ALBERT

Description: An extensive seismic database covering an area of 100,000 km 2 (38,610 mi 2 ) and 16 wells are integrated to define a sequence-stratigraphic framework for the Lower Cretaceous succession in the southwestern Barents Sea. Seven sequences (S0–S6) are defined, and the geometry, trajectory, and lateral variability of decompacted seismic clinoforms are described to elucidate the depositional history of the basin and to better understand coarse-grained sediment transport from the shelf to basin. Three different clinoform scales are recognized: (1) clinoform sets with 35–60 m (115–197 ft) height, interpreted as deltaic or shoreline clinoforms; (2) clinoform sets with 60–110 m (197–361 ft) height, interpreted as sediments prograding on a continental shelf; and (3) clinoforms with greater than 150 m (〉492 ft) height, which represent shelf-margin clinoforms. Furthermore, clinoforms are grouped into two main progradation directions: (1) clinoforms prograded to the southeast in sequences 2–3, in the Fingerdjupet Subbasin and the western Bjarmeland platform, indicating a source of sediments located in the west-northwestern Barents Sea, and (2) clinoforms prograded to the southwest in sequences 1–6, in the eastern part of the Bjarmeland platform, Nordkapp Basin, and Finnmark platform, indicating a second source of sediments located in the east-northeast. Additionally, in the Hammerfest Basin, clinoforms prograded to the southeast off the Loppa high in sequences 5–6. Low-relief (35–60 m [115–197 ft]), high-gradient, and oblique clinoforms are observed within sequence 2 in the western Bjarmeland platform. The high-gradient foresets are interpreted as potential coarse-grained deposits or as a result of clinoforms prograding to progressive deeper waters, resulting in steeper foresets. Clinoforms located in the eastern part of the study area are interpreted as sourced by a mud-rich system, reflecting a long transportation distance. However, thin, heterolithic patterns in the gamma-ray log possibly reflect thin, sheetlike sands. The height of the clinoforms seems to be a factor controlling the sediment bypass to deep water in the study area. When the height is more than 200 m (656 ft), bottomset deposits are common. This study contributes to a better understanding of the paleogeography and the evolution of the frontier southwestern Barents Sea during the Early Cretaceous and to comprehending the variables increasing the bypass of coarse-grained sediments to deep-water settings.

Description: Variations in environmental and biological origins contributing to the heterogeneity of lacustrine source rocks can be illustrated in their diverse genetic facies. The Zhu 1 depression, eastern Pearl River Mouth Basin, South China Sea, is characterized by two thick, Paleogene, organic-rich synrift units, the Wenchang and Enping Formations. The integration of bulk geochemical and biomarker data with tectonic and sedimentary information provides the basis for a comprehensive assessment of the environmental and ecological changes through geologic time and their impact on the heterogeneity of these lacustrine source rocks. Both the Wenchang and Enping Formations display wide variations in total organic carbon content and hydrogen index values as well as biomarker composition, suggesting lateral and chronological changes in organic facies. Using gas chromatography–mass spectrometry and hierarchical cluster analysis, five genetic facies were identified within these two source horizons. These facies represent different organic-matter inputs and sedimentary and early diagenetic environments based on their distinctly different assemblages of 11 source-dependent biomarker ratios. Four facies were distinguished in the Wenchang Formation, and two facies were distinguished in the Enping Formation, with one being common to both formations. During the middle Eocene, the Wenchang Formation was deposited in a series of small, deep lakes of laterally variable salinity, acidity, and biofacies. During the deposition of the Enping Formation in the late Eocene and early Oligocene, the previous lakes merged into fewer lakes with shallower depth and larger areal coverage, with the biota becoming more uniform across the whole depression. The coevolution of these lacustrine settings and their biota is closely associated with the development of the Zhu 1 depression, within which multiple separate sags produced by rapid mid-Eocene subsidence finally merged into a single depositional unit during slow subsidence in the late Eocene and early Oligocene. Accordingly, an integrated model was established to provide an overview of the contrasting origins of lacustrine source rocks during the two Paleogene epochs. This model may have important implications for source-rock prediction in the undrilled parts of the basins or for reference to source-rock heterogeneity in other rift basins.

Description: Three-dimensional (3-D) printing provides an opportunity to build lab-testable models of reservoir rocks from tomographic data. This study combines tomography and 3-D printing to reproduce a sample of the Fontainebleau sandstone at different magnifications to test how this workflow can help characterization of transport properties at multiple scales. For this sandstone, literature analysis has given a porosity of 11%, permeability of 455 md, mean pore throat radius of 15 μm, and a mean grain size of 250 μm. Digital rock analysis of tomographic data from the same sample yielded a porosity of 13%, a permeability of 251 md, and a mean pore throat radius of 15.2 μm. The 3-D printer available for this study was not able to reproduce the sample’s pore system at its original scale. Instead, models were 3-D printed at 5-fold, 10-fold, and 15-fold magnifications. Mercury porosimetry performed on these 3-D models revealed differences in porosity (28%–37%) compared to the literature (11%) and to digital calculations (12.7%). Mercury may have intruded the smallest matrix pores of the printing powder and led to a greater than 50% increase in measured porosity. However, the 3-D printed models’ pore throat size distribution (15 μm) and permeability (350–443 md) match both literature data and digital rock analysis. The powder-based 3-D printing method was only able to replicate parts of the pore system (permeability and pore throats) but not the pore bodies. Other 3-D printing methods, such as resin-based stereolithography and photopolymerization, may have the potential to reproduce reservoir rock porosity more accurately.

Description: The Upper Ordovician Red River Formation has been a prolific producer of oil and gas in the Williston Basin, where it has cumulatively produced more than 750 million bbl of oil equivalent over the past half century. Previous studies have recognized petroleum source beds, referred to as kukersites, in the Red River Formation but have not determined their complete extent or hydrocarbon generation significance. Examination and analysis of 28 cores and greater than 300 wireline logs have revealed 10 distinct kukersites in the Red River D zone that can be correlated individually for tens to hundreds of miles (tens to hundreds of kilometers) across the western quarter of North Dakota. Although each Red River kukersite is typically thin (1–2 ft [0.3–0.7 m] thick), they combine to reach net thicknesses of greater than 12 ft (3.7 m) with average present day total organic carbon (TOC) values of typically 3–6 wt. %. Hydrogen index (HI) values from kukersite samples range from primarily greater than 800 mg hydrocarbons (HC)/g TOC within the northern flank of the basin to systematically decreasing to less than 100 mg HC/g TOC within the basin center. This systematic decrease in HI is interpreted to be a function of increased thermal maturity, where hydrocarbon generation has depleted kukersite organic richness. Preliminary calculations of hydrocarbon volumes generated from Red River kukersites, based on a previously developed method that calculates the volumetric decrease in original to present-day kerogen content, total approximately 66 billion bbl (1.05 x 10 10 m 3 ) of oil equivalent. This approximate generation total is more than enough to account for cumulative Red River production and supports the idea that the Red River is a self-sourced petroleum system with potentially significant remaining exploration potential.

Description: Event-based risk management (EBRM) is an improved way of describing subsurface uncertainties and their possible business impacts in a manner that facilitates specific actions to improve business performance. In EBRM, uncertainties are viewed as potential causes of risk events that could in turn lead to consequences that affect the attainment of objectives. This "causes–event–consequences" syntax aids the design of prevention measures to inhibit the causes turning into the event and mitigation measures to reduce the potential consequences should the risk event occur, and it also facilitates construction of a risk taxonomy scheme based on risk consequences, events, and causes. Using a data set of 1456 subsurface risks, each risk was described in this manner and placed in the taxonomy, and the proportion of risks in each taxonomic group was analyzed. This revealed clear trends in the relative frequency of risk groups with type of field: for example, risks related to hydrocarbon-in-place volumes are more frequently identified in deep-water oil fields and gas fields feeding liquefied natural gas plants, situations in which resource volumes are critical to support the large project capital costs. Trends were also evident with field maturity: for example, risks related to hydrocarbon-in-place volumes are more frequently identified before the field sanction decision than afterward. Several benefits have yielded from EBRM: the risk description syntax encourages the creation of meaningful risk-management actions, the taxonomy and associated risk identification frequencies assist the identification of relevant risks so that key risk areas are not overlooked and also help to anticipate future risks, and the focus on risks (rather than uncertainties) helps to focus resources (data acquisition, technical studies) onto those aspects of the subsurface that are likely to impact business outcomes.

Description: A comprehensive study of seep carbonates at the top of the organic-rich Maastrichtian to Danian Moreno Formation in the Panoche Hills (California) reveals the mechanisms of generation, expulsion, and migration of biogenic methane that fed the seeps. Two selected outcrops show that seep carbonates developed at the tip of sand dykes intrude up into the Moreno Formation from deeper sandbodies. Precipitation of methane-derived cements occurred in a succession of up to 10 repeated elementary sequences, each starting with a corrosion surface followed by dendritic carbonates, botryoidal aragonite, aragonite fans, and finally laminated micrite. Each element of the sequence reflects three stages. First, a sudden methane pulse extended up into the oxic zone of the sediments, leading to aerobic oxidation of methane and carbonate dissolution. Second, after consumption of the oxygen, anaerobic oxidation of methane coupled with sulfate reduction triggered carbonate precipitation. Third, progressive diminishment of the methane seepage led to the deepening of the reaction front in the sediment and the lowering of precipitation rates. Carbonate isotopes, with 13 C as low as –51 Peedee belemnite, indicate a biogenic origin for the methane, whereas a one-dimensional basin model suggests that the Moreno Formation was in optimal thermal conditions for bacterial methane generation at the time of seep carbonate precipitation. Methane pulses are interpreted to reflect drainage by successive episodes of sand injection into the gas-generating shale of the Moreno Formation. The seep carbonates of the Panoche Hills can thus be viewed as a record of methane production from a biogenic source rock by multiphase hydraulic fracturing.

Description: Production decline prediction is important to understand the performance and life span of oil and gas wells. The most common prediction method is decline curve fitting based on available production rate data. Such data are fit with different equations that extrapolate to future time. However, the parameters are commonly poorly constrained, especially when the production rate data are limited. In this study, we establish a novel gas isotope interpretation tool to better predict the resource quantity and life span of producing gas wells. This tool is based on the evolution of methane carbon isotope ratios ( 13 C1) caused by different gas-releasing processes during production. It requires (1) real-time methane carbon isotope ratio data, (2) continuous gas production rate data for a certain period of time, and (3) basic geological and engineering conditions. We successfully applied the production decline prediction tool to a producing shale gas well in the Barnett Shale. We obtained real-time 13 C1 data for approximately 1 yr using our proprietary, field-deployable gas chromatography–infrared isotope ratio analyzer. The prediction in this well from the isotope method showed a total reserve of up to 7.34–7.75 BCF (2.07–2.19 x 10 8 m 3 ), which was used to constrain the production decline trend of the study well. The measured production rate data were first fit using the Arps equation, which then joined to an exponential decline curve smoothly at approximately 10 yr, such that the cumulative production calculation from integration of the product rate curve equaled to the total reserve predicted by the isotope method. The novel production decline prediction method thus provided important constraint on the future well production and expected ultimate recoverable reserves.

