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In easternTexas, a thick (150-200 ft) interval of Lower Cretaceous upper Glen Rose D strata was deposited in the Houston trough intrashelf basin landward of the Stuart City reef margin and seaward of the main eastern Texas intrashelf basin. The stratigraphic section in this intrashelf basin forms a primarily oil-bearing hydrocarbon system where porous grainstones in the Alabama Ferry and Fort Trinidad fields were deposited coevally with organic-rich calcareous argillaceous mudstones. Here, we present evidence to suggest that the depositional setting within the Houston trough and the contained ooid grainstone beds were of deeper-water origin (400-500 ft), below storm wave base. Further, the water column was stratified, allowing dysaerobic to anaerobic conditions to develop, fostering accumulation and preservation of organic matter. Grain-rich gravity flows consisting of ooids, intraclasts, and thin-walled mollusks, derived from the shallower shelf to the northwest, were deposited in the basin, forming the Alabama Ferry and Fort Trinidad fields. The upper Glen Rose interval is composed of lithofacies that vary laterally within the Houston trough. Five lithofacies are recognized on the basis of sedimentary features, texture, fabric, biota, and organic-matter content: (1) laminated to nonlaminated argillaceous lime mudstone to lime wackestone; (2) laminated to nonlaminated calcareous siliciclastic mudstone to siltstone; (3) intraclast–ooid skeletal lime packstone; (4) intraclast–bivalve–ooid lime grainstone; and (5) oyster lime floatstone and rudstone. Grain-rich lithofacies laterally adjacent to and interbedded with organic-rich argillaceous lime mudstones and calcareous siliciclastic mudstones were previously interpreted as being deposited in a tidally influenced, high-energy, shallow-water shoal environment; however, reconstruction of the depositional setting and interpretation of the vertical and lateral distribution of lithofacies suggest that these lithofacies were deposited as grain-rich gravity flows into the deeper-water Houston trough. This interpretation suggests a new conceptual framework integrating facies models from submarine channel and fan complexes to explore for grainstone reservoirs similar to Alabama Ferry and Fort Trinidad fields.

Berea reservoirs in eastern Kentucky are developed in tight siltstone and sandstone. Precision horizontal drilling provides access to thin ( 0.1 md, porosity is generally >10%. Cement in Berea samples includes quartz overgrowths, ferroan dolomite, siderite, pyrite, and kaolinite. In addition, these rocks were subject to varying degrees of intergranular compaction, quartz overgrowths, and secondary porosity formation (grain dissolution). In thin section, three pore types were encountered: (1) primary intergranular pores, (2) secondary moldic pores, and (3) microporosity. Intergranular porosity is most common. Mercury capillary injection tests show that moderate-permeability (0.02–0.2 md) Berea has pore size distributions of 1 to less than 0.1 μm, but mostly from 0.5 to 0.6 μm, which are commonly found in gas reservoirs. Higher-permeability samples (1.2–2.0 md) have pore-throat diameter distributions of 2 to >0.1 μm. The highest pore volumes (near 3.25%) have pore diameters of 1–2 μm, which is more characteristic of oil-producing reservoirs.

With development dating from the 1800s, the Devonian Berea Sandstone has a long history of oil and gas development in the Appalachian Basin. A new phase of development began in northeastern Kentucky in 2011 with production of high-gravity oil from horizontal wells at depths less than 2200 ft (

Detailed facies characterization in the Wolfcamp B and lower Spraberry intervals of two drill cores in the Midland Basin has yielded five main lithofacies with distinctive physical, chemical, and biologic attributes. The main attributes for facies identification include lithology and/or mineralogy, texture and/or fabric, porosity, hydrogen index, and total organic carbon content. The methodologies are focused on detailed core description, thin-section petrography, quantitative x-ray diffraction, and field emission scanning electron microscopy (SEM). Porosity data are primarily based on Gas Research Institute (Core Laboratories) measurements and field emission SEM assessment. Moreover, the depositional and diagenetic controls on facies development are addressed to assess the dominant geological processes that govern reservoir quality and distribution. A model of five end-member facies is proposed to characterize source and reservoir elements through delineating facies tracts. The five end-member facies are as follows: facies 1: silty mudstone, optimal source, and optimal to fair reservoir; facies 2: muddy siltstone (optimal source and optimal reservoir); facies 3: silty calcareous mudstone (good source and good reservoir); facies 4: bioclastic wackestone–floatstone (fair source and fair reservoir); and facies 5: packstone–grainstone (poor source and poor to excellent reservoir). The proposed facies scheme aims to provide a more comprehensive approach to capture the high vertical and lateral variability in this mixed carbonate and fine-grained clastic succession. Through this detailed textural, compositional, sedimentologic, and diagenetic approach, this facies model can be used to better understand reservoir quality and distribution throughout the Midland Basin.

The lacustrine shale of the Upper Cretaceous Qingshankou Formation is the principal prospective unconventional target lithology, acting as source, reservoir, and seal. Lithofacies and associated storage capacity are two significant factors in shale oil prospectivity. This paper describes an investigation of the lower Qingshankou Formation lacustrine shale based on detailed description and analysis of cores, shale lithofacies characteristics, depositional setting, and stacking patterns. Seven lithofacies are recognized based on organic matter content, sedimentary structure, and mineralogy, all exhibiting rapid vertical and lateral changes controlled by the depositional setting and basin evolution. An overall trend from shallow-water to deep-water depositional environments is interpreted from the characteristics of the infilling sequences, characterized by increasing total organic carbon (TOC) and total clay content and decreasing layer thickness (i.e., from bedded to laminated then to massive sedimentary structures). Periods of deposition during shallowing cycles show a reverse trend in the sedimentary characteristics described above. The sedimentary rocks in the studied interval show three complete short-term cycles, each one containing progressive and regressive system tracts. Massive siliceous mudstones with both high and moderate TOC are considered to have the best hydrocarbon generation potential. Laminated siliceous mudstones, bedded siltstones, and calcareous mudstones with moderate and low TOC could have the same high hydrocarbon saturations as the high-TOC massive siliceous mudstones, but these lithologies contain more brittle minerals than the massive mudstones. Several siltstone samples show low or zero saturation of in situ hydrocarbons; this is considered to be related to a combination of fair to poor hydrocarbon generation potential and extremely low permeability, limiting migration. Moderate-TOC laminated siliceous mudstones were also observed to have connective pore-fracture networks. It can be demonstrated that successive thick sequences of moderate-TOC laminated siliceous mudstones, showing high volumes of hydrocarbon in situ, a high mineral brittleness index, and good permeability, combine to form shale oil exploration “sweet spots.”

This study describes the sedimentology and stratigraphy of the Devonian–Mississippian Sappington Formation in exceptional outcrop exposures in southwestern Montana. The goal was to assess the extent to which these outcrops could be used to define stratigraphic heterogeneity of time-equivalent Bakken Formation reservoir and source rocks of the Williston Basin. Facies analysis of the Sappington Formation shows three depositional sequences deposited along a storm- and wave-influenced coastline. The first sequence encompasses the lower Sappington shale, dominated by organic-rich mudstones that represent an anoxic to dysoxic lower-shelf environment. The second sequence is marked by a basal transgressive surface and initial siltstone deposition. These siltstones are abruptly overlain by basinward-dipping, low-angle clinoforms (

The Middle Jurassic Lajas Formation in the Neuquen Basin of Argentina has been considered an ideal analog for tide-dominated deposits because of the widespread presence of tidal sedimentary structures and its heterolithic nature. Outcrops of the Lajas in the Los Molles area provide excellent exposures allowing both sedimentary structures and large-scale architectural information to be documented in detail. The extensive event bed stratification that characterizes the delta front and interdistributary bay deposits is interpreted to be the result of river floods because of the sharp base, fining-upward grain size trend, and seaward-directed paleocurrent indicators within each bed. The absence of wave-generated structures precludes a storm wave origin for these beds. Interflood deposits have two forms. The first is fine-grained sandstone and siltstone that is highly bioturbated with no tidal structures and is indicative of an overall river-dominated system. The second is also finer grained than the river flood beds but shows distinctive tidal features, indicative of a tide-influenced system during times when river influence was least. Mouth bars can be classified as purely river-dominated or river-dominated with tidal influence, depending on the type of interflood beds present. Tide-influenced mouth bars tend to be muddier, with more internal flow baffles or barriers and a lower-angle dip than their river-dominated counterparts. This study suggests that heterolithic successions containing pervasive tidal structures need not be tide-dominated because not all tidal structures are of equal importance in environmental interpretations. Their location (in river flood layers versus interflood layers) can be used as a methodology for determining the dominant and subordinate processes responsible for shaping the delta.

The Lower Mississippian upper shale member of the Bakken Formation in the Williston Basin, North Dakota, consists of organic-rich, black, siliciclastic mudstones deposited offshore on a low-gradient shelf; 12 fine-grained facies are recognized and grouped into 5 facies associations (FAs). Very fine-grained, massive to faintly laminated mudstone (FA1) records deposition in the deepest, calmest parts of the basin, whereas well-laminated mudstones (FA2a); well-laminated, clay-clast–bearing mudstones (FA2b); burrow-mottled mudstone with shells (FA3); and interlaminated siltstone and mudstone (FA4) suggest deposition in the shallower, less calm, and more proximal offshore environment. These proximal-offshore mudstones (FA2a, FA2b, FA3, and FA4) reflect (1) variation in bottom-water oxygen levels and (2) lateral changes in the input of silt and clay clasts. Ubiquitous Phycosiphon fecal strings, patches of shells, burrows, and rare agglutinated foraminifera indicate dysoxic to suboxic basinal deposition and not a persistently anoxic environment. In all FAs, storm-event laminae are sparse to ubiquitous. Repeated stacking of FAs defines up to 10 coarsening-upward parasequences mostly 0.15–0.60 m (0.49–1.97 ft) thick. Individual parasequences can be correlated for 300 km (180 mi) through the basin. The lower half of the succession (interval 1) represents a transgressive systems tract and shows high radiolarian productivity with minor silt input. The upper half of the succession (interval 2) represents the base of a highstand systems tract. In contrast to interval 1, interval 2 mudstones are characterized by high clay content, low radiolarian productivity, and intermittent colonization of the sea floor during higher-order sea-level lowstands.

