field result in differences in the potential for lower crustal flow both in space and time. Our modeling results provide templates for the understanding of lower crustal flow at transform margins in general. They await follow-up studies focused on comparing their results with data on thermal regime, maturation history, and uplift/subsidence patterns.

Abstract The Los Angeles basin is a Neogene rift containing a nearly ideal petroleum system. Highly organicrich strata accumulated slowly during tectonic rotation, followed by rapid subsidence and burial beneath thick successions of submarine fan deposits and nonmarine sediments. Late Miocene and Pliocene slope-channel and basin-floor fan sandstones are the main reservoirs. Most petroleum accumulations have been found in faulted anticlines that are associated with the principal structures of the basin and that have been greatly enhanced and modified by transpressional tectonics during the past 6 million years. The basin’s 68 named oil fields probably originally contained more than 40 billion barrels of oil in place. In spite of many years of production, large volumes of technically recoverable petroleum remain in undiscovered accumulations, as additional recoverable oil in existing fields, and possibly in source-rock system reservoirs. Additional large-scale development is problematic, however, owing to the complexities of oil production within a modern megacity.