Description: Opening-mode veins in cores drilled from the mudrocks overlying and underlying the major Silurian salt décollement in the Appalachian plateau (Tioga and Lawrence Counties, Pennsylvania) have mineralogic and isotopic compositions generally matching those of their host mudrocks, suggesting opening and filling amid little cross-stratal fluid motion. Calcite and most trace minerals probably entered the veins via dissolution–reprecipitation from nearby host rock. Consistent with this interpretation are the observations that (1) trace minerals within the veins, including quartz, pyrite, and dolomite, are invariably also present within the layers hosting the veins, with vein cement minerals generally reflecting the abundance and solubility of minerals in the host rock, and (2) carbon and oxygen isotopic compositions of vein-filling calcite are similar to those of calcite within the host rock, with vein-filling 18 O slightly depleted and 13 C slightly enriched. Modeling the fluid isotopic evolution, assuming vein opening and filling amid immobile connate formation water, accounts for these minor but systematic differences, which are attributable to increasing temperature and hydrocarbon maturation. An exception to the above trend is barite, which, despite its low solubility, is systematically enriched in veins with respect to the host rock. It is unclear whether barite precipitation resulted from the influx of external fluids—perhaps deriving from Silurian salt—or from barium mobilized at depth from local clays or organic material.

Description: Water salinity in the San Joaquin Valley is a function of depth, location, and stratigraphy. This paper presents a reconnaissance study of water salinity within Kern County, California, using chemical analyses from oil field produced water and water wells as well as geophysical logs. Log analysis indicates that the base of underground sources of drinking water (USDWs) (〈10,000 mg/L) slopes from northwest to southeast. Lab analyses show that USDWs extend to depths as great as 1900 m (6233.5 ft) southeast of Bakersfield. This area receives the greatest amount of fresh water recharge from streams flowing westward from the Sierras. The marine Olcese Sand is more saline than the overlying and underlying aquifers and separates the aquifers into an upper and lower USDW. Log analysis also indicates a zone of higher salinity separating zones of lower salinity in this area. Salinities in the west are higher, and depths to base USDW are variable. Although waters in many sands in the western valley are more saline than 3000 ppm total dissolved solids (TDS), numerous wells contain waters between 3000 and 10,000 ppm at depths of less than 600 m (1968.5 ft), particularly in the nonmarine Tulare Formation. At North Belridge field, a salinity reversal is apparent below 2100 m (6890 ft). Waters above this depth are approximately 40,000 mg/L TDS, whereas water salinities below 2200 m (7218 ft) range from 10,000 to 32,000 mg/L. Extremely high salinities are found in several wells less than 30 m (98 ft) deep, primarily in the northwestern area. These may be perched aquifers or lie adjacent to unmapped agricultural drainage sumps and do not reflect salinities in the regional aquifer.

Description: To assess prospective modeling trends for oolitic tidal sand shoals and explore potential patterns of reservoir heterogeneity, this study examines, quantifies, and models the cycle-scale architecture of the Holocene mobile oolitic tidal sand shoal complex at Schooner Cays, Bahamas. Process-based stratigraphic trends are captured in quantitative, geocellular models of the shoal from analyses of satellite imagery; two-dimensional, high-frequency seismic (chirp) data; and sediment cores. Data show that longitudinal tidal sand ridges extend up to 8 km (5 mi) along depositional dip, gradually transforming bankward into channel-bound, compound barforms consisting of linear, parabolic, and shoulder bars. These bars terminate into a laterally extensive (10 km [6 mi]), strike-elongate sand sheet. Each bar type includes distinct internal architecture, grain size, and sorting related to feedbacks among hydrodynamics, geomorphology, and sedimentology. Building on these data and concepts from the Holocene accumulations, this study demonstrates a methodology for quantifying and validating probabilistic stratigraphic trends prior to their inclusion in stochastic-based facies modeling algorithms. Inclusion of statistically robust facies probability volumes during truncated Gaussian simulation generated ordered and geologically accurate facies distributions relative to bar-crest centerlines, water depth, and geomorphic position. Petrophysical models that incorporate facies-specific porosity, permeability, and water saturation functions display pronounced cycle-scale heterogeneity that could provide insights into variable production rates and poor sweep efficiency commonly encountered during development of analogous oolitic reservoirs.

Description: Organic-rich and carbonate-rich Eagle Ford Shale is a self-sourced oil and gas reservoir with little alteration of gas chemistry as might be affected by petroleum expulsion and migration. As such it provides an ideal natural laboratory to quantify the compositional variation of gases generated from oil-prone type II kerogen during thermal maturation. The chemical composition of the gas released from rock crushing was conducted and integrated with Rock-Eval pyrolysis to define the empirical relationship between gas compositional parameters and thermal maturity in this study. From 10 wells in the Eagle Ford Shale in south Texas, we collected 74 core samples having a range of thermal maturity (the measured maximum temperature [ T max ] values of hydrocarbons generated in Rock-Eval pyrolysis range from 427°C to 494°C [800°F to 921°F], and the calculated equivalent vitrinite reflectance ( R oe ) values range from 0.51% to 1.73% based on T max values). Total organic carbon content ranges from 0.3% to 8.53%, with an average of 3.12% (standard deviation of 1.77%). Burial depth is from 2989.6 to 13,827.3 ft (911.2 to 4214.6 m). Our results showed that gas composition in the Eagle Ford Shale is mainly controlled by thermal maturity, and three stages of gas generation are identified based on the C 1 and C 2 concentrations of the gases released by rock crushing from Eagle Ford Shale core samples. The three stages of gas generation correspond to the following processes of organic matter conversion: (1) kerogen and bitumen thermal cracking to crude oil, (2) bitumen and heavy crude oil thermal cracking to light oil, and (3) light oil cracking to gas. Methane-rich gas and an abundance of branched butane and pentane are generated in light oil cracking to gas, resulting in high C 1 /C 2 , C 1 /(C 2 + C 3 ), i-C 4 /n-C 4 , and i-C 5 /n-C 5 ratios. Increased cracking of normal alkanes such as n-butane and n-pentane occurs in the light oil cracking to gas. Empirical equations between gas compositional parameters and thermal maturity ( T max or R oe ) are obtained for oil-prone type II. The C 1 , C 2 , C 1 /C 2 , C 1 /C 2 + C 3 , and i - C 4 /n - C 4 ratios are the five best parameters for determining thermal maturity with an exponentially derived R 2 value of 0.74. The composition of gas produced from the Eagle Ford Shale following hydraulic fracturing is used to validate the empirical equations. Calculated thermal regime for the oil production based on the produced gas is located at the peak of oil generation and the beginning of light oil cracking to gas, corresponding to T max from 454°C to 464°C (849°F to 867°F) or at an R oe ranging from 1.01% to 1.19%. Empirical equations provide a basis for interpretation of mud gas logging data and produced gas composition.

Description: In this paper, a new approach to calculating and restoring the effects of physical compaction in subsalt units is presented. The loading of subsalt units and associated physical compaction is controlled by a combination of suprasalt sedimentation and salt movements. Here it is proposed that the change in load affecting the subsalt units is equivalent to the thickness between paleosurfaces of the basin (regional levels) reconstructed for successive stratigraphic horizons. This is in contrast to suprasalt units, where the changes in load are equivalent to the thickness of the stratigraphic unit. The new approach is integrated into a complete workflow for sequential restoration in a salt basin, which involves (1) removing the effects of physical compaction in suprasalt units, (2) reconstructing the paleosurfaces of the basin (regional level), (3) restoring faults, (4) unfolding to the reconstructed regional level to restore the effects of salt movement in the suprasalt units, (5) reconstructing the change in load affecting subsalt units and restoring the associated physical compaction, and (6) restoring any isostasy and postrift thermal subsidence. Results obtained using this workflow are compared with other methodologies to assess the differences in subsalt sediment thickness and structural configurations. These results suggest that the workflow proposed in this paper will improve the accuracy of sequential restoration of subsalt hydrocarbon plays, allowing their structural configurations through time to be more accurately quantified, and will ultimately reduce the risks in developing subsalt resources.

Description: The Upper Jurassic Norphlet Formation is an eolian sandstone and important hydrocarbon reservoir that overlies the Louann Salt in the Gulf of Mexico (GOM). Because the sand was concentrated into dunes formed by Late Jurassic winds, determining the source areas and paleotransport direction of the sand can improve predictions of the distribution of the dune facies around the GOM. Paleo–wind-blown sediment transport into the proto-GOM was controlled by wind direction and magnitude and the extant topography of the basin and adjacent uplands. Analysis of the Norphlet Formation in the eastern GOM shows that wadis and alluvial fans controlled by the location of highs were the primary route for introducing sediment of varied provenance into the eolian erg. Eolian transport directions interpreted from dip-log analyses are south directed in southern Alabama and west to northwest directed in western Florida. Interpretations of regional, two-dimensional, prestack-depth-migrated seismic data show that erosional incision of the Middle Ground arch occurred prior to and during the time of Norphlet deposition; this as well as preexisting lows in the basement topography may have facilitated basinward sand transport of sediment that fed the Norphlet Formation erg preserved in the deep-water subsurface eastern GOM.