The lower section of the lower Silurian Qusaiba Member, Qalibah Formation, is characterized by regionally developed organic-rich shales that have sourced many of the large Paleozoic petroleum systems of Saudi Arabia. In northern Saudi Arabia, these high–total organic carbon (TOC) horizons are being assessed for their unconventional shale-gas potential. The initial phase of exploration drilling, which resulted in a quadrupling of the number of penetrations in northern Saudi Arabia, had the dual purpose of (1) assessing the high-TOC horizons as an unconventional resource play and (2) acquiring the fundamental data required to understand the geologic development of the zones of interest within the lower Qusaiba. The availability of numerous new cores from across northern Saudi Arabia enabled an extensive refinement of the existing biostratigraphy and enhanced integration between graptolite and palynomorph biozonation systems. In cores from the study area, four distinct sedimentary facies are recognized, (1) pyritic siltstone, (2) black mudstone, (3) black chert, and (4) gray shale, representing distinct paleoenvironmental conditions related to the stepped latest Ordovician and early Silurian Gondwanan deglaciation. The failure of the Gondwanan ice sheet was not a simple, short-lived, consistent melting and associated flooding of a flat continental shelf. This study highlights the complex interplay of sea-floor topography, ocean currents, sediment supply, and variations in the rate of melting of the ice sheet. With the associated rising ambient temperatures there are (1) increasing clay concentrations associated with intensifying chemical weathering of the exposed land mass and (2) progressive lowering of the carbonate compensation depth as water temperatures rise, enabling the preservation of carbonate shell material.

The reservoir sedimentology and depositional environment of the Lower Cretaceous Alam El Bueib Formation in the Betty-1 well, Shoushan Basin, were investigated by studying lithofacies, petrography, and calcareous nannofossils. The sedimentary lithofacies indicate a fluvial to shallow-marine depositional environment. We have lithologically identified and described five lithofacies assemblages (massive-sandstone facies; cherty massive-sandstone facies; argillaceous-sandstone facies; heterolithic, laminated sandstone/shale facies; and sandy/silty–shale facies); we have petrographically identified and described seven microfacies (laminated claystone and siltstone; ferruginous quartz–arenite; feldspathic ferruginous quartz–wacke; quartz–arenite; anhydritic quartz–arenite; biomicrite; and sandy-limestone microfacies). Calcareous nannofossils were used to determine the age of the investigated deposits. The calcareous-nannofossil species led to the recognition of two nannofossil zones of the Early Cretaceous (Nannoconus bermudezi zone of the Hauterivian and Nannoconus colomi zone of the Barremian). The studied sandstone reservoirs can be classified as compositionally immature feldspathic arenite and wacke. The main diagenetic minerals of the sandstones include authigenetic clay minerals, calcite cement, quartz overgrowth, and later ferroan carbonate. Wide porosity variations in sandstones correlate with an abundance of grain-coating clays and consequent inhibition of quartz cementation. Secondary porosity has been created mainly by feldspar, rock-fragment dissolution, and clay-matrix dissolution.

The purpose of this work was to study the depositional mechanisms and significance of the Longmaxi shale in the Sichuan Basin in southern China. Seven lithofacies were identified based on the detailed observation of outcrops and cores using petrographic and scanning electron microscope examination of thin sections and other data analyses: (1) laminated calcareous mudstone, (2) laminated carbonaceous mudstone, (3) laminated silty mudstone, (4) laminated claystone, (5) laminated siliceous shale, (6) siltstone, and (7) massive mudstone. The laminated mudstone and laminated claystone originated from suspension deposition, and siliceous shale is associated with ocean upwelling, whereas massive mudstone and siltstone were primarily deposited by turbidity currents. The depositional mechanisms have a great effect on the source rock and reservoir properties. Suspension deposition near oceanic upwelling zones can provide favorable conditions for the production and preservation of organic matter and are thus conducive to the formation of high-quality source rocks (total organic carbon content up to 5.4%). The reservoir storage spaces are primarily interlaminated fractures and organic pores with good physical reservoir properties (high porosity, permeability, and brittle mineral content). Turbidity currents may carry a large quantity of oxygen to the seafloor, resulting in the oxidation of organic matter, which is unfavorable for its preservation. The lithofacies formed by turbidity currents have relatively low total organic carbon contents (average

The sedimentologic and tectonic histories of clastic cap rocks and their inherent mechanical properties control the nature of permeable fractures within them. The migration of fluid through mm- to cm-scale fracture networks can result in focused fluid flow allowing hydrocarbon production from unconventional reservoirs or compromising the seal integrity of fluid traps. To understand the nature and distribution of subsurface fluid-flow pathways through fracture networks in cap-rock seals we examine four exhumed Paleozoic and Mesozoic seal analogs in Utah. We combine these outcrop analyses with subsidence analysis, paleoloading histories, and rock-strength testing data in modified Mohr–Coulomb–Griffith analyses to evaluate the effects of differential stress and rock type on fracture mode. Relative to the underlying sandstone reservoirs, all four seal types are low-permeability, heterolithic sequences that show mineralized hydraulic-extension fractures, extensional-shear fractures, and shear fractures. Burial-history models suggest that the cap-rock seal analogs reached a maximum burial depth >4 km (2.5 mi) and experienced a lithostatic load of up to 110 MPa (15,954 psi). Median tensile strength from indirect mechanical tests ranges from 2.3 MPa (334 psi) in siltstone to 11.5 MPa (1668 psi) in calcareous shale. Analysis of the pore-fluid factor () through time shows changes in the expected failure mode (extensional shear or hydraulic extension), and that failure mode depends on a combination of mechanical rock properties and differential stress. As expected with increasing lithostatic load, the amount of overpressure that is required to induce failure increases but is also lithology dependent.

The Eau Claire Formation of the midwestern United States was evaluated for its potential use as a confining unit (seal) overlying a sandstone reservoir to securely store injected . This evaluation included: (1) lithofacies composition and distribution, (2) capillary entry pressure analysis, and (3) fluid- and fracture-pressure analysis. The regional distribution of lithofacies in the Eau Claire was evaluated by examination of core and log data from selected wells across the study area. Log data were used to define electro-lithofacies, which are spatially variable and represent a mixture of shale, siltstone, sandstone, limestone, and dolomite. Because of the significant variation in lithofacies and the complex spatial distribution, the entire interval should be considered in evaluating the seal capacity of the unit at a given locality. Mercury-injection capillary pressure (MICP) data were obtained on 17 samples of Eau Claire lithofacies ranging from muddy shale to sand/silt to evaluate the potential for capillary entry of fluids into the pore system of the lithofacies of the unit. Interpretation of these data indicated capillary failure of the muddy shale lithofacies is unlikely. However, many of the MICP samples contain millimeter-scale silt/sand interbeds, which would probably allow entry but, because these beds commonly have very limited lateral continuity, they are very unlikely to provide pathways for large-scale leakage through the interval. Evaluation of structural settings, lithostatic and existing formation aquifer pressures in the Eau Claire, in conjunction with the height of columns stored in the underlying Mount Simon Sandstone (Cambrian), suggest that fluid pressures induced by a static buoyant plume are unlikely to induce fractures in the formation. However, elevation of the aquifer pressure during injection may be capable of creating fractures within the unit.

Concerns about potential climate change related to greenhouse gas emissions have spurred researchers across the world to assess the viability of geologic storage of CO2. In the Illinois Basin in the United States, the Cambrian Mount Simon Sandstone has been targeted as a reservoir for carbon capture and storage (CCS). In this CCS system, the Eau Claire Formation is expected to serve as the primary seal to prevent upward migration of the CO2 plume; however, little work has been done to specifically determine how well it will function as a seal. Although the lateral extent and thickness of the Eau Claire Formation, along with its generally low permeability, certainly make it a prime candidate to serve in this capacity, the primary depositional fabric and mineralogy, which are the fundamental controls on the petrophysical charter of this unit, remain poorly constrained. Therefore, the purpose of this study is to investigate the lithologic, mineralogical, and petrophysical properties of the Eau Claire Formation in an effort to characterize its potential as a functional seal in a CCS system. Sixty-six core-derived Eau Claire Formation samples from seven wells within the Illinois Basin are described using a combination of petrography, reflectance spectroscopy, x-ray diffraction, geochemical, and petrophysical analyses. These analyses show that the Eau Claire Formation contains five different lithofacies (sandstone, clean siltstone, muddy siltstone, silty mudstone, and shale) with fine-scale heterogeneities in fabric and mineralogy that greatly influence the petrophysical properties. Porosity, permeability, and entry-pressure data suggest that some, but not all, lithofacies within the Eau Claire Formation have the capability to serve as a suitable CCS seal. Abundant authigenic minerals and dissolution textures indicate that multiple generations of past fluid-rock interactions have occurred within the Eau Claire Formation, demonstrating that much of the formation has behaved as a fluid conduit instead of as a seal. Minerals that would be potentially reactive in a CCS system (including carbonate, glauconite, and chlorite) are common in the Eau Claire Formation. Dissolution of these and other phases in the presence of carbonic acid could potentially jeopardize the sealing integrity of the unit. Although complexities in the sealing properties exist, the dynamics of the CCS system and the potential for precipitation of new minerals should allow the Eau Claire Formation to serve as an adequate seal.