Description: A total of 225 rock samples and 37 oil samples from the Beibuwan Basin, South China Sea, were analyzed with geochemical and organic petrological techniques to evaluate the Eocene lacustrine source rocks and investigate controls on their properties and the distribution of different oil families in the basin. Two types of organic facies are recognized in the Liushagang Formation (LS). The first organic facies is algal-dominated and mainly occurs in the organic-rich, laminated mudstones of the middle member of the LS (LS-2) that were deposited in an anoxic, stratified, medium–deep lake environment. It is geochemically identified by its high abundance of C 30 4-methylsteranes and heavy 13 C values in the range of –22.4 to –27.5. The organic matter in this organic facies comprises type I and II 1 kerogens, with its macerals dominated by fluorescent amorphous organic matter (AOM) and exinites, indicating a highly oil-prone character. The second organic facies is of terrestrial algal origin and is mainly identified in the nonlaminated mudstones of the upper (LS-1) and lower (LS-3) members of the LS that were deposited in shallow, dysoxic, weakly stratified, freshwater environments. Source rocks of the second organic facies mainly contain type II 1 –II 2 kerogens with mixed macerals of AOM, internites, and vitrinites. It is geochemically differentiated from the algal-dominated organic facies by its relatively low abundance of C 30 4-methylsteranes and lighter 13 C values in the range of –27.20 to –28.67. Three oil groups are identified by their biomarkers and stable carbon isotopes. The first two groups (A and B) are probably end-members of two major oil families (A and B) that correspond to the algal-dominated organic facies and algal–terrestrial organic facies, respectively. Most of the discovered oils belong to group A oils that are characterized by a high abundance of C 30 4-methylsteranes and heavy 13 C values and show a good correlation with the algal-dominated organic facies in LS-2. Group B oils are found only within the LS-1 and LS-3 reservoirs, and they are recognized by their relatively low content of C 30 4-methylsteranes and lighter 13 C values, showing a close relation to the algal–terrestrial source facies within the LS-1 and LS-3 members, respectively. Group C oils display intermediate biomarker features and stable carbon isotope values and are interpreted to be a mixture of group A and B oils. The oil–source correlation reveals a strong control of organic facies on the geographic distribution of oil groups or oil fields in the basin.

Description: Two-dimensional seismic refraction tomography was used to map the bedrock topography beneath Hallsands beach in southwest Devon, United Kingdom. Seismic refraction data were acquired from 11 spreads, 4 parallel to the beach and 7 normal to the beach, with either 12 or 24 geophones at 5-m (16-ft) spacing. Eight sediment cores were used to calibrate the velocity model. The bedrock consists of metasedimentary rocks that have a seismic velocity of 2100–2500 m/s (6900–8200 ft/s) and is overlain by variable amounts of gravel, peat, and muddy peat. Wood peat and peaty mud are differentiated within the peat as 700-m/s (2300-ft/s) velocity for wood peat and 1200-m/s (4000-ft/s) velocity for peaty mud. These refraction data were collected and processed in two dimensions, then imported into Petrel, a three-dimensional (3-D) geological modeling software package. The 3-D geologic model was built using the velocity attribute of the seismic refraction data. These selected data points were used to create 3-D horizons, surfaces, and contacts constraining the target bedrock surface from the overlying unconsolidated deposits. The bedrock surface beneath Hallsands beach is marked by two paleochannels. One paleochannel occurs in the north end of the beach beneath the axis of the modern valley. A second paleochannel occurs in the southern section of Hallsands beach centered along the axis of a tributary valley. Bedrock occurs at a depth of approximately –10 m (–33 ft) in the southern and northern sections of the main valley. Bedrock occurs at a depth of approximately –2 m (–6 ft) along the valley wall at the southern end of the beach east of the parking lot. Shore-perpendicular refraction lines differentiate layers within the peat, whereas shore-parallel lines delineate wood-peat, peaty-mud, and bedrock topography.

Description: Drilling for oil/gas and trawling on a continental shelf can cause damage to hard-bottom communities. Moving these activities offshore poses a threat to offshore communities. Habitat complexity is correlated with species diversity. The relationship of bottom relief to benthic species richness is not well understood in deeper communities. Relief may act as a proxy for species richness and disturbance risk. Geographic patterns in relief and richness are also not well understood. We gathered information on bottom relief and species richness of the sessile epibenthic community using a remotely operated vehicle. We surveyed hard bottom on the flanks of 13 banks in the north–central Gulf of Mexico, greater than 27-m (89-ft) depth, on the shelf and at the shelf edge. We found a positive asymptotic relationship between mean relief and species richness at the transect level. Secondary analyses at the drop site level revealed a similar relationship; variance was higher. The relationship was positively linear at the bank level. Analyses using standard deviation of relief yielded even stronger positive results. There was no significant relationship between species richness and latitude or longitude over the study area (215 km [133 mi]). When species richness was plotted in three dimensions, however, peaks in richness emerged in the southeastern study area and the western region, with a trough between them, coinciding with bottom relief. Species richness is positively correlated with bottom relief on banks in the northern Gulf of Mexico. Relief and species richness may be predicted at many spatial scales, up to hundreds of kilometers.

Description: Petroleum is retained in shales either in a sorbed state or in a free form within pores and fractures. In shales with oil resource potential, organic matter properties (i.e., richness, quality, and thermal maturity) control oil retention in general. In gas shales, organic pores govern gas occurrence. Although some pores may originate via secondary cracking reactions, it is still largely unclear as to how these pores originate. Here we present case histories mainly for two classic shales, the Mississippian Barnett Shale (Texas) and the Toarcian Posidonia Shale (Lower Saxony, Germany). In both cases, shale intervals enriched in free oil or bitumen are not necessarily associated with the layers richest in organic matter but are instead associated with porous biogenic matrices. However, for the vast bulk of the shale, hydrocarbon retention and porosity evolution are strongly related to changes in kerogen density brought about by swelling and shrinkage as a function of thermal maturation. Secondary organic pores can form only after the maximum kerogen retention (swelling) ability is exceeded at T max (the temperature at maximum rate of petroleum generation by Rock-Eval pyrolysis) around 445°C (833°F), approximately 0.8% vitrinite reflectance. Shrinkage of kerogen itself leads to the formation of organic nanopores, and associated porosity increase, in the gas window.

Description: The deep high-temperature, high-pressure Lower Cretaceous Bashijiqike sandstone (buried to depths as great as 6.5–7.1 km [21,325–23,293 ft]) is an important natural gas reservoir in Keshen gas field, Kuqa depression of the Tarim basin. Reservoir quality is a critical risk factor in the development of these ultradeep reservoirs. Integrated approaches incorporating routine core analyses and mineralogical, petrographic, and geochemical analyses have been used to investigate the diagenetic history of these rocks and their effect on reservoir quality with the aim to unravel the mechanisms for maintaining anomalously high porosities in sandstones that are buried to such a great depth. These sandstones are dominantly fine- to medium-grained, moderately to well-sorted lithic arkoses and feldspathic litharenite. Most primary pores have been lost by mechanical compaction or carbonate cementation, and the reduction of porosity by mechanical compaction was more significant than that by cementation. Dissolution of framework grains contributed to the enhancement of reservoir quality. Eogenetic diagenetic alterations mainly include mechanical compaction, precipitation of calcite cements, and grain-coating clays, and mesogenetic diagenesis is characterized by dissolution of framework grain by organic acids and subsequent precipitation of clay minerals and quartz. Infiltration of meteoric water related to teleodiagenesis would result in dissolution of the framework grains. The meteoric leaching events during teleodiagenesis are of great importance for the Bashijiqike sandstones. Grain-coating clay minerals (mixed-layer illite/smectite clays) help to preserve porosity at depth by retarding quartz cementation and pressure solution. The unique burial regime as early-stage shallow burial with late-stage rapid deep burial contributes to porosity preservation in eodiagenesis. Fluid overpressure caused by intense structural compression in the middle Himalayan movement retarded compaction and helped preserve porosity in the late rapid deep burial stage. Anomalously high porosities are mainly found in medium-grained, well-sorted sandstones with grain-coating clays but with low clay and carbonate cement content, of which the porosity is preserved primarily and enhanced secondarily. The lowest porosities are associated with sandstones that are tightly compacted or cemented with carbonates or rich in detrital matrix. Porosity–depth trends may vary significantly with lithofacies because of their differences in textural and compositional attributes. Five lithofacies are defined in terms of detrital composition and texture and type and degree of diagenesis. The reservoir quality prediction models of various litho-facies are constructed, and the results of this study provide insights into mechanisms for maintaining anomalously high porosity and permeability in high-temperature, high-pressure sandstone reservoirs and may help explain hydrocarbon distribution.

Description: 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.

Description: We use finite element modeling to show that upbuilding can be a significant component of salt diapir growth in tectonically stable systems when basin sediments are elastoplastic mudrocks. The ability of such sediments to deform plastically and the dependence of their strength on confining pressure enable structural thinning, which allows salt to pierce through a relatively thick roof. Once pierced, the originally continuous roof uplifts to form a megaflap. We show that the evolution to an upturned megaflap adjacent to a salt stock causes shortening of the bedding layers in the radial and vertical directions and extension in the hoop (circumferential) direction. These deformations lead to significant shear strains within the sediments; as a result, in some areas within the upturned megaflap, mudrocks have reached their maximum level of shear resistance and are failing. Thinning and shear failure of sediments are also significant near salt walls, despite the absence of out-of-plane deformation. We illustrate that cross-sectional area and bedding line lengths are not necessarily preserved. Based on our results, we re-evaluate traditional assumptions of kinematic restoration and show that established workflows may not properly restore salt systems that interact with shallow plastic sediments. Finally, we show that when wall rocks are deformable, salt diapir shapes are not necessarily a simple function of sedimentation and salt flux rates ( q fx / Å ) and that the diapir hourglass shape might result from lateral deformation of the megaflap.

Description: Provenance of Pleistocene–Holocene deepwater sediments in the Gulf of Papua (National Science Foundation Source to Sink Focus Area) has been studied to understand sediment sources and glacioeustatic influences on sedimentary routing and to better understand processes controlling sediment sources and delivery. We show how diverse processes operate in a complex deep-sea environment over time to control sediment routing and accumulation. Quantitative detrital analyses were conducted on 53 turbidite sand and 3 terrestrial samples with scanning electron microscopy and mineral liberation analysis, which yielded a broader and more insightful classification than manual point counts. We determined that (1) multiple terrestrial sediment sources along an approximately 500-km (300-mi) basin margin converged to form one continuous deep-sea system in two major basins (〉30 cal [calibrated] ka); (2) subsequent sea level fall near the last glacial maximum (LGM) (18–22 cal ka) drove repartitioning of sediment sources to create multiple distinct depocenters, presumably caused by migration and incision of individual rivers across the newly exposed coastal plain; and (3) multiple separate deep-sea channels then regained compositional similarity near the end of the LGM. In the subsequent Holocene, deepwater sand transport shut down, except for one locality where delivery continues because of a combination of narrow shelf–slope setting, oceanographic processes, and additional volcanic supply. These findings highlight the diverse processes that must be considered for the development of deepwater petroleum systems, in terms of sediment delivery, deposition, and provenance that may affect the reservoir geometry and quality.

Description: Secondary processes within reservoir sandstones during and after hydrocarbon production are poorly understood. This study looks at the effect of secondary water fill on a sandstone reservoir within a time span of 8 yr. The reservoir rocks consist of medium-grained litharenites with large clasts of shales and carbonates. They originate from a depleted gas reservoir that has been converted into an underground storage field for natural gas. Gas production resulted in a rise of the gas–water contact of approximately 30 m (98 ft). Based on their initial and final gas and water saturations, four zones can be identified. Observed diagenetic changes in all four zones include carbonate cementation, K-feldspar overgrowths, authigenic quartz overgrowths, pyrite formation, and poorly crystallized authigenic clay minerals. However, the authigenic clay mineral fraction differs significantly within the zones. Total clay mineral content and crystallinities of smectite, chlorite, kaolinite, and illite increase from the gas-bearing to the initial water zone. Additionally, expandable clay minerals and kaolinite were not identified in the gas-bearing zone. This is different in the secondary watered zones, where smectites and kaolinites are developing. The study shows that within a maximum of 8 yr from the start of water influx into the gas zone, new clay minerals are forming. The porosity and permeability reduction caused by this artificially induced process might continue and could also be of relevance within producing reservoirs, where water saturation increases during production.

Description: The northern deep-water Gulf of Mexico is one of the most active deep-water petroleum provinces in the world. This paper introduces the regional geologic setting for the northern deep-water Gulf of Mexico and briefly discusses the importance of technology in developing the area’s resources. Exploration has focused on four major geologic provinces: Basins, Subsalt, Fold Belt, and Abyssal Plain. These provinces formed from the complex interactions between Mesozoic–Cenozoic sedimentation and tectonics. Improved understanding of the geology of these provinces has largely been accomplished by improvements in seismic acquisition and processing. In addition, advances in drilling technology have permitted drilling and field development in increasingly greater water depths. The 226 oil and gas fields and discoveries in the northern deep-water Gulf of Mexico are summarized in terms of their exploration and development history, producing facility, ages of reservoirs (Upper Jurassic, upper Paleocene–lower Eocene, Oligocene, lower Miocene–upper Pleistocene), and trap type (structural, combined structural-stratigraphic, and stratigraphic). In addition, the interpreted regional distribution of Upper Jurassic and possible Lower Cretaceous source, source rocks is shown, in part based on the 26 wells that have penetrated these source rocks. The eight papers in this special issue review the geology of the Mississippi Canyon and northern Atwater Valley protraction areas. The first five papers review the subregional structural setting and the evolution of its tectonics and petroleum systems. The final three papers summarize the geologic evolution of two economically important intraslope basins—Thunder Horse and Mensa—in terms of their stratigraphy, structural evolution, and petroleum systems. These two basins contain two of the larger oil and gas fields, respectively, in the northern deep-water Gulf of Mexico.

Description: Thunder Horse and Mensa are two of the largest fields of oil or gas, respectively, in the northern deep-water Gulf of Mexico. The fields are present in adjacent intraslope minibasins, located approximately 12 mi (19 km) apart in Mississippi Canyon. Both fields illustrate important complexities of deep-water sedimentation. Analysis is based on the integration of wire-line logs, biostratigraphy, and a 378-mi 2 (979-km 2 ), three-dimensional seismic data set. Thunder Horse and Mensa reservoirs were deposited during the middle to late Miocene. Changes in paleobathymetry controlled the reservoir deposition, initially as salt withdrawal and later as turtle structures. From 125 to 24 Ma, the lithologies in both intraslope basins are interpreted as dominantly deep-water marls with interbedded shales. From 24 to 14.35 Ma, major input of deep-water siliciclastic sediments began. Sands were deposited in amalgamated sheets and amalgamated channel-fill units within the two major paleobathymetric lows; by contrast, shales were deposited across paleobathymetric highs. Between 14.35 and 13.05 Ma, the Thunder Horse turtle formed, creating a paleobathymetric high. Channelized sands were diverted around and deposited on the flanks of the structure. Meanwhile, to the north at Mensa, thick channel-fill sediments continued to be deposited. From 12.2 to 8.2 Ma, the lithologies throughout the entire area are dominantly overbank shales with thin channel-fill sands, suggesting that large volumes of sand bypassed the study area farther downslope to the south. Finally, at 9.0 Ma, Mensa's sheet-sand reservoir represents a different setting; sands were deposited near the crest of the Mensa turtle, which had subtle bathymetric expression.

Description: The Mensa and Thunder Horse intraslope minibasins in south-central Mississippi Canyon, northern deep-water Gulf of Mexico, had a linked structural evolution from the Early Cretaceous through the late Miocene. Analysis of the two minibasins illustrates the complexities of deep-water sedimentation and salt tectonics in intraslope minibasins. This study is based on the integration of a 378-mi 2 (979-km 2 ) three-dimensional seismic data set, wire-line logs, and biostratigraphic data. These two minibasins comprise several structural features that affected their geologic evolution: basement faults, autochthonous salt, three allochthonous salt systems (top Barremian, top Cretaceous, and Neogene), a growth fault and raft system, three major turtle structures with associated extensive crestal faults, and strike-slip faults. Remnant allochthonous salt pillows are present above the 125 Ma horizon (approximate top Barremian system) and on the 66 Ma horizon (top Cretaceous system) throughout the Mensa minibasin, whereas the top Cretaceous allochthonous salt system is identified regionally by a salt weld in the Thunder Horse area. These allochthonous salt systems formed weld surfaces beneath the Mensa and Thunder Horse turtle structures. Structural features and associated minibasins evolved during several discrete intervals. From the Early Cretaceous through the latest Oligocene (125 to 24 Ma), an extensive allochthonous salt canopy was present within the Mensa and Thunder Horse minibasins. During this interval, sediments loaded the salt, forming thin wedge- and sheet-form deposits in the Mensa area and a thick, northwest-trending trough in the Thunder Horse area. A secondary allochthonous salt system extruded at the Top Cretaceous level, as seen by remnant salt bodies. Salt withdrawal from these allochthonous salt systems provided accommodation for bowl- and trough-shaped external stratigraphic forms to develop during the Miocene. High sedimentation rates produced salt evacuation from these allochthonous salt systems and initiated diapirism that formed the Neogene allochthonous salt level. The prominent turtle structures in the two minibasins, critical to the formation of traps to the two major fields, developed at slightly different times: Thunder Horse at 14.35 and Mensa at 11.4 Ma.

Description: The 86 fields and discoveries in the central Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and Lloyd Ridge protraction areas are summarized with production characteristics and representative seismic profiles and wire-line logs. Three trap styles are recognized: four-way closure, three-way closure, and stratigraphic. The reservoirs in nearly all of the fields are Neogene deep-water sandstones; four are in Upper Jurassic eolian sandstones. Development facilities include a variety of floating platforms and production units and subsea tiebacks.

Description: The petroleum systems of two adjacent Miocene intraslope minibasins in the northern deep-water Gulf of Mexico are modeled to investigate why one of them produces primarily gas but the other produces oil. Specifically, the Mensa field produces gas from a faulted four-way closure that overlies a turtle structure, whereas the adjacent Thunder Horse field produces from a turtle structure with four-way structural closure. To resolve this issue, a three-dimensional petroleum-system model was constructed, whose results indicate that the Lower Cretaceous source interval, comprising type II kerogen, matured significantly earlier in the Mensa basin; the oil window was reached between 11.4 and 9.0 Ma, and the thermogenic gas window was reached between 6.2 and 0.0 Ma. By contrast, within the Thunder Horse basin, the source interval reached the oil window by 10.75 to 9.4 Ma and largely remains in the oil window. The Thunder Horse trap had formed by 13.05 Ma, which was before the end of the oil window. The Mensa trap (9.0–8.2 Ma) was not in place when the source rock passed though the oil window. The primary control on the timing of maturation and charge is related to the original thickness of allochthonous salt that created the accommodation for the thick Miocene deep-water sediments. Originally, the Mensa minibasin contained thicker Cretaceous allochthonous salt than the Thunder Horse minibasin. Consequently, as the salt was loaded with sediment and completely evacuated, the turtle structure (trap) formed earlier in Thunder Horse field than in Mensa. By contrast, the source rocks matured earlier in Mensa, prior to the deposition of reservoir sands and the formation of the trap. The results indicate that turtle structures with similar appearances can have subtle differences in the timing of their petroleum systems, which ultimately control whether the feature is charged and with what fluid. These features must be modeled carefully in evaluating their exploration potential.

Description: The structural framework and evolution from the Middle Jurassic to the present of the Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and western Lloyd Ridge protraction areas consist of a complex history influenced by basement fabric, multiple stages of salt movement, and gravitational gliding. A detailed tectono-stratigraphic interpretation of the study area indicates that three main stages of salt movement controlled sediment dispersal patterns and the formation and evolution of intraslope minibasins. These three stages of salt movement occurred during the Cretaceous, the Paleogene, and the Neogene. Basement structures were the primary control on initial salt kinematics, affecting gravity-driven slope deformation and resulting in a wide variety of structural styles. Basement (acoustic basement) structures (horsts, grabens, and half grabens) formed prior to the deposition of the Middle Jurassic autochthonous Louann Salt. These features are interpreted to have controlled the original thickness of the autochthonous salt layer and subsequent salt-withdrawal patterns. Mesozoic structures, such as extensional-compressional gliding systems and expulsion rollovers, formed above the autochthonous salt. Three levels of allochthonous salt systems are identified: (1) approximate top Barremian, (2) top Cretaceous, and (3) intra-Neogene (between 10 and 4 Ma). Early emplacement of two allochthonous salt layers is present in the northeastern part of the study area, whereas the Neogene allochthonous salt system extends throughout the Mississippi Canyon, western DeSoto Canyon, and northern Atwater Valley protraction areas. Salt from the autochthonous and two deep allochthonous salt layers was expelled vertically and basinward during the Neogene, feeding the younger allochthonous salt systems. The autochthonous and deep allochthonous salt layers were detachments for many of the large Neogene extensional (growth faults and turtles) and contractional (anticlines and thrust faults) structures, whereas the Neogene allochthonous salt system accommodated suprasalt minibasins associated with counterregional and roho salt systems. These three allochthonous salt layers were successively loaded by gravity-flow sediments, resulting in deep (above autochthonous or deep allochthonous salt layers) and shallow (supra-Neogene allochthonous salt) minibasin formations and local development of extensive salt welds. Northwest–southeast-oriented strike-slip structures, active during the Neogene, are present in the salt province within the study area. They are related to basinwide heterogeneities in the salt distribution and are controlled by differential basinward movement of adjacent suprasalt minibasins.