The Upper Devonian–Lower Carboniferous Bakken Formation is a widespread siliciclastic unit in the subsurface of the Williston Basin that is subdivided into three members: lower and upper organic-rich shale members and a dolomitic, silty, and sandy middle member. Although the unit has become one of the most active oil plays in North America and numerous sedimentologic studies have been made, no consensus about the depositional environments of the middle member has been achieved. Previous studies suggested several depositional and sequence-stratigraphic scenarios, including lowstand offshore-shoreface, normal-regressive offshore-shoreface, incised estuary, and falling-stage shoreface complexes for the middle member. We propose a new depositional and sequence-stratigraphic model and compare it with some previous interpretations. This new model includes a basal transgressive systems tract (TST) embracing shelf deposits, a highstand systems tract comprising shelf to lower shoreface environments, and an upper TST encompassing a brackish-water embayment complex and offshore to shelf settings. Petrophysical characterization of the sedimentary facies reveals that bay-mouth cross-stratified fine-grained sandstone, flaser-bedded very fine grained sandstone formed in wave-dominated tidal flats, offshore-transition highly bioturbated interbedded very fine grained sandstone and siltstone, and tidal-flat very fine grained sandstone with common mud drapes possess the best reservoir qualities. Recognition of a restricted embayment within the Bakken middle member has major implications for both exploration and production. Embayment facies with good reservoir quality constitute good oil prospects in localized areas, whereas fully marine facies may represent good oil prospects of more regional extent.

Tight gas reservoirs are notoriously difficult to characterize; routine methods developed for conventional reservoirs are not appropriate for tight gas reservoirs. In this article, we investigate the use of nonroutine methods to characterize permeability heterogeneity and pore structure of a tight gas reservoir for use in flow-unit identification. Profile permeability is used to characterize fine-scale (1 in. [2.5 cm]) vertical heterogeneity in a tight gas core; more than 500 measurements were made. Profile permeability, although useful for characterizing heterogeneity, will not provide in-situ estimates of permeability; furthermore, the scale of measurement is much smaller than log scale. Pulse-decay permeability measurements collected on core plugs under confining pressure were used to correct the profile permeability measurements to in-situ stress conditions, and 13-point averages of profile permeability were used to relate to log-derived porosity measurements. Finally, N2 adsorption, a new method for tight gas was used to estimate the pore-size distribution of several tight gas samples. A unimodal or bimodal distribution was observed for the samples, with the larger peak corresponding to the dominant pore-throat size, as confirmed by independent methods. Furthermore, the adsorption-desorption hysteresis loop shape was used to interpret the dominant pore shape as slot-shaped pores, which is typical of many tight gas reservoirs. The N2 adsorption method provides rapid analysis and does not suffer from some of the same limitations of Hg injection. In the future, we hope that the N2 adsorption method may prove useful for flow-unit characterization (based on dominant pore size) of fine-grained (siltstone-shale) tight gas reservoirs.

The bitumen of the Lower Cretaceous McMurray Formation in Alberta arguably represents one of the most important hydrocarbon accumulations in the world. In-situ development relies on heat transfer through the reservoir via horizontal steam injection wells placed 4 to 6 m (13–20 ft) above horizontal producers near the base of the sandstone reservoirs. Given this technology, understanding the distribution of the resource is paramount for a successful development program. Sedimentary facies provide a direct control on bitumen distribution and recovery. Most facies models developed to describe and predict sedimentary units of the McMurray Formation consider fluvial, estuarine, and/or deltaic depositional settings. In-situ development, however, requires a particularly high-resolution sedimentologic interpretation. High-quality three-dimensional seismic reflection data and extensive drill cores from acreage located approximately 50 km (31 mi) south of Fort McMurray provide important insights into the sedimentologic organization of reservoir and nonreservoir deposits in the upper one third (40 m [131 ft]) of the reservoir interval. Geomorphologic characteristics of the strata observed in seismic time slices reveal that a fluvial depositional setting was prevalent. Ichnologic and palynologic data, as well as sedimentary structures suggestive of tidal processes, indicate a marine influence in the upper reaches of a fluvial system characterized by channels that were 390 to 640 m (1280–2100 ft) wide and 28 to 36 m (92–118 ft) deep. The complex stratigraphic architecture consists of a mosaic of large-scale depositional elements, including abandoned channels or oxbow lake fills, point bars associated with lateral accretion, point bars associated with downstream accretion, counter point bars, and sandstone-filled channels. Reservoir deposits are primarily associated with point bars and sandstone-filled channels.

At Cranfield field, Mississippi, a monitored carbon dioxide (CO2) sequestration and enhanced oil recovery project provides a unique opportunity to study sealing properties of a marine shale as a CO2-confining zone. The reservoir is in the amalgamated fluvial basal sandstone of the lower Tuscaloosa Formation at depths of more than 3000 m (9843 ft). The marine mudstone of the middle Tuscaloosa forms a continuous regional confining system of approximately 75 m (246 ft).A 6-m (20-ft) core was retrieved from the middle Tuscaloosa marine mudstone approximately 70 m (230 ft) above the CO2 injection zone. We conducted a series of characterizing analyses on the core that would enable us to assess with high confidence seal performance over geologic time. The core displays considerable heterogeneity at centimeter to decimeter scales, with lithology varying from silt-bearing clay-rich mudstone to siltstone and very fine grained sandstone. In total, nine microfacies are recognized in the core. Petrographic, mineralogical, and chemical analyses (scanning electron microscopy, x-ray diffraction, and x-ray fluorescence) show that calcite cements preferentially form in coarser grained beds and have greatly reduced porosity and permeability, making silty and sandy beds less permeable than mudstone. Mercury intrusion capillary pressure tests show desirable sealing capacity for all samples capable of retaining a CO2 column of 49 to 237 m (161–778 ft) at 100% water saturation. Permeability and porosity of all facies are less than 0.0001 md and 4%, respectively. Pores in the samples are at nanometer scales, with modal pore-throat sizes less than 20 nm. Scanning electron microscopic imaging on ion-milled surfaces confirms that nanopores are scarce and generally isolated.

The Elm Coulee field of the Williston Basin is a giant oil discovery in the middle Bakken Formation (Devonian–Mississippian) discovered in 2000. Horizontal drilling began in the field in 2000, and to date, more than 600 wells have been drilled. The estimated ultimate recovery for the field is more than 200 million bbl of oil (31.8 million m3). The Bakken Formation in the field area consists of three members: (1) upper shale, (2) middle silty dolostone, and (3) lower siltstone. The total Bakken interval ranges in thickness from 10 to 50 ft (3.1 to 15.3 m) over the field area. The upper shale is dark-gray to black, hard, siliceous, slightly calcareous, pyritic, and fissile. The shale consists of dark organic kerogen, minor clay, silt-size quartz, and some calcite and dolomite. The kerogen consists mainly of amorphous material, and the organic material is distributed evenly throughout the shale interval (not concentrated in laminations or lenses). The upper shale ranges in thickness from 6 to 10 ft (1.8 to 3.1 m) over the field area. The middle member consists of a silty dolostone and ranges in thickness from 10 to 40 ft (3.1 to 12.2 m). The lower member in the Elm Coulee field consists of brownish-gray, argillaceous, organic-rich siltstone. Burrowing and brachiopod fragments are common in the lower member. This facies is equivalent to the lower Bakken black shale facies on the northern side of the field and is interpreted to be an updip-landward equivalent to the deeper-water, black shale facies. The lower member ranges in thickness from 2 to 6 ft (0.61 to 1.8 m). Based on the abundance of fossil content and amount of burrowing, the members of the Bakken Formation are interpreted to have been deposited under aerobic (middle member, common burrows, and rare fossils), dsyaerobic (lower member, common fossils, and lesser amount of burrows), and anaerobic conditions (upper member, rare fossils, and burrows). The main reservoir in Elm Coulee field is the middle member, which has low matrix porosity and permeability and is found at depths of 8500 to 10,500 ft (2593 to 3203 m). The current field limits cover approximately 450 mi2 (1165 km2). The middle Bakken porosities range from 3 to 9%, and permeabilities average 0.04 md. Overall, the reservoir quality in the middle Bakken improves upward as the amount of clay matrix decreases. The middle Bakken is interpreted to be a dolomitized carbonate-shoal deposit based on subsurface mapping and dolomite lithology. The main production is interpreted to come from matrix permeability in the field area. Occasional vertical and horizontal fractures are noted in cores. The vertical pay ranges in thickness from 8 to 14 ft (2.4 to 4.3 m). The Bakken is slightly overpressured with a pressure gradient of 0.53 psi/ft (0.02 kPa/m). Horizontal wells are drilled on 640- to 1280-ac (259- to 518.4-ha) spacing units. Long single laterals, dual laterals, and trilaterals have all been drilled in the field. The horizontal intervals are sand-, gel-, and water-fracture stimulated. Initial production ranges from 200 to 1900 BOPD (31.8 to 302.1 m3/day). Initial potential rates for vertical wells are generally less than 100 BOPD (15.9 m3/day). The upper Bakken shale probably also contributes to the overall production in the field. The exact contribution is unknown but estimated to be less than 20% of the total production. The Elm Coulee field illustrates that the Bakken petroleum system has enormous potential for future oil discoveries in the Williston Basin.

The Jurassic Navajo Sandstone core in the Covenant field includes eolian dune interbedded with carbonate playa lake and fluvial interdune facies. Dune facies samples are bleached but not depleted in iron; bleached dune facies outcrop samples are depleted in iron. Bleached dune facies in the core samples contains ferroan dolomite, quartz overgrowths that do not completely fill pore spaces, grain-coating and pore-filling illite, coarse-grained gray hematite, kaolinite, and trace pyrite. Reddish brown interdune facies are typically very fine-grained sandstone and siltstone and contain dolomite and ferroan dolomite cement, illite pore-filling, and very fine-grained, red hematite. Diagenetic mineralogy and chemical compositions overlap the mineralogy and compositions of outcrop samples. The carbon and oxygen isotopic composition of dolomite in interdune facies and adjacent dune facies is derived from groundwater discharge modified by evaporation in a playa lake interdune environment, not from interaction with hydrocarbons. The iron in bleached dune facies is incorporated in coarse-grained hematite, ferroan dolomite, and trace pyrite. The bleached diagenetic mineral association of ferroan dolomite-hematite-pyrite with is metastable relative to more reducing conditions produced by petroleum. The reservoir temperature of 188F (87C) is too high for bacterial sulfate reduction and too low for geologically significant thermochemical sulfate reduction accounting for the association of abundant in produced water and trace pyrite in the core.

The Upper Triassic Yanchang Formation in the Ordos Basin, central China, is a typical sandstone reservoir with an ultra-low permeability. High-angle tectonic fractures and diagenetic fractures, such as near-horizontal bedding fractures, intragranular fractures, and grain-boundary fractures, are abundant. Fractures are major pathways and enhance fluid flow in sandstone reservoirs with ultra-low permeability. Because of their weak lateral continuity and their small apertures under lithostatic pressure, bedding fractures make a relatively small contribution to the overall permeability of reservoirs. As they are both of small size and low permeability, intragranular fractures and grain-boundary fractures mainly improve the connectivity of reservoirs by connecting the matrix pores. High-angle tectonic fractures control the fluid movement in the ultra-low-permeability reservoirs. Under the effect of different successive tectonic stress fields, four assemblages of high-angle tectonic fractures developed in the sandstone reservoirs. Under the present-day stress, differently oriented fractures have different connectivities, apertures, and permeabilities. The northeast–southwest fractures parallel to the maximum principal stress have a good connectivity, large apertures, and a high permeability, forming the dominant flow paths. Knowledge of these paths can be used for optimizing well placement. Because of their sensitivity to pressure, fractures in different directions will show varying apertures as the formation pressure decreases. Therefore, the permeability of the fractures of different orientations and its impact on reservoirs vary at different developmental stages.

The Miocene Bear Lake Formation is exposed along the coast and mountains of the central Alaska Peninsula and extends offshore as part of the Bristol Bay Basin. The Bear Lake Formation is up to 2360 m (7743 ft) thick in an offshore well and is considered to have the highest reservoir potential in this gas-rich frontier basin. Our new macrofossil and palynological data, collected in the context of measured stratigraphic sections, allow us to construct the first chronostratigraphic framework for this formation. Biostratigraphic age assignments for the numerous, commonly isolated, onshore exposures of the Bear Lake Formation show that deposition initiated sometime before the middle Miocene (15 Ma) and extended to possibly the earliest Pliocene. The bulk of the Bear Lake Formation, however, was deposited during the middle and late Miocene based on our new findings. We interpret the Bear Lake Formation as the product of a regional transgressive estuarine depositional system based on lithofacies analysis. The lower part of the formation is characterized by trough cross-stratified sandstone interbedded with coal and pedogenic mudstone deposited in fluvial and swamp environments of the uppermost parts of the estuarine system. The lower-middle part of the formation is dominated by nonbioturbated, wavy- and flaser-bedded sandstone and siltstone that were deposited in supratidal flat environments. The upper-middle part of the Bear Lake Formation is characterized by inclined heterolithic strata and coquinoid mussel beds that represent tidal channel environments in the middle and lower tracts of the estuarine system. The uppermost part of the formation consists of tabular, bioturbated sandstone with diverse marine invertebrate macrofossil faunas. We interpret this part of the section as representing the subtidal tract of the lower estuarine system and possibly the adjacent shallow inner shelf. A comparison of our depositional framework for the Bear Lake Formation with core and well-log data from onshore and offshore wells indicates that similar Miocene depositional systems existed throughout much of the Bristol Bay Basin. The documented changes in depositional environments within the Bear Lake Formation are also important for understanding upsection changes in the geometries of potential reservoirs.

An analysis of 31 whole cores (1600 ft, 490 m) and closely spaced wireline logs (500 wells) penetrating the Lower Cretaceous (Cenomanian) lower Woodbine Group in the mature East Texas field and adjacent areas indicates that depositional origins and complexity of the sandstone-body architecture in the field vary from those inferred from previous studies. Heterogeneity in the lower Woodbine Group is controlled by highstand, fluvial-dominated deltaic depositional architecture, with dip-elongate distributary-channel sandstones pinching out over short distances (typically 500 ft [150 m]) into delta-plain and interdistributary-bay siltstones and mudstones. This highstand section is truncated in the north and west parts of the field by a thick (maximum of 140 ft [43 m]) lowstand, incised-valley-fill succession composed of multistoried, coarse-gravel conglomerate and coarse sandstone beds of bed-load fluvial systems. In some areas of the field, this valley fill directly overlies distal-delta-front deposits, recording a fall in relative sea level of at least 215 ft (65 m). Correlation with the Woodbine succession in the East Texas Basin indicates that these highstand and lowstand deposits occur in the basal three fourth-order sequences of the unit, which comprises a maximum of 14 such cycles. Previous studies of the Woodbine Group have inferred meanderbelt sandstones flanked by coeval flood-plain mudstones and well-connected, laterally continuous sheet sandstones of wave-dominated deltaic and barrier-strand-plain settings. This model is inappropriate, and a full assessment of reservoir compartmentalization, fluid flow, and unswept mobile oil in East Texas field should include the highstand, fluvial-dominated deltaic and lowstand valley-fill sandstone-body architecture.

Calcite cement is the dominant control on reservoir quality in turbidite sandstones of the Upper Permian Bell Canyon Formation, Delaware Basin. These well-sorted, very fine-grained arkoses were deposited in a basin-floor setting by channel-levee systems terminating in broad lobes. Calcite cement distribution in the East Ford and Geraldine Ford fields was mapped using core, log, and thin-section data. Calcite is concentrated in tightly cemented zones that are mostly less than 1 ft (0.3 m) thick. Areas that have high percentages of calcite-cemented sandstone (20%) occur along the margins of the sandstone bodies, in overbank and lobe deposits, where sandstone pinches out into siltstone. Areas that have the lowest percentage of calcite-cemented sandstone (10%) occur where the sandstone is thickest, in the channel facies. Isotopic composition of the calcite (13C = 1.8 to 3.0 [relative to the Peedee belemnite, PDB], 18O = 4.6 to 6.3 [PDB]) is consistent with the source of calcium carbonate being from dissolution of detrital carbonate rock fragments and marine skeletal debris. Because internal sources of calcite were apparently insufficient to account for the cement volume, cement components are interpreted as having been transported into the sandstones from organic-rich basinal siltstones and limestones. Feldspars buffered acidic formation waters near where they entered the sandstone, resulting in calcite concentrated near the sandstone margins. The calcite formed near maximum burial depths of 4800 ft (1.5 km) and temperatures of 104F (40C) from marine pore waters with 18O of approximately 0 (relative to standard mean ocean water). Most of the calcite-cemented zones are interpreted as being concretions that extend no more than a few meters laterally. Production data and geophysical log correlations suggest that some cemented zones are laterally continuous at least 1000 ft (300 m) and cause vertical reservoir compartmentalization. Laterally extensive calcite layers may be associated with the base of turbidite deposits.

A late Mississippian–early Pennsylvanian eustatic sea level drop resulted in a complex lowstand drainage network being eroded across the Illinois Basin in the eastern United States. This drainage system was filled during the early part of the Pennsylvanian. Distinct differences can be recognized between the trunk and tributary paleovalley fills. Fills preserved within the trunk systems tend to be fluvially dominated and consist of bed-load deposits of coarse- to medium-grained sandstone and conglomerate. Conversely, the incised valleys of tributary systems tend to be filled with dark mudstone, thinly interbedded sandstones, and mudstones and siltstones. These finer grained facies exhibit marine influences manifested by tidal rhythmites, certain traces fossils, and macro- and microfauna. Examples of tributary and trunk systems, separated by no more than 7 km (4.3 mi) along strike, exhibit these styles of highly contrasting fills. Useful analogs for understanding this Pennsylvanian system include the Quaternary glacial sluiceways present in the lower Ohio, White, and Wabash river valleys of Indiana (United States) and the modern Amazon River (Brazil). Both the Amazon River and the Quaternary rivers of Indiana have (or had) trunk rivers that are (were) dominated by large quantities of bed load relative to their tributaries. The trunk valley systems of these analogs aggraded much more rapidly than their tributary valleys, which evolved into lakes because depositional rates along the trunk are (were) so high that the mouths of the tributaries have been dammed by bed-load deposits. These Holocene systems illustrate that sediment yields can significantly influence the nature of fill successions within incised valleys independent of rates of sea level changes or proximity to highstand coastlines.