Description: Geochemical interactions between shale and hydraulic fracturing fluid may affect produced-water chemistry and rock properties. It is important to investigate the rock–water reactions to understand the impacts. Eight autoclave experiments reacting Marcellus and Eagle Ford Shale samples with synthetic brines and a friction reducer were conducted for more than 21 days. To better determine mineral dissolution and precipitation at the rock–water interface, the shale samples were ion milled to create extremely smooth surfaces that were characterized before and after the autoclave experiments using scanning electron microscopy (SEM). This method provides an unprecedented level of detail and the ability to directly compare the same mineral particles before and after the reaction experiments. Dissolution area was quantified by tracing and measuring the geometry of newly formed pores. Changes in porosity and permeability were also measured by mercury intrusion capillary pressure (MICP) tests. Aqueous chemistry and SEM observations show that dissolution of calcite, dolomite, and feldspar and pyrite oxidation are the primary mineral reactions that control the concentrations of Ca, Mg, Sr, Mn, K, Si, and SO 4 in aqueous solutions. Porosity measured by MICP also increased up to 95%, which would exert significant influence on fluid flow in the matrix along the fractures. Mineral dissolution was enhanced and precipitation was reduced in solutions with higher salinity. The addition of polyacrylamide (a friction reducer) to the reaction solutions had small and mixed effects on mineral reactions, probably by plugging small pores and restricting mineral precipitation. The results suggest that rock–water interactions during hydraulic fracturing likely improve porosity and permeability in the matrix along the fractures by mineral dissolution. The extent of the geochemical reactions is controlled by the salinity of the fluids, with higher salinity enhancing mineral dissolution.

Description: This study evaluates the proportion, length, and effective properties of thin (0.003–0.7 m [0.01–2.3 ft]) shale beds and drapes in tidally influenced channels within a compound valley fill with a focus on estimating geologically based effective rock properties. The Cretaceous Ferron Sandstone is an outcrop analog for fluvial–tidal systems with primary reservoirs being deposited as tidally influenced valley filling point bars. The study outcrops expose three valley systems in Neilson Wash of Utah. Light detection and ranging–derived digital outcrop models have been used to characterize shale length, width, thickness, and frequency of each valley fill succession. Long, uncommon, and anisotropic shales in valley 1 (V1) were deposited in a braided setting with little tidal influence. In contrast, shales in valley 2 (V2) were abundant, short, common, and equidimensional, suggesting deposition by more tidally influenced meandering rivers. Short, frequent, and equidimensional shales in valley 3 (V3) were deposited in single-thread meandering rivers with less tidal influence. A sandstone–shale model was used to estimate the effects of shales on vertical to horizontal permeability ratio ( \[{k}_{v}/{k}_{h} \] ). The unique character of each depositional unit was reflected in resultant \[{k}_{v}/{k}_{h} \] distributions. The valley fill deposits, V1, V2, and V3, had average \[{k}_{v}/{k}_{h} \] ratios of 0.11, 0.09, and 0.17, respectively. More tidally influenced reservoirs such as the studied V2 had short but frequent shales, which resulted in low \[{k}_{v}/{k}_{h} \] estimates. Estimates of \[{k}_{v}/{k}_{h} \] for valleys that predominantly contained fluvial point bar deposits with lesser tidal influence (V1 and V3) were higher. The results of this study highlight the link between shale heterogeneity, reservoir architecture, and inferred flow parameters.

Description: The Permian Khuff-C reservoir in Saudi Arabia is known for its lateral and vertical heterogeneity caused mainly by dolomitization. Detailed petrographic analysis of 600 thin sections, from six cored wells, revealed three main replacive dolomite fabrics: (1) fabric-preserving mimetic (FPM), (2) fabric-preserving nonmimetic (FPNM), and (3) fabric-destructive (FD) dolomites. Crystal sizes are mostly less than or equal to 20 μm for FPM dolomite, less than or equal to 50 μm for FPNM dolomite, and less than or equal to 100 μm for FD dolomite. The FPM dolomite decreases in abundance, and FPNM dolomite increases in abundance, with increasing grain content of the facies. The 18 O values of dolostones (although considered an obsolete term, dolostone is used here to mean rock containing ≥80% dolomite) indicate early dolomitization at low temperatures in Permian seawater or evaporated seawater, with landward facies (mudstone and wackestone) generally dolomitized by more evaporated waters and seaward grainy facies generally dolomitized by less evaporated, more normal marine seawaters. Stratigraphic variations in the dolostones’ 18 O values track with facies variations through fourth-order depositional sequences and indicate that different stratigraphic bodies of dolomite formed from seawaters with different degrees of evaporation. The 13 C values of the dolostones exhibit temporal trends inherited from the precursor limestones. Variations in the lateral and vertical abundance of dolomite and dolomite fabrics, in the propensity for each facies to be dolomitized, and in the dolomites’ oxygen isotopic values all suggest that multiple dolomitization events occurred in the Khuff-C reservoir as depositional cycles accumulated, with some dolostones overprinted by younger events. Average porosities of grain-rich dolostones are greater than those of mud-rich dolostones, indicating that depositional facies preordained porosity distribution within the dolostones. However, the more evaporated the dolomitizing fluid, the more likely dolomitization resulted in lower porosity regardless of facies.

Description: Outcrop studies of fracture development, used as analogs for subsurface fracture patterns, are critical because of the importance of fractures as fluid flow pathways and the fact that most fracture networks exist at a smaller resolution than current seismic data can resolve. Fracture networks in carbonate units are typically controlled by the mechanical properties of the unit, indicating that the mechanical stratigraphy, as well as the fracture stratigraphy, should be considered. This study presents the results of a fracture analysis in the Mississippian carbonates of the Ozark Plateau, considering both mechanical and fracture network characteristics. Mechanical characteristics of the succession were defined using a combination of rebound values and thin section petrography. Fracture characteristics included orientation and intensity, together with abutting relationships. Results indicate that fracture orientations show a distinct evolution throughout the measured succession, including the appearance of early systematic sets, followed by pervasive systematic fracture sets related to existing basement features. Fracture orientation changes do not correspond to changes in mechanical stratigraphy. Fracture intensity, however, is related to the thickness of the mechanical unit instead of the bed thickness and is greatest in less competent units. Mechanical control influences the fracture network on a smaller scale than that of regional tectonic stresses. Thus, evaluations of carbonate reservoirs must account for both the large-scale and the small-scale investigations into fracture characteristic controls. Outcrop evaluations are of critical importance to properly assess characteristics that are challenging to recover from conventional subsurface data sets such as core and seismic reflection volumes.

Description: The results of petroleum system models (PSM) critically depend on the computed evolution of the temperature field. Because PSM typically only resolve the sedimentary basin and not the entire lithosphere, it is necessary to apply a basement–heat-flow boundary condition inferred from well data, surface–heat-flow measurements, and an assumed tectonic scenario. The purpose of this paper is to assess the use of surface–heat-flow measurements to calibrate basin models. We show that a simple relationship between surface and basement heat flow only exists in thermal steady state and that transient processes such as rifting and sediment deposition will lead to a decoupling. We study this relationship in extensional sedimentary basins with a one-dimensional, lithosphere-scale finite element model. The numerical model was built to capture the large-scale dynamic evolution of the lithosphere and simultaneously solve for transient thermal processes in basin evolution, such as sedimentation, compaction-driven fluid flow, and seafloor temperature variations. Our analysis shows that several corrections need to be applied when using surface–heat-flow information for the calibration of basement heat flow in PSM. Not doing so can lead to significant errors of up to 30°C–50°C (86°F–122°F) at typical petroleum-reservoir and source-rock depths. We further show that resolving sediment-blanketing effects in basin modeling is crucial, with the thermal impact of sediment deposition being at least as important as rifting-induced basement–heat-flow variations.

Description: 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.

Description: The Fort Worth basin in northcentral Texas is a major shale-gas producer, yet its subsidence history and relationship to the Ouachita fold-thrust belt have not been well understood. We studied the depositional patterns of the basin during the late Paleozoic by correlating well logs and constructing structure and isopach maps. We then modeled the one-dimensional (1-D) and two-dimensional subsidence history of the basin and constrained its relationship to the Ouachita orogen. Because the super-Middle Pennsylvanian strata were largely eroded in the region, adding uncertainty to the subsidence reconstruction, we used PetroMod 1-D to conduct thermal-maturation modeling to constrain the post-Middle Pennsylvanian burial and exhumation history by matching the modeled vitrinite reflectance with measured vitrinite reflectance along five depth profiles. Our results of depositional patterns show that the tectonic uplift of the Muenster uplift to the northeast of the basin influenced subsidence as early as the Middle Mississippian, and the Ouachita orogen became the primary tectonic load by the late Middle Pennsylvanian when the depocenter shifted to the east. Our results show that the basin experienced 3.7–5.2 km (12,100–17,100 ft) of burial during the Pennsylvanian, and the burial depth deepens toward the east. We attributed the causes of deep Pennsylvanian burial and its spatial variation to flexural subsidence that continued into the Late Pennsylvanian in response to the growth of the Ouachita orogen and southeastward suturing of Laurentia and Gondwana. The modeling results also suggest that the Mississippian Barnett Shale reached the gas maturation window during the Middle–Late Pennsylvanian.

Description: Compaction disequilibrium is a widely accepted cause of overpressure, especially in clay-rich, rapidly deposited sediments. Clay diagenesis has been associated with the occurrence of overpressure greater than the compaction disequilibrium overpressure. These observations have led to the expectation that overpressure will be greater than the compaction disequilibrium contribution when clay diagenesis occurs within an overpressured mudstone. Clay diagenesis have been reported in a Pliocene section of a well from the Gulf of Mexico, offshore Louisiana. Pressure and log data from that well indicate that despite clay diagenesis, the overpressure can be attributed solely to compaction disequilibrium. This paper examines the whole mudstone and clay mineralogy composition and petrophysical characteristics of the offshore Louisiana well with clay diagenesis, but without a diagenesis contribution to overpressure and contrasts that data with results from other clay diagenesis and petrophysical studies. The comparison suggests that the offshore Louisiana well was relatively smectite poor compared with wells from regions associated with a clay diagenesis contribution to overpressure. The lower smectite content resulted in a lower percentage of reacted volume that was insufficient to allow the load transfer often associated with clay diagenesis. Petrophysical features of the offshore Louisiana well and nearby wells differ from the features associated with clay diagenesis in other Gulf of Mexico wells and a limited number of international wells. Comparison of location, age, depositional package, clay mineralogy, and petrophysical features suggests that provenance may control the occurrence of Gulf of Mexico mudstones that do not experience increased overpressure as a result of clay diagenesis.

Description: Fresh cores from tight-rock samples of subsurface hydrocarbon reservoirs retain mobile fluids. These fluids have complex chemical compositions and a large spectrum of molecules with different diameters and polarities. When investigated using high-resolution field-emission scanning electron microscopy (SEM), the imposed vacuum over hours of time causes pore fluids trapped in the rock sample to flow and interact with the mineral matrix. This paper reports the capillary fluid dynamics effect observed on freshly milled cross sections of tight chalk at high resolution. Multiphase fluid dynamic simulations confirm the aggregation of heavier fluid molecules on the geometrical irregularities of the pore space. As a consequence of this pitfall, the differentiation of solid organic matter versus variably viscous hydrocarbons from SEM data is subject to a fundamental revision.

Description: This study analyzed crude oils from the lower part of the third member of the Eocene Shahejie Formation (Es 3 L ) and three prospective source rocks from the Shulu sag, Bohai Bay basin, eastern China, using a variety of organic geochemical methods. Biomarker characteristics were used to interpret source rock organic matter input and depositional environment, and oil–source rock correlation. The biomarker data indicate that the crude oils originated from the Es 3 L source rock, which contains a mixture of plankton and land plant organic matters deposited in brackish–fresh water under reducing conditions. The oil in the Es 3 L is self-sourced instead of migrated from the overlying source rocks. The petroleum generation potential of the Es 3 L source rock was evaluated using organic geochemistry. Total organic carbon (TOC) values for approximately 100 samples are between 1.02 and 4.92 wt. %, and hydrogen indices range from 285 to 810 mg hydrocarbons/g TOC. The Es 3 L source rock contains mainly type II and III kerogen, and most of the samples are thermally mature. The data show that the Es 3 L source rock has good potential for liquid hydrocarbon generation. The Es 3 L rock also acts as the oil reservoir, having very low bulk porosity and permeability. Various types of storage space in the marlstone and carbonate rudstone in the Es 3 L of the Shulu sag include (1) fractures, (2) intergranular pores, (3) dissolution pores, (4) organic matter pores, (5) intragranular pores, and (6) seams around gravels. Pore size ranges from nanometers to millimeters. Because the oil was generated and stored in Es 3 L strata, which lack any obvious trap and seal and have low permeability, the unit represents a continuous petroleum accumulation.

Description: This paper shows how nonuniform source–receiver spacing in a three-dimensional (3-D) land acquisition creates footprints that could easily be mistaken for geology. In a 3-D time-migrated seismic volume from the midcontinent United States, amplitude extraction along the top of the Mississippian limestone formation shows a sinkhole-like feature, which is justified from a depositional perspective. However, an inspection of the acquisition layout shows that the sinkhole is a replica of the fold distribution. In land surveys where source and receivers seldom have a regular distribution and for unconventional plays that are not developed through patterned drilling, a thorough review of processing and acquisition parameters is necessary before interpreting amplitude maps.

Description: We use experimental (analog) models to examine the three-dimensional (3-D) fault geometries and interactions that develop during two phases of noncoaxial extension. In the models, a homogeneous layer of wet clay undergoes two phases of extension whose directions differ by 45°. The resulting fault pattern varies significantly with depth. At shallow levels, second-phase normal faults accommodate most second-phase extension. At depth, both second-phase normal faults and reactivated, first-phase faults with oblique slip accommodate most second-phase extension. A variety of interactions occurs between first-phase and second-phase faults. One interaction involves the upward propagation of second-phase faults from tips of reactivated, blind, first-phase faults. These hybrid faults have deep segments that strike subperpendicular to the first-phase extension direction and shallow segments whose strike varies with depth, becoming increasingly subperpendicular to the second-phase extension direction at shallow levels. A second interaction involves the nucleation of second-phase normal faults on the surfaces of reactivated, first-phase faults. These splay faults propagate upward and laterally from their nucleation sites into the hanging walls of the first-phase faults. As they propagate, they commonly encounter and link with different first-phase faults. The resulting composite faults have zigzag geometries in both map and cross-sectional views. A third interaction involves either the termination of second-phase antithetic normal faults against or near first-phase faults or the offset of first-phase faults by second-phase antithetic normal faults. The 3-D fault patterns and interactions within our models closely resemble those within the Taranaki basin of offshore New Zealand and Milne Point on Alaska’s North Slope.

Description: The geochemistry and reservoir characteristics of the lacustrine shale in the Eocene Dongying depression are described in detail based on thin-section and field-emission–scanning electron microscope observations of well cores combined with x-ray diffraction, physical property testing, and geochemical indicators. The Eocene Shahejie (Es) Formation Es4s–Es3x shale member is predominantly carbonate, clay minerals, and quartz. Six lithofacies were identified: (1) laminated limestone (organic-rich laminated limestone and organic-poor laminated limestone), (2) laminated marl, (3) laminated calcareous mudstone, (4) laminated dolomite mudstone, (5) laminated gypsum mudstone, and (6) massive mudstone. The Es4s–Es3x shale samples from three cored wells had total organic carbon (TOC) contents in the range of 0.58 to 11.4 wt. %, with an average of 3.17 wt. %. The hydrocarbon generation potential (free hydrocarbons [S1] + the hydrocarbons cracked from kerogen [S2]) values range from 2.53 to 87.68 mg/g, with an average of 24.19 mg/g. The Es4s–Es3x shale of the Dongying depression has a high organic-matter content with very good or excellent hydrocarbon generation potential. The organic maceral composition is predominantly sapropelinite (up to 95%). The hydrogen index (being S2/TOC) versus the maximum yield temperature of pyrolysate ( T max ) indicates that the organic matter is predominantly type I kerogen, which contains a high proportion of convertible organic carbon. The Es4s–Es3x shale is thermally mature and within the oil window, with the vitrinite reflectance values ranging from 0.46% to 0.74% and the T max value ranging from 413°C to 450°C, with the average being 442°C. The shale contains interparticle pores, organic-matter pores, dissolution pores, intracrystalline pores, interlaminar fractures, tectonic fractures, and abnormal-pressure fractures. The primary matrix pore storage is secondary recrystallized intercrystal pores and dissolution pores that formed during thermal maturation of organic matter. The TOC content and effective thickness of the organic-rich shales are the primary factors for hydrocarbon generation. The reservoir capacity is related to the scale, abundance, and connectivity of pore spaces, which are controlled by the characteristics of the lithofacies, mineral composition, TOC content, and microfractures.

Description: A succession of four deep-water lobe complexes deposited within a salt-controlled minibasin have been imaged in unprecedented detail on high-resolution, high-frequency, three-dimensional seismic-reflection data. The ponded interval was deposited over approximately 2.7 m.y. and consists of four discrete sequences, each of which contains one lobe complex. A systematic change exists in the shape and orientation of the lobe complexes through time: the two older lobe complexes are oriented broadly north–south and are up to 10 km (6 mi) long by 5 km (3 mi) wide, whereas the youngest lobe complexes are oriented southeast–northwest and have a rounder shape (9 km [6 mi] long by 8 km [5 mi] wide). The north–to-south migration of the feeder-channel entry point and the change in lobe-complex orientation are attributed to growth of the basin-bounding salt structures. Each lobe complex is composed of a feeder channel, multiple individual lobes formed of a trunk channel, and a diverging network of smaller distributary channels, commonly fringed by a high-amplitude band. The lobes are on average 1.6 km (1 mi) long by 1.3 km (0.8 mi) wide and are fed by trunk channels that range from 60 to 200 m (197 ft to 656 ft) wide, with thicknesses up to 15 m (49 ft). Variations in lobe shape and spatial location are driven by the response of the lobes to topographic growth along the edge of the basin and inherited seabed relief generated by previous lobe growth. In areas where lobe development is constrained by structural growth along the edge of the basin, the lobes become elongated and divert away from the growing topography. Lobe complexes of similar scales have been described in detail in outcrops and in unconfined settings on the sea floor, but this is the first study to describe these systems in such detail in the subsurface, resolving the individual lobes and lobe elements within a ponded intraslope basin. The high-resolution plan-view images help bridge the gap between the fine-scale sedimentological studies that have been carried out on lobe complexes and sheet sands in outcrop for the past 20 yr and more recent research on less well-resolved seismically imaged systems. The sheet sands described in outcrop studies can be correlated with features seen in the plan-view amplitude extraction maps. We record densely channelized lobes passing laterally into more branched, thinner channels and lobe elements then terminating in a high-amplitude fringe. We relate these seismic characteristics to outcrop facies of channelized, amalgamated, and layered sheets.

Description: Confidently defining the trajectory of faults that control structural traps is a recurring challenge for seismic interpreters. In regions with fault-related folds, seismic and well data often constrain the upper fold geometry, but the location and displacement of the controlling fault are unknown. We present a generalized area–depth strain (ADS) analysis method that uses the observed depth variation in deformed horizon areas to directly estimate underlying fault depth, dip, displacement, and layer-parallel strain from a structural interpretation. Previously established ADS methods are only applicable to structures controlled by faults that sole into layer-parallel detachments. The new technique, referred to as the fault-trajectory method, generalizes ADS analysis to contractional and extensional structures controlled by fault ramps that cut across layers and displace the regional. For structures where area is conserved during deformation and shear is minimal, laterally shifting the analysis limits across the structure defines changes in fault orientation. We validate the method by applying it to numerical forward models, analog clay models, and seismically imaged structures from the San Joaquin basin in California, the Sierras Pampeanas in Argentina, and the North Sea. The fault-trajectory method is shown to be robust, because it exactly reproduces the prescribed fault trajectories and displacements used to construct the numerical and analog models. In the natural examples, the ADS-estimated fault trajectories are consistent with independent fault-location constraints such as earthquake focal mechanisms, seismic imaging, and forward modeling.

Description: Well logs such as spontaneous potential and gamma ray historically have been the only tools available for facies evaluation of noncored wells in the McMurray Formation. The addition of microresistivity image logs has greatly improved facies identifications and interpretations, particularly when integrated with core data sets. In the case of McMurray channel complexes, core descriptions provide detail about bedding contacts, sedimentary texture, stratification, bioturbation intensity, and trace fossil diversity. Image logs provide texture, fabric, bedding contact style, dip directions and angles, and bedding architecture information, yielding paleoflow and lateral accretion directions. This study characterizes facies by integrating interpretations from 414 image logs with core-based descriptions from 138 of these wells. The reservoir targets, and most prolific depositional facies in this study, are associated with channel systems and their associated point-bar deposits. Facies identifications are based on several image log criteria. Mud clast breccias display variable dip angles and dip directions. Cross-stratified sands comprise vertical successions of stacked, internally consistent bedsets with high dip angles (〉15°) that indicate paleoflow direction. Lateral accretion beds show consistent dip directions with a progressive change from shallow-to-steep-to-shallow dip angles (e.g., 〈4 to 15° to 〈4°) from the base to the top of the succession, as well as beds that dip toward the thalweg of the paleochannel. Flat-lying (〈4°) mud records vertical accretion associated with point-bar tops or channel abandonment. Although this facies classification is specific to the McMurray Formation in the study area, the principles provided here are applicable to other subsurface studies and demonstrate the enhanced reliability of integrated core–image log data sets.