The Potrerillos minibasin of the La Popa basin, Mexico, is defined by the Carroza syncline and bounded by the El Gordo anticline and the La Popa salt weld. Stratigraphic geometries and facies distribution of the upper sandstone member of the Potrerillos Formation within the minibasin indicate that diapirism, shortening, and deposition were simultaneous and complexly interrelated during the Paleocene. The upper sandstone member is a regressive succession of marginal marine, siliciclastic deposits. Wave-dominated shoreface deposits consist of mudstone, siltstone, and sandstone and are interpreted to represent offshore to upper shoreface environments. Tide-dominated environments are heterogeneous and grouped into four broad classes based on the energy of the depositional environment. Lower delta-plain deposits range from mudstone to sandstone and are interpreted to represent channel, flood-plain, and lagoonal environments. Sedimentary structure orientations indicate asymmetrical, bidirectional paleocurrents with a dominant southeast trend parallel to regional structural trends. Unconformity-bounded strata onlap the El Gordo anticline, indicating syndepositional folding and control of the depositional system by detachment fold trends in the basin.The strata of the upper sandstone member are interpreted to contain six systems tracts that record three successive fourth-order eustatic cycles. These strata represent the deposits of a prograding, ebb-dominated deltaic system confined to the Carroza syncline. Maximum stratal accumulation in the synclinal hinge caused the migration of underlying salt into flanking structures. A balance between salt withdrawal and subsidence stabilized the position of both the synclinal hinge and the shoreline, leading to a positive deposition-subsidence feedback loop. During regional regression, the structural basin defined by the syncline formed a paleogeographic embayment and controlled shoreline evolution.

The coalbed methane resource is very abundant in Qinshui basin (3.28 1012 m3; 114 tcf). The investigation on the upper Paleozoic coalbed methane system is a guide to the exploration and development of coalbed methane. The upper Paleozoic coalbed methane system in the Qinshui basin is sealed by a low-permeability roof and floor strata comprising mudstone, siltstone, and bauxite of the Carboniferous Benxi Formation and the Permian Shanxi and Xiashihezi formations. The overburden is the Lower Permian Xiashihezi Formation and the Upper Permian, Triassic, and Middle Jurassic clastic deposits. The source and reservoir rocks are the Carboniferous–Permian coal seams. The hydrocarbon generation of the source rocks reached its first peak in the Late Triassic. The highest maturity was about Ro = 1.2% under a normal paleogeothermal gradient (2–3C/100 m; 1.1–1.7F/100 ft). A tectonic thermal event during the Jurassic and Cretaceous Yanshanian orogeny enhanced the coal maturity and caused a second peak of hydrocarbon generation. Varying igneous intrusions caused the coal maturity to be higher in the southern, northern, and eastern parts of the Qinshui basin instead of the central and western parts. The highest maturity was greater than Ro = 4% in the Jincheng area. The migrated thermogenetic coalbed methane accumulated in the reservoirs in which abnormally high reservoir pressure exists locally under the hydrodynamic drive. Because of the different hydrodynamic background and sealing condition, the distribution of coalbed methane content is inhomogeneous. The reservoir is undersaturated with gas in most areas. Based on the coalbed methane system investigation, we assessed the coalbed methane producibility in different parts of the Qinshui basin, and the major producibility area is in the southern part of the basin.

The Jeanne d'Arc Basin is a relatively small passive-margin rift basin that underlies what is now the northeastern corner of the Grand Banks of Newfoundland. In the Late Cretaceous and early Paleogene, the basin formed an elongated depression where sediment accumulated in and along the margins of a shallow-shelf sea. Seismic and well data were used to examine the Late Cretaceous and Paleogene evolution of the basin and to formally revise the existing stratigraphic classification scheme. In the Late Cretaceous, the western margin of the basin was characterized by a well-developed shelf and slope system comprised of the sand-prone Otter Bay and Fox Harbour members and the distally equivalent shale-prone Red Island and Bay Bulls members, respectively. These members record two main progradational episodes that are separated by a regional unconformity and a thick shale interval corresponding to the Bay Bulls Member. East of the shelf-slope system, Upper Cretaceous shale and sparse sandstone of the Dawson Canyon Formation and chalk of the Petrel Member and Wyandot Formation were deposited in a relatively condensed section. In the early part of the Paleogene, two main sandstone units, herein named the Avondale and South Mara members, were deposited east of the well-developed latest Cretaceous slope in the lower part of the Banquereau Formation. The Avondale Member corresponds to small sand-prone submarine fans deposited on the basin floor in the early Paleocene. The submarine fans were fed primarily by two canyons that incised the western margin of the basin, eroding the Late Cretaceous shelf and slope. Also in the Paleocene, siliceous shale and siltstone of the Tilton Member were deposited above bathymetric highs along the western and southern basin margins. The exact temporal relationship between the Tilton and Avondale members is poorly understood. The South Mara Member was deposited in the latest Paleocene and early Eocene. In the southern parts of the basin, it forms a regressive sandstone unit above the Tilton Member, deposited during a period of renewed shelf-slope progradation. In the central and northern parts of the basin, the South Mara Member corresponds to small, sand-prone submarine fans, similar to those deposited in the early Paleocene.

The early Cenozoic evolution of the Canadian High Arctic was governed by a compressional stress regime related to the opening of Baffin Bay-Labrador Sea. On northeastern Ellesmere Island, the Eureka Sound Group sediments (late Paleocene in age) record the paleogeographic reorganisation of this event. This group is divisible into three formations and are preserved within six outliers in this area. The oldest of these units, the Mokka Fiord Formation is characterised by a brown weathering medium - to coarse grained lithic sandstone occuring as decimeter scale trough cross bedded units. These sediments are to 740 metres thick and are interpreted to be a predominantly fluvial deposit. The overlying and younger Cape Back Formation is interpreted to be fluviolacustrine in origin consisting of interbedded fine grained litho- to calcarenite, siltstone, and mudrock. Current ripples, climbing ripples, ripple and parallel laminations are common throughout this formation which reaches a total thickness of 1100 metres. Polymictic boulder orthoconglomerates of the Cape Lawrence Formation varies in thickness from 700 to 1000 metres. Clast composition consists of a variety of siliciclastics and carbonates. These conglomerate units are interpreted to be proximal gravely rivers which were alluvial fans. These data provide us with a valuable contribution towards advancing our understanding of the dynamics of this syntectonic siliciclastic depositional system.

The late Miocene Mt. Messenger Formation of Taranaki, New Zealand, consists mainly of well-sorted, very fine to fine-grained thin-bedded sandstone and siltstone deposited in middle- and upper-bathyal water depths. Lithofacies are dominated by turbidite beds, comprising planar-laminated and climbing-ripple-laminated sandstone and massive siltstone. These strata were studied in a 200 m-thick, 4 km-long coastal outcrop section and in two, behind-outcrop boreholes from which Fullbore Formation Micro Imager (FMI) and Platform Express logs and core were obtained. The boreholes were 47 and 105 m deep and were drilled about 100 m behind the cliff outcrop about 150 m apart. In addition, a high-resolution seismic reflection line was shot adjacent to the coastal cliff and was tied to the updip outcrop exposures. The outcrop section displays abundant erosional cutout of beds by scour or channels that considerably limit lateral bed continuity. At a smaller scale, bed continuity is also interrupted by bioturbation structures. We interpret the outcrop section as a series of vertically stacked or shingled slope fan or channel-levee/overbank complex deposits, comparable to Mutti type III fans. Comparison of behind-outcrop dipmeter, seismic reflection profiles, and FMI data with outcrop data indicates that three main channel-levee/overbank depositional units are present. Siltstone and alternating thin-bedded sandstone and siltstone that display an upward decrease in dip magnitude and variable dip orientation on dipmeter logs are interpreted as channel fill deposits. Vertically stacked, interleaved packages of thin-bedded, typically planar-laminated sandstone (Bouma Tb divisions), climbing-ripple-laminated sandstone (Tc), and siltstone (Te) with complex upward-decreasing dipmeter patterns are interpreted as proximal channel-levee and overbank deposits. Laterally extensive interbedded Tb and Tc sandstone and Te siltstone lithofacies with low-angle dips and little variability on dipmeter logs are interpreted as distal channel-levee and overbank deposits. These three depositional settings are important to distinguish, as each exhibits different fluid-flow behaviors in an analog reservoir. Comparison of the outcrops with typical subsurface data sets as used by petroleum geologists (logs, core, seismic reflection) has provided criteria for distinguishing subtle stratigraphic features that can influence production from a subsurface reservoir analog.