Description: The northeastern Brooks Range of northern Alaska is an active, north-directed fold-and-thrust belt that is advancing on the Barrow arch and the north-facing passive margin of the Arctic Basin. Density logs, leak-off tests, and mud-weight profiles from 57 wells from the northeastern North Slope were used to determine the magnitude of the present-day in situ stresses and document significant regional lateral and vertical variations in relative stress magnitude. Preliminary analysis of the in situ stress magnitudes indicates two distinct stress regimes across this region of Alaska. Areas adjacent to the eastern Barrow arch exhibit both strike-slip and normal stress regimes. This in situ stress regime is consistent with fault patterns in the subsurface and with north–south extension along the Barrow arch and the northern Alaska margin. To the south in and near the northeastern Brooks Range thrust front, in situ stress magnitudes indicate that an active thrust-fault regime is present at depths up to 6000 ft (1829 m). This is consistent with the fold-and-thrust structures in surface exposures and in the subsurface. However, at depths greater than 6000 ft (1829 m), the relative in situ stress magnitudes indicate a change to a strike-slip regime. This observation is consistent with the few earthquake focal mechanisms in the area and suggests deep north-northeast–oriented strike-slip faults may underlie the western margin of the northeastern Brooks Range.

Description: The geometry and growth of normal faults are fundamental to the evolution and petroleum prospectivity of sedimentary basins, controlling trap development; source, reservoir, and seal rock distribution; and fluid flow. The poorly studied, petroliferous Ceduna Subbasin located offshore southern Australia contains an east–southeast-striking, gravity-driven fault array, which soles out onto a southwest-dipping detachment horizon. These gravity-driven faults displace the White Pointer delta and overlying Hammerhead delta. Within the subbasin, structural closures bound by these gravity-driven faults represent the main exploration targets. Determining when these faults and associated traps formed relative to petroleum generation and migration and, more specifically, if the faults reactivated is thus critical to understanding the prospectivity of the Ceduna Subbasin. In this study, we use a time-migrated two-dimensional (2-D) seismic reflection survey covering the central Ceduna Subbasin to constrain the geometry and kinematics of the fault array. Throw patterns reveal that most faults nucleated in the Cenomanian. Although some faults display evidence for continuous growth by upper tip propagation throughout the Cenomanian to Maastrichtian, it is apparent that other faults were inactive during the Turonian–Santonian, before reactivating and propagating upward or dip-linking with overlying, newly formed faults during the Campanian and/or Maastrichtian. Faults that grew continuously during the Cenomanian to Maastrichtian primarily formed in the center of the study area, whereas reactivated faults developed in landward positions. Faults that formed because of dip linkage developed in seaward positions. We suggest that this spatial variation in fault growth style was controlled by compositional and mechanical heterogeneities in the Tiger and lower Hammerhead supersequences, which mark the boundary between the two delta systems. In addition to providing insights into the petroleum prospectivity of the Ceduna Subbasin, this study shows how 2-D seismic reflection data can be used to probe the kinematics of normal faults.

Description: The vast majority of discovered oils in the Bohai offshore area have undergone biodegradation ranging from 1 to 9 on the PM scale (a scale to rank the level of biodegradation, proposed by Peters and Moldowan, 1993 ). The extent of distribution and biodegradation of all discovered oils in the Bohai offshore area was investigated systematically using geologic and geochemical data to reveal controlling factors of varying levels of biodegraded oils. Based on the analysis of the environment and material significances and the resistance to degradation of biomarkers, the biomarker parameter assemblage that is suitable for the oil-source correlation of severely biodegraded oils (higher than PM 6) in the Bohai offshore area was determined. The spatial distribution and biodegradation extent are mainly controlled by the current burial depth, the duration of biodegradation, the area of the oil–water contact (OWC), and a late strike-slip movement of the Tanlu fault. Almost all biodegraded oils are found in shallow reservoirs above 2000 m (6562 ft). The longer the oils are present in these reservoirs or the larger the area of the OWC the reservoirs show, the greater the extent of biodegradation will be. The late, strong strike-slip movement of the Tanlu fault may have significantly enhanced the biodegradation extent of several oils in fields located in the Tanlu fault zone by introducing oxygenated freshwater from the surface or near surface and creating a more suitable environment for biodegradation. The C 19 tricyclic terpane/C 23 tricyclic terpane, C 24 tetracyclic/C 26 tricyclic terpane, and gammacerane/C 24 Tetracyclic do not seem to be influenced by biodegradation and show obvious differences between the three different source-rock intervals. Such a biomarker parameter assemblage can be used successfully to determine the origin of severely biodegraded oils (higher than PM 6) by correlating with extracts of possible source rocks in the Bohai offshore area.

Description: The successful implementation of geologic carbon sequestration depends on the careful evaluation of the petrophysical characteristics of the storage reservoir. Two petrophysical properties, porosity and permeability, constrain the reservoir in terms of its storage potential and injectivity. These two key parameters may vary significantly in scale within a reservoir. Likewise, the analytical tools that are useful for measuring these properties also vary and only assess pores of a given scale. In this investigation, 52 rock samples that consist of carbonates having a high degree of dolomitization were obtained from the Cambrian–Ordovician Knox Supergroup from different depth intervals; these samples span a significant area of the Midwestern United States. The samples were analyzed for total porosity and pore-size distribution using a variety of techniques, including petrographic image analysis, helium porosimetry, gas adsorption, mercury porosimetry, and ultrasmall-angle/small-angle neutron scattering. Capillary entrapment, or "residual saturation," is that part of the injected CO 2 that remains trapped in micropores after the pressure elevated by the injection process returns to ambient reservoir pressure. Results from low-pressure nitrogen and carbon dioxide adsorption and from mercury injection capillary pressure are important in that they provide insights about small pore size that otherwise cannot be resolved by standard helium porosimetry or by image analysis software. Results from these analyses suggest that micro- and mesoporosity control capillary entrapment, whereas macroporosity controls permeability.

Description: Cambrian–Ordovician strata of the midwestern United States are considered a promising reservoir for geologic storage of carbon dioxide. To assess the potential of the Ordovician St. Peter Sandstone, storage-resource estimates were generated using a hierarchical approach to estimating prospective storage resources. The method employs a series of increasingly sophisticated analyses to better facilitate an understanding of the uncertainty in the estimates. Results demonstrate how uncertainty of storage-resource estimates varies as a function of data availability and quality as well as the underlying assumptions used in the application of specific storage efficiency factors. In the simplest analysis, storage-resource estimates were calculated from updated regional-scale mapping of the gross thickness of the formation and by applying a single best estimate of the mean porosity for the entire formation. This analysis follows the technique prescribed by the US Department of Energy and yields storage-resource estimates ranging from 3.3 to 35.1 billion t CO 2 in the Michigan Basin and 1.0 to 11.0 billion t CO 2 in the Illinois Basin at the 10% and 90% probability levels. The second analysis incorporated generalized models of the diagenetic history of the formation throughout the two basins by implementing depth-dependent functions of porosity that lead to more realistic portrayals of spatially variable results. Similar resource estimates were calculated for the Michigan Basin, but reduced estimates (43%) were found for the Illinois Basin. The third analysis explicitly accounted for the local-scale spatial variability in reservoir quality using net-porosity calculations, resulting in a significant increase in the low-range resource estimate for the Michigan Basin and dramatic increases for Illinois Basin resource estimates (factor of 3 to 11 increases). A fourth analysis was conducted for the Michigan Basin that used advanced reservoir characterization to define reservoir properties for multiple reservoir facies and yielded resource estimates significantly larger than the third analysis and a larger range of uncertainty. This study highlights how different factors impact the expected uncertainty in storage-resource estimates, and analysis suggests that estimates from the first two approaches provide excessively conservative results, whereas the second two approaches tend to overestimate the resource.

Description: Two different approaches have been used to evaluate the potential for CO 2 geologic sequestration and CO 2 -assisted enhanced oil recovery in the major oil fields in Ohio: a volumetrics-based method, which uses field volumetric data to calculate CO 2 storage capacity, and a production-based method, which uses historical oil and gas production data to calculate CO 2 storage capacity. The fields were selected based on their historical importance as oil and gas producers as well as the availability of data in published sources. The storage capacity found using the production data–based methodology—878 million t—is believed to be more representative than that found using the volumetrics-based method because it uses actual production data to calculate void space for CO 2 storage rather than estimated efficiency factors. This estimated capacity is higher than previously reported values based on efficiency factors and is enough to support the storage of 25% of annual emissions from 45 of Ohio’s largest power plants for a period of 36 yr.

Description: The type section of the Oligocene to lower Miocene Maikop Group, considered the main source rock in the eastern Paratethys, has been studied using geochemical proxies to gain insights into depositional setting and hydrocarbon potential. The Maikop Group at the type section is approximately 600 m (2000 ft) thick. Deposition commenced after a major late Eocene sea level drop and a subsequent early Oligocene sea level rise. The Maikop Group is composed mainly of carbonate-free pelitic rocks. Calcareous rocks are limited to the lower Oligocene succession, including the Polbian Bed that forms a basin-wide marker horizon deposited during a time with significantly decreased salinity (Solenovian event). Anoxic conditions prevailed and were only interrupted for longer periods during deposition of the lower part of the lower Oligocene Pshekha Formation, the Polbian Bed, and the lower Miocene Olginskaya Formation. Total organic carbon (TOC) contents range up to 3.5 wt. %. Hydrogen index values are typically less than 300 mg hydrocarbons (HC)/g TOC but reach 420 mg HC/g TOC in black shales overlying the Polbian Bed (lower Morozkina Balka Formation). Organic richness of this level, approximately 10 m (33 ft) thick, is controlled by low salinity and high bioproductivity. The Maikop Group could generate approximately 2.0 t HC/m 2 surface area. A significant part (0.45 t/m 2 ) comes from the lower Morozkina Balka Formation, which generates a high-wax paraffinic–naphthenic–aromatic mixed oil. The Pshekha, upper Morozkina Balka, and Batalpashinsk Formations would generate low-wax oil or condensate. The hydrocarbon generation potential of the overlying formations is minor. Overall, the generation potential of the Maikop Group is surprisingly low.