A detailed geochemical and stratigraphic study conducted on a sedimentary sequence of the Upper Cretaceous Umir Formation, in a section outcropping on the eastern flank of Middle Magdalena basin (MMB), Colombia, identifies this formation as a new hydrocarbon source rock, not previously considered as a source for MMB oil.The Umir Formation is composed of coal, coaly shale, claystone, siltstone, and sandstone. Based on Rock-Eval data, the coal and coaly shale show good potential for oil generation. Certain biomarkers are characteristic of the depositional environment of the Umir Formation and related oil and contrast it with the La Luna Formation and related oil. For example, biomarkers of the Umir Formation show pristane/phytane ratios greater than 1; predominance of C29 steranes; low oleanane/hopane ratios (

The Canning basin (400,000 km2) of Western Australia is one of the largest intracratonic basins to have been affected by cold climates as Gondwana drifted across the south polar regions during the Permian-Carboniferous. This article describes the tectono-stratigraphic setting and evolution of the Permian-Carboniferous Reeves Formation and Grant Group of the northern part of the basin. We employ seismic facies analysis, downhole well-log responses, palynostratigraphy, and sedimentary facies logs from 25 continuously cored wells. The succession rests on a widespread erosional unconformity of middle Carboniferous age. This surface may have been modified by glacial erosion when a late Carboniferous ice sheet expanded across the entire basin, but no primary glacial deposits can be identified; if present, such sediments were likely reworked during subsequent basin faulting. Reeves Formation and Grant Group strata are dominated by massive and deformed sandstones, diamictites, and conglomerates deposited subaqueously as sediment gravity flows close to active faults. Initial strata of Late Carboniferous age (Reeves Formation) are preserved in the deeper troughs (Fitzroy trough) and in salt collapse subbasins on high-standing structural blocks (Barbwire, Betty, and Balgo terraces; Crossland platform). These areas later subsided and were blanketed by gravity flow deposits of Early Permian age (Hoya Formation). In turn, a regional flooding surface and overlying bioturbated siltstone unit (Calytrix Formation) records an increase in relative water depths across the northern Canning basin. Siltstones coarsen upward into lower shoreface storm-influenced sandstones (Clianthus Formation) and the fluvial Poole Sandstone. Potential petroleum play types are principally associated with faults and channels.

Discovered in 1939, Storms Consolidated field in the central Illinois basin has produced approximately 24.5 million bbl oil, mainly from Mississippian sandstone reservoirs, yet may contain significant remaining reserves. The field produces from a combination structural-stratigraphic trap along the upthrown side of a major normal fault trend. Although the principal reservoir zone, the Waltersburg Sandstone, is mostly depleted, another important interval, the Aux Vases Sandstone, appears underexploited in many parts of the field. Description and analysis of the only continuous core through the Aux Vases has led to the identification of major lithofacies and their characterization in terms of reservoir quality. The Aux Vases appears to represent a series of shallow marine bars separated by nonreservoir areas of siltstone, shale, and shaly sandstone. Log-based mapping of reservoir distribution, plus production and pressure data, indicates significant lateral and vertical compartmentalization of the reservoir. Although insufficient data exist for full-scale integrated reservoir characterization studies, a trend surface analysis was performed on structural information across the field. The results of this analysis were compared with reservoir distribution maps to identify areas for future drilling or recompletion.

The Late Devonian and Early Mississippian Bakken and Exshaw formations are a continuum of regionally correlated, organic-rich (up to 35% total organic carbon), black shale source rocks covering much of the Western Canada sedimentary basin. The Bakken Formation is composed of (1) a black mudstone lower member, (2) a gray mudstone/sandstone middle member, and (3) a black mudstone upper member. The Exshaw Formation, beneath the Alberta Plains and in exposures in the Foothills and Front Ranges of the Rocky Mountains, is composed of (1) a lower black shale member and (2) an upper siltstone member. The basal black shale unit of the Lower Mississippian Banff Formation, overlying the Exshaw Formation, is a second organic-rich interval. These black shales are regionally significant hydrocarbon source rocks and local reservoirs. The middle Bakken member is a locally important reservoir rock with substantial economic potential. The Bakken and Exshaw formations and the basal Banff black shale are divisible into three systems tracts: (1) a transgressive systems tract, (2) a lowstand systems tract, and (3) a second transgressive systems tract. Lodgepole and Banff formation carbonates, overlying the Bakken and Exshaw formations, are part of a highstand systems tract. A sequence boundary occurs between the lower and middle Bakken members. The conformable equivalent of this sequence boundary is within the Exshaw black shale member. Variations in the internal composition of these systems tracts imply that two depocenters, (1) the Williston basin and (2) the Prophet trough and the western margin of the North American craton, were affected differently by relative sea level rise and fall during Bakken and Exshaw deposition because of differences in water depth and sediment accommodation. Spatial and temporal changes in black shale and gray mudstone/sandstone, as highlighted by this sequence stratigraphic interpretation, may have significant impacts on source rock potential and hydrocarbon reservoir size, location, and quality.

The Lower Silurian Qalibah Formation consists of two members, the (upper) Sharawra Member and the (lower) Qusaiba Member. The Qusaiba is the main hydrocarbon source rock for the known Paleozoic hydrocarbon accumulations in central Saudi Arabia. The Qusaiba Member is composed mostly of claystone and shale with interbeds of siltstone and sandstone. Depositionally, the Qusaiba Member is interpreted to represent the delta-toe clays, whereas the Sharawra Member was deposited as pro-delta sandstones of an immense fluviodeltaic system that dominated the Silurian-Carboniferous of Arabia. The Qalibah Formation accumulated syndepositionally in at least two rapidly subsiding depocenters. One depocenter was located in central and southern Arabia, and the other depocenter was located in northwestern Saudi Arabia. The former trough began subsiding during the Late Ordovician following the Taconic uplift. The latter trough began subsiding during the Early Silurian. At least 10,000 ft (3100 m) of Upper Ordovician- Lower Devonian strata accumulated in the trough located in central and southern Saudi Arabia. About 3300 ft (1000 m) of Lower Silurian sediments accumulated in the depocenter found in northwestern Saudi Arabia. The development of these troughs documents a period of crustal extension probably related to the rifting of the Lower Paleozoic continental margin of Saudi Arabia. The Qusaiba Member organic-rich facies occurs near the base of the unit and has up to 8% total organic carbon content. The development of favorable source rock facies in the Qusaiba is observed along the flanks of the depositional thicks associated with the "lower" Qusaiba Member. The basal Qusaiba Member organic-rich facies was produced during periods of elevated primary productivity of organic matter within the water column in an open-marine, nonsilled basin setting. Deposition of the basal organic-rich facies of the Qusaiba Member occurred as a condensed sequence along a sediment-starved continental margin. The basal Qusaiba Member organic-rich facies accumulated in normally to partly oxygenated bottom-water settings; however, the sediments below the sediment/water interface were probably preserved in an anoxic setting. Geochemical data also demonstrate that the organic-rich Qusaiba Member sediments found in the depositional thicks have characteristics consistent with a more oxidized sediment column. Geo chemical data also show that the basal Qusaiba Member organic-rich facies deposited more distally to these depocenters are more dysoxic to anoxic in their characteristics. The organic-rich facies of the basal Qusaiba Member found in depositional thicks was produced under conditions that either reworked the organic-rich sediments, thereby oxidizing them, or diluted the organic matter, resulting in less preservation of potential source rock.

The Velkerri Formation (~1.43 Ga) in northern Australia is one of the organically richest Pro terozoic successions in Australia and over the last 10 yr has been a target for oil exploration. This formation is predominantly a glauconitic marine shale deposited in restricted to anoxic conditions in a deep-water pro-delta slope to basin environment. The Velkerri Formation is composed of superimposed sediment couplets made up of laminated black organic-rich mud shales [total organic carbon (TOC) ~4-6%] and laminated gray-green organically lean mud shales (TOC

The Dunlin Group in the northern North Sea, consisting of the Johansen, Amundsen, Burton, Cook, and Drake formations of late Sinemurian- Toarcian age, hosts important hydrocarbon reservoirs in the Cook Formation sandstones. The Johansen Formation is associated with a relative fall of sea level and is interpreted to be a large sandstone delta confined within a broad incised valley at the base of the group. During a later stage of relative sea level rise, the finer grained Amundsen and Burton formations were deposited. The overlying Cook Formation consists of four sandstone tongues, each of which is characterized by a lower zone of sharp-based, upward-coarsening, thinly bedded shoreface sandstones and siltstones (reflecting forced regression during falling relative sea level) and an erosively based upper zone of thin tidal flat and thick deltaic/estuarine sandstones (reflecting lowstand incision, as well as initial progradation and subsequent transgressive backfill of estuaries during relative sea level rise). The Drake Formation shales were deposited during continued relative sea level rise. Several types of erosional surfaces are recognized within the studied succession: (1) sequence boundaries occur at the base of the Johansen Formation and within the Cook Formation, and represent the bottoms of incised valleys that truncate the underlying ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received May 4, 1995; revised manuscript received March 27, 1996; final acceptance September 12, 1996. 2Department of Geology/Paleontology, University of Zagreb, 10000 Zagreb, Croatia. 3Department of Geology/Geophysics, University of Wyoming, Laramie, Wyoming 82071. This paper was part of the sequence stratigraphy research project at the University of Bergen, Norway, and is a product of studies on the architecture of Lower Jurassic shelf sandstones of the northern North Sea. The work was sponsored by STATOIL through a VISTA fellowship awarded to T. Marjanac, and this support is gratefully acknowledged. We are grateful to D. Mellere and L. M. Falt for discussion and encouragement during the work. We also thank Else Lien for drafting the sections and Jane Ellingsen for reprographs. Constructive criticism from D. Nummedal, J. Webb, and K. T. Biddle on the final version of the manuscript is much appreciated.

The late Middle to Late Ordovician (late Mohawkian to Cincinnatian) supersequence in Kentucky and Virginia was deposited in a tectonically active foreland basin during a transition from the "ice-free" Early Ordovician to the glacial Late Ordovician. This sequence was deposited in less than 12 m.y., is 250-500 m thick, and is composed of four large third-order sequences (each 40-150 m thick) that are regionally correlative in outcrops, cores, and gamma-ray logs. Smaller scale third-order parasequence sets (up to 20 m thick) and component parasequences (1-8 m thick) make up the larger sequences, and are only locally correlative. Subtidal-dominated parasequences comprise the basal part of each sequence, whereas shallower subtidal- or peritidal-dominated parasequences compose upper parts of sequences. Each large, third-order sequence is asymmetric and marked by lowstand, transgressive, and highstand systems tracts with unique lithologic and gamma-ray log response characteristics. Ramp margin wedges (RMW) are poorly developed and consist of marine siltstone or grainstone/packstone sheets extending into deep ramp settings; these sheets have high gamma-ray values in their base and lower, blockier gamma-ray responses in their tops. Transgressive systems tracts (TST) are thin; composed of high-energy, locally phosphatic grainstone ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received February 7, 1996; revised manuscript received May 27, 1997; final acceptance June 16, 1997. 2Department of Geology, Virginia Tech, Blacksburg, Virginia 24061-0420. Present address: Department of Earth, Atmospheric and Planetary Sciences, Massachusetts Institute of Technology, Cambridge, Massachusetts 02139. 3Department of Geology, Virginia Tech, Blacksburg, Virginia 24061-0420. This study was supported by NSF Grant EAR-9316057 to J. F. Read, a grant from Mobil Oil Company, and grants-in-aid of research from the Geological Society of America and Appalachian Basin Industrial Associates to Mike Pope. We thank John Haynes, Brian Keith, and Rick Major for thorough and insightful reviews of an earlier version of this manuscript.

Since discovery in 1924, Granny Creek field in central West Virginia has experienced several periods of renewed drilling for oil in a fluvial-deltaic sandstone in the Lower Mississippian Price Formation. Depositional and diagenetic features leading to reservoir heterogeneity include highly variable grain size, thin shale and siltstone beds, and zones containing large quantities of calcite, siderite, or quartz cement. Electrofacies defined through cluster analysis of wireline log responses corresponded approximately to facies observed in core. Three-dimensional models of porosity computed from density logs showed that zones of relatively high porosity were discontinuous across the field. The regression of core permeability on core porosity is statistically significant, and differs for each electrofacies. Zones of high permeability estimated from porosity and electrofacies tend to be discontinuous and aligned roughly north-south. Cumulative oil production varies considerably between adjacent wells, and corresponds very poorly with trends in porosity and permeability. Original oil in place, estimated for each well from reservoir thickness, porosity, water saturation, and an assumed value for drainage radius, is highly variable in the southern part of the field, which is characterized by relatively complex interfingering of electrofacies and similar variability in porosity and permeability.

The Nonesuch Formation, a black siltstone, was deposited in the Lake Superior portion of the mid-continent rift system during middle Proterozoic rifting. Despite its age of nearly 1.1 Ga, the Nonesuch Formation contains liquid petroleum and solid pyrobitumen. Numerical modeling techniques were used in this study to constrain the thermal history of the Nonesuch Formation at White Pine, Michigan. Thermal modeling addresses two issues: (1) the utility of illite-smectite expandability as a limiting parameter for describing the thermal history of ancient (Proterozoic) sedimentary rocks, and (2) the potential for hydrocarbon maturation within the Nonesuch Formation at White Pine. A range of potential burial histories for the Nonesuch Formation was constructed based on geologica evidence. Time-temperature histories were calculated for each burial history model assuming one-dimensional, transient, conductive heat flow. Results of numerical time-temperature models were then evaluated on the basis of organic and inorganic thermal maturity indicators including Rock-Eval® pyrolysis data and biomarker indices (correlated to equivalent vitrinite reflectance values), in addition to illite-smectite expandability. Illite-smectite expandability values appear generally consistent with measured organic thermal maturity values. The preferred set of cases also produces calculated illite-smectite expandability and vitrinite reflectance values consistent with thermal maturity indicators (that do not include vitrinite) collected in the field. Modeling results demonstrate tha a combination of elevated basal heat flow and rapid burial during the Proterozoic is required to produce the observed thermal maturities at White Pine, Michigan. More specifically, modeling indicates that maximum temperatures for the Nonesuch Formation, 110 to 125°C, were reached at about 1075 Ma, coincident with a maximum burial depth of about 6 km, although 4 km represents a more plausible value. The results support a thermal history consistent with in-situ oil generation at White Pine; however, thermal modeling alone cannot rule out the possibility that oil was generated and expelled elsewhere and migrated into the area with fluids expelled during an episode of postrift compression.

In order to determine the geologic features of the reservoirs and their areal statistical distribution and geometry, a study was made of a selected interval where the sands present less coalescence and the reservoirs are clearly defined. The study area comprises 1900 km{sup 2} of the Greater Oficina area; core samples, logs and reservoir maps were used. It was found that interval I consists of interbedded sandstones, shales, some siltstone, and occasionally lignites. Based upon lithologic mesoscopic features, eight (8) characteristic lithofacies could be defined. Rocks classified as sub-litharenites, sub-arkoses, arkoses lithic sandstones and graywackes could be inferred as belonging to a fluvio-deltaic system sourced on the Pre-Cambrian Guayana shield. The diagenetic level reached by the sequence corresponds to the intermediate stage, where significant processes of cementation by oxides, carbonates and silica are of equal intensity and magnitude to the lixiviation of feldspars and other detritic particles, giving these rooks good potential reservoir qualities. Descriptive statistical evaluation was performed on 140 reservoirs representing all lithofacies populations in this interval. Based on this analysis reservoirs were statistically grouped in classes which are a function of their geometry, spatial location and type of hydrocarbon content.

Correlations from the Yates shelf through the Capitan reef margin and into the Bell Canyon of the deep Delaware Basin (Guadalupian, Permian Basin) are not known with great detail due to limited biostratigraphic control and the inability to trace beds or time lines from the cyclic shelf deposits, through the massive reef and foreslope, and into basinal siliciclastics. The presence of a strong hierarchy of depositional cycles on the shelf and in the basin suggests that cycles may be useful as a correlation tool. A Yates shelf-to-basin correlation is proposed based on matching 3rd- and 4th-order cycles recognized with a stratigraphic computer model and on cores and outcrop. We believe thick, sand-dominated cycles were deposited in the basin during long-term lowstands; whereas, thin, organic-rich lime mudstone-dominated cycles were deposited during long-term highstands. The correlation scheme hinges on equating 3rd-order condensed intervals of organic mudstone in the basin with thick carbonate {open_quote}banks{close_quote} deposited ad the lower and upper Yates boundaries. Within this tentative large-scale framework, there is a reasonably good match between 4th-order shelf and basin cycles. Some ambiguity remains, however, due to the possibility of missed cycle beats in both the shelf (thin or no cycles, erosion) and basin (nomore » or minor condensed mudstones resulting in sand on sand, erosion) during long-term lowstands. Computer modeling suggests siliciclastics bypassed the Yates shelf and were delivered to the basin as turbidites during high-frequency (5th-order) lowstands, but the amount of bypass during any lowstand was controlled by longer-term cycles. The large-scale basinal cycles are slightly more symmetrical than their shelf counterparts; typically showing a gradual increase in clean sandstone and decrease in siltstone and organic mudstone away from a condensed interval, and the converse towards the next condensed interval.« less

Lower Pennsylvanian paleovalley-confined sandstones are important petroleum reservoirs in the Midwest. In Kansas, such reservoirs have produced approximately 220 million bbl of oil and 1.7 tcf of gas. Valley-fill successions tend to become muddy upward, but there can be considerable local heterogeneity in which reservoir sandstones pass laterally into muddy sandstones or nonreservoir shales. The lack of understanding of this reservoir heterogeneity can lead to low drilling success rates. The Tonganoxie paleovalley (Upper Pennsylvanian, northeastern Kansas) contains facies very similar to Lower Pennsylvanian (Morrowan) valley fills, and can provide an outcrop- and subsurface-based model of sandstone deposition. The Tonganoxie paleovalley was incised during lowered sea level and filled during the subsequent transgression. The main paleovalley is approximately 41 m deep, 11 km wide, and 240 km long, and was fed by 1-km-wide tributary valleys oriented roughly normal to the trunk valley. Sandstones occur in four distinct architectural elements that were deposited during different phases of transgression. Type I sandstone consists of a belt of sandstone and conglomerate 3-18 m thick and confined to the trunk valley and wider portions of tributary valleys. Type I sandstone consists of amalgamated channel fills, has little or no mud, and has the highest porosity and permeability. The type I sandstone is overlain by estuarine deposits of sandstone (type II sandstones), rippled argillaceous sandstone to sandy mudstone, and coal. Most of the paleovalley was filled during this stage. The type II sandstones are narrow (1.5 km wide) arcuate bodies up to 8 km long and were likely deposited in tidal point bars near the fluvial to tidal transition, are either isolated sandstone bodies or are incised into type I sandstone. The higher mud content is expected to reduce porosity and permeability compared to fluvial facies. Type III sandstone bodies occur at the upstream limits of narrow tributaries and are probably bay-head deltas. Well logs indicate a range of mud content. Type IV sandstone is a thin (3 m) discontinuous sheet of marine sandstone deposited after most of the paleovalley had been filled.

The Neocomian strata of the West Siberian Basin are a prograding complex unique in its aerial extent, structure and hydrocarbon reserves, such as Priob Field in the Ob River area. Interpretation of the basin history is based on well data and seismic reflection profile. As many as 45 transgressive-regressive depositional sequences, called cyclites, prograde into the deep-water basin formed during Late Jurassic and Early Cretaceous. Each transgressive-regressive sequence is defined by a coarsening-upward cycle of shale, siltstone and sandstone, and is considered a chronostratigraphic subdivision of the prograding complex. Each sequence boundary is regionally correlatable on seismic reflection profiles, and is identified on well logs by sharp contacts between regressive sandstones below and thin transgressive shales above. Subordinate progradational wedges are locally developed within these sequences and contain major hydrocarbon reserves. These depositional wedges map as lens-shaped packages downlapping the outermost shelf (Priob zone) or as narrow progradational wedges downlapping the foreset reflections of the slope clinoforms immediately beyond the shelf break (Sugmut zone). Regressive facies of the shelf consist of thin but wide spread sandstones that also contain major hydrocarbon reserves. Pervasive sediment starvation during the Late Neocomian resulted in deposition of thin regionally extensive shales that provide top-sealmore » to the Neocomian hydrocarbon system. At the Priob field, a deep erosional incision has been mapped at the AS11 shelf-edge. Sands transported through this incised valley were deposited as a prograding wedge along the shoreline, forming the reservoir facies for the Priob hydrocarbon accumulation. Stratigraphic aspects of the Priob trap include top and lateral shale seals and subtle regional structural tilt. Types of stratigraphic traps are discussed and the possibility of predicting additional such traps are analyzed.« less

Where it was studied at two sites in north-central Oklahoma, the Gypsy sandstone of the Pennsylvanian Vamoosa Formation provides significant insights into the controls on reservoir quality in a meandering river deposit. At an outcrop site west of Tulsa, a three-dimensional architectural framework, based on erosional surfaces, allowed the recognition of a channel-fill sequence consisting of six channel sand bodies and representing at least three channel belts. Belts are vertically stacked and are incompletely separated by low-permeability flood-plain deposits, which are locally eroded. Porosity and permeability are primarily related to depositional facies. Within channel belts, mudclast lags associated with erosion surfaces at the base of channels have the potential to act as vertical permeability baffles between channel sand bodies, as do mud-draped lateral accretion surfaces within channel sand bodies. At a subsurface site 31 km (19 mi) to the west of the outcrop site, nine wells were drilled and cored through the Gypsy interval. At this site, it was possible to identify and correlate three channel belts comprising amalgamated channel sand bodies. Although lower level architectural elements could be recognized in cores, they could not be correlated with confidence given a 100-m (330-ft) well spacing.

One of the problems with the application of sequence stratigraphy to nonmarine sediments is the use of effective surfaces for correlations. This case study from the Mannville Group of southern Saskatchewan demonstrates how major, regional bounding surfaces can be identified and correlated to produce a suite of maps that can be used for exploration purposes. In southern Saskatchewan, Cretaceous Mannville sediments, termed the Pense, Cantuar, and Success (S2) formations, overlie Jurassic S1 and older deposits. The interval, which is up to 100 m thick, was deposited over 40 to 50 m.y. and is riddled with unconformities and weathered horizons. Detailed stratigraphic correlations using well logs are difficult, imprecise, and highly suspect unless corroborated by core control. Jurassic Success S1 sediment was deposited in a restricted shallow-marine environment. The S2 was deposited as a sheet of quartzose, braided fluvial sandstone that unconformably cuts into the S1. The overlying Cantuar Formation consists of dominantly lithic sandstone, siltstone, and shale overlying a basal quartzose unit. The base of the Cantuar Formation has a high local relief and in places has eroded long, wide valleys into the Success and older Jurassic strata. The valleys were hundreds of kilometers long and up to 74 inmore » deep. Remnants of the Success sediment are preserved as isolated, buried cuestas on the margins of the valley walls. Cantuar sediments represent the infill of an extensive valley system that took millions of years to fill. The fill was from meandering streams with abundant paleosols, shallow lacustrine, and splay deposits. The top of the Cantuar Formation is represented by chert and quartzose sandstones deposited in a north-south-trending estuarine system with several tributaries. Several play types, which are dominantly stratigraphic, have been identified and are related to the valley incision, valley fill, and preserved erosional cuesta remnants.« less

The downdip Queen City sandstone interval in the Mestena Grande field area of the south Texas Gulf Coast Basin comprises two sandstone depositional units, referred to herein as A Lobe and B Lobe. A total of 583 ft (179 m) of conventional core from 11 wells containing predominantly B Lobe deposits was examined macroscopically. The A Lobe is a thin (6-34 ft; 1.8-10.4 m) fine- to very fine grained, mostly bioturbated, well-sorted sandstone. The B Lobe is composed of fine to very fine, well-sorted sandstone interbedded with siltstone and mudstone. The trace fossil assemblage of the B Lobe indicates that sediments were deposited in the Cruziana ichnofacies. Trace fossils and authigenic minerals also suggest oxygen stratification during deposition. The B Lobe contains five subunits, each as much as 13.5 ft (4 m) in net sandstone thickness. These units were deposited as part of a highstand systems tract during the early Lutetian Stage (early middle Eocene). The B Lobe is a primarily aggradational unit composed of storm-generated sandstone and heterolithic deposits of the lower shoreface to inner shelf environment. The A Lobe is an upward-coarsening unit that represents progradation of the shoreface during late highstand systems tract development. An interlobal mudstone, which separates the units, marks the transition from early to late highstand systems tract development. End_of_Record - Last_Page 767

In eastern Mississippi and western Alabama, the Tombigbee Sand Member of the Eutaw Formation accumulated as part of a marine transgression during the Late Cretaceous (Santonian Stage). The Tombigbee includes glauconitic, fossiliferous, micaceous, bioturbated, massive-bedded, quartzose sandstone and siltstone deposited on a marine shelf. The inner to middle shelf sandstone and siltstone of the Tombigbee disconformably overlie thinly laminated to cross-bedded, tidally influenced, fine- to medium-grained, nearshore sandstone of the Eutaw Formation. Ophiomorpha burrows are common in the lower member of the Eutaw, and no calcareous microfossils were recovered from this member. In eastern Mississippi, the disconformable Eutaw-Tombigbee contact is marked by a 1- to 2-in (2.54- to 5.08-cm) sandstone bed containing phosphatic pebbles, shark teeth, and reworked fossils. The Tombigbee contains a diverse macrofauna, including echinoderms, gastropods, cephalopods, and bivalves, and a rich microfauna and microflora, including foraminifera, ostracodes, and calcareous nannoplankton. The foraminiferal assemblage consists of globotruncanids, heterohelicids, nodosariids, anomalinids, verneuilinids, globotextulariids, and textulariids. The middle shelf marls of the Mooreville Chalk conformably overlie the Tombigbee. These lower Mooreville marlstone beds have a diverse microfossil assemblage similar to the upper Tombigbee beds.

A recent well in northeastern Kansas penetrated 296 ft (90.2 m) of dark gray siltstone in the Precambrian Mid-Continent rift (Proterozoic Rice Formation). Correlations indicate this unit may be as thick as 600 ft (183 m) and is possibly time-equivalent to the Nonesuch Shale (Middle Proterozoic) in the Lake Superior region. The upper half of this unit qualifies as a lean source rock (averaging 0.66 wt. % TOC), and organic matter in it is in the transition stage between oil and wet gas generation. The presence of the gray siltstone in this well and similar lithologies in other wells is encouraging because it indicates that source rock deposition may be common along the Mid-Continent rift, and that parts of the rift may remain thermally within the oil and gas window. Microscopic examination of calcite veins penetrating the dark gray siltstone reveals numerous oil-filled and subordinate aqueous fluid inclusions. Homogenization temperatures indicate these rocks have been subjected to temperature of at least 110-115°C (230-239°F). Burial during the Phanerozoic is inadequate to account for the homogenization temperatures and thermal maturity of the Precambrian rocks. With the present geothermal gradient, at least 8250 ft (2.5 km) of burial is necessary, but lesser burial may be likely with probably higher geothermal gradients during rifting. Fluorescence colors and gas chromatograms indicate compositions of oils in the fluid inclusions vary. However, oils in the fluid inclusions are markedly dissimilar to the nearest oils produced from Paleozoic rocks.

The Cenomanian to earliest Turonian (Cretaceous) Kaskapau Formation in northwestern Alberta and adjacent British Columbia contains three shallow-marine shelf sandstone bodies encased in shale: the Doe Creek, Pouce Coupe, and Howard Creek members. These sandstone bodies were deposited in a retrogradational pattern, subparallel to the paleoshoreline of the underlying Dunvegan Formation. They represent distal-deltaic sedimentation during sea level lowstands or stillstands that punctuated the overall transgression represented by the shale of the Kaskapau Formation. A thin, slightly to nonbioturbated finely interbedded sandstone, siltstone, and shale facies containing syneresis cracks and no benthic foraminifera (facies 4) may be important paleoenvironmentally, representing th leading edge of a progradational wedge. The sandstone bodies are bounded by disconformities. The lower disconformity is erosive, perhaps the result of wave scour associated with a minor fall in relative sea level. The upper disconformity is a flooding surface formed as relative sea level subsequently rose. Within the Doe Creek Member, the overlapping I, N, and A reservoir sandstone bodies suggest an oscillatory shoreline caused by high-frequency, relative sea level fluctuations during the overall transgression. As such, the succession represents a transgressive, high-frequency sequence set. The Howard Creek Member is directly overlain by the Second White Speckled Shale (Turonian), which represents a condensed section having good source rock potential. The latter unit was deposited durin the peak of the marine transgression corresponding to an eustatic highstand.