Description: Micropore-dominated carbonate reservoirs remain challenging for accurate hydrocarbon evaluation and production because conventional reservoir models using depositional textures and petrophysical properties to distribute porosity and permeability cannot be applied. Nevertheless, understanding the distribution of pore systems and predicting the fluid flow behavior of microporous reservoirs is fundamental because micropores constitute a significant percentage of the total porosity and storage capacity. We present the results from an integrated study on the producing micropore-dominated Word field characterized by a facies-independent, diagenetically controlled pore system that approaches 100% microporosity. Four cored wells through the Albian Edwards Formation were described and correlated using stacking patterns and vertical facies trends; pore type characterization was done through thin section petrography, routine core analyses, scanning electron microscopy, and mercury injection capillary pressure data. This study is an example of a permeable reservoir in which intergrain pores are cemented during burial diagenesis and micropores, being more resistant to cementation, remain open to depths greater than 4000 m (13,000 ft). A unique relationship exists between porosity, permeability, median pore throat size, and microcrystalline textures, independent of facies and fabrics. Cumulative gas production data show there is a correlation between the total porosity and the structural position of the wells: wells high on the structure have the highest production. We demonstrate that an equally well–connected micropore network exists in mud-dominated rocks via the matrix and via grain-to-grain contacts in grain-dominated rocks. The here described intragrain micropore network through grain-to-grain contacts in cemented grainstones is a new carbonate flow path that will likely become more important as more unconventional carbonate reservoirs are explored.

Description: The Lower Cretaceous stratigraphic section in the northern Gulf of Mexico (GOM) comprises several well-documented carbonate systems that have prominent shelf-margin buildups, including the Berriasian Knowles Limestone ramp and shelf system, Barremian Sligo Formation shelf system, Aptian Pearsall Formation ramp system, and shelf systems of the Albian Glen Rose, Edwards, and Stuart City Formations. Two lesser-known but large-scale Lower Cretaceous Valanginian carbonate shelf to shelf-margin systems are documented in this investigation using core, wireline-log, and regional two-dimensional seismic data. The platform-margin succession of the older Calvin section comprises a shelf-margin buildup (back reef, reef, and fore reef facies) that may be as thick as 2000 ft (610 m). The seaward margin of the shelf, as displayed by seismic data, suggests shelf-to-basin relief of as much as 1000 ft (305 m) and margin-to-lagoon relief of 200 to 500 ft (60 to 140 m) (relief estimates are not decompacted). Major reef-building organisms are Lithocodium , stromatoporoids, and corals. The Winn limestone is younger than the Calvin limestone, and at the shelf margin, it may have been 600 to 800 ft (180 to 245 m) thick. It is composed of organisms similar to those of the Calvin reef complex. Considering the vertical position of the Calvin platform, succeeding the major bypass of Calvin lowstand siliciclastic sands, the platform probably records a transgression, which is consistent with its highly aggradational depositional style. The Winn shelf margin was initiated landward of the Calvin shelf margin and did not prograde as far seaward as the Calvin shelf margin. The recognition of these two Lower Cretaceous carbonate systems is important because they further detail the stratigraphic history and architecture of this deeply buried, lowermost Lower Cretaceous section in the GOM. These formations are also potential deep-gas, tight-carbonate (low-porosity) plays.

Description: The Alboran Sea in the Mediterranean is a back-arc basin developed during the Miocene by extensional collapse within an arc-shaped orogen. A major depocenter (〉10 km [〉6.2 mi]) is located to the west of the basin (West Alboran Basin [WAB]) and contains a diapiric province with overpressured shales and mud volcanoes. Seismic and well data are used to analyze the evolution of the shale structures in the northern margin of the WAB and to estimate the in situ stress tensor. Geomechanical modeling suggests a present-day normal faulting stress regime along the northern WAB, where the maximum horizontal stress is parallel to the coastline. Pore pressure shows a hydrostatic gradient down to 2000 m (6561 ft), where the top of the regional pore pressure ramp is located. Undercompaction is the dominant mechanism generating overpressures in sediments shallower than 5000 m (16,406 ft). At greater depths, thermal mechanisms impose an excess of pore pressure on the sediments feeding the diapirs. This framework is used to discuss the contribution of thermally generated pressures to the triggering of shale diapirism. Increasing thermal pressures in the deepest confined units cause tensile failure of the overburden and subsequently promote mud withdrawal and injection in the overburden. The magnitude of the overpressure conditions the vertical ascent of shale. The more mature structures reuse preexisting normal faults in their ascent toward shallower basin levels. Results provide insights into the current discussion about the triggering factors behind shale diapirism. They also help to explain the differences between shale structures and those shaped by salt tectonics.

Description: It is widely acknowledged that the growth and linkage of a boundary fault affects the evolution of the accompanying sedimentary basin and exerts a strong influence on its sedimentary characteristics. In this study, we attempt to discuss the evolution of a boundary fault and rift basin by using seismic interpretation, incremental fault throw, and growth rate–distance (G–d) profile, which are more suitable parameters than the expansion index in rift basins where footwall strata are missing because of erosion or a depositional hiatus. Therefore, the Gaoyou depression is taken as an example. The Gaoyou depression is the largest hydrocarbon-bearing depression in the Subei Basin, which is a representative rift basin in eastern China. The depression is bounded to the south by the Jiangdu–Wubao fault zone, which includes the Zhen 1–Wu 1, Zhen 2, and Wu 2 faults. Using high-resolution, three-dimensional seismic data, the Zhen 1–Wu 1 fault can be subdivided into four segments based on its G–d profile: the Shaobo, Fanchuan, Liuwushe, and Liulu segments. Growth rates indicate that the Zhen 1–Wu 1 fault and the Zhen 2 and Wu 2 faults developed successively from the Late Cretaceous to the Miocene during rifting of the Gaoyou depression and that development of the Zhen 2 and Wu 2 faults was controlled by the Zhen 1–Wu 1 fault. The four segments of the Zhen 1–Wu 1 fault were linked with each other by the time the Zhen 2 and Wu 2 faults formed in the Late Paleocene. An evolution model of the Gaoyou depression is set up in this study. Integrating the fault activity with previous sedimentological studies, we suggest that the evolution of the Gaoyou depression was controlled by the Jiangdu–Wubao fault zone rather than by a single fault. Successive slip of the Zhen 1–Wu 1 fault and the Zhen 2 and Wu 2 faults caused subsidence and migration of the depocenters. This study presents a case investigation of the effects of boundary faults on rift basins in eastern China.

Description: Historical exploration drilling results provide an opportunity to test the accuracy of geoscience interpretations and technologies by comparing predrill predictions to postdrill outcomes. This includes chance of success, success case recoverable hydrocarbon volumes, and individual reservoir parameters. Analyzing Exxon Mobil’s conventional wildcat predictions versus results from 1994 to 2015 leads to the following insights. (1) Including all wells, risking and volume predictions were objective. Predrill predictions overall differentiated between high- and low-risk prospects and large and small volumes. However, individual wildcat volumes had significant uncertainty, with a lognormal distribution. (2) Prospect parameter predictions were also subject to considerable uncertainty. For example, net-to-gross error was ±20%. (3) Exploration play maturity strongly influenced performance. New play tests had a lower success rate but very large success case volumes. Chance of success increased and prospect success case volumes decreased with play maturity. For very mature plays, success rate decreased again. (4) Trap and seal failure accounted for about half of all dry holes. However, source, maturation, and migration are the most important risks for play tests and extensions. (5) Two seismic technologies were associated with success rate differences. Wildcats drilled based on three-dimensional seismic data had 10%–15% higher success rate than those based on two-dimensional data. Direct hydrocarbon indicator (DHI)–based prospects had about double the success rate of non-DHI prospects and were also overrisked. Although it can be misleading to use previous performance as an indicator of future results, benchmarking geoscience analysis with historical outcomes is useful to audit technical work, identify areas for improvement, and guide future predictions.

Description: Precise dating and correlation of drilled wells through continental successions is challenging for hydrocarbon exploration, especially where preservation and recovery of age-diagnostic fossils is poor. As a complement or alternative to biostratigraphic dating we demonstrate the effectiveness of U–Pb geochronology via laser ablation–inductively coupled plasma–mass spectrometry on detrital zircon from well cuttings. In basins with syndepositional volcanic input, the youngest zircons in a stratigraphic interval can refine and serve as a proxy for the age of deposition. We demonstrate the reliability of this technique when applied to hydrocarbon exploration wells by analyzing drill cuttings through a continental interval of the Galula-1 well in the Rukwa Rift Basin, East African rift system, Tanzania, which previously yielded conflicting biostratigraphy results. The lower third of the well section reveals a late Miocene to Pliocene up-hole younging trend in the youngest detrital zircon populations, which matches new radioisotopic ages on volcanic tuffs from a correlative outcrop section. This is followed by an interval with recycled young zircons, followed by a zircon-free interval, interpreted to correspond to changes in magma composition of the nearby Rungwe volcanic province. This study provides the first radioisotopic age constraints for the Lake Beds in the Rukwa rift and demonstrates that sedimentation in the basin began by 8.7 Ma, critical for burial and thermal history modeling and establishing the probability of a working hydrocarbon system. Correspondence in age and zircon preservation between well and outcrop samples from the same intervals provides strong support for applying U–Pb detrital zircon geochronology to well cuttings, as a rapid, inexpensive approach for hydrocarbon exploration.

Description: The Lawton oil field is located on the Wichita Mountain uplift in southwestern Oklahoma. This study focused on addressing three problems related to the Lawton oil field: (1) What is (are) the source(s) of the oils? (2) Have the oils been subjected to alteration since emplacement? (3) What is the filling history of the field? Eighteen oils and one seep sample were collected and characterized by a variety of geochemical techniques including bulk composition, biomarkers, and stable carbon isotopes to address these questions. Source rocks in this region are absent following the Pennsylvanian Wichita orogeny, but biomarkers and stable isotopic data suggest the source of these oils is probably the Woodford Shale. Despite the fact that all of these oils were recovered from reservoirs at depths between 125 and 1000 ft (38 and 305 m), none of them appeared to be extensively biodegraded as manifested by the abundance of the complete range of n-alkanes. However, the presence of 25-norhopanes in all 18 samples suggests that these oils are mixtures of various proportions of degraded and nondegraded (or slightly degraded) oils. The seep sample and some oils have a relatively high abundance of the 17β(H), 21β(H) 22R bishomohopanoic acid (C 32 ββ 22R hopanoic acid), relative to the 17β(H), 21β(H), 22R homohopane (C 31 ββ 22R hopanoic acid), with the presence of these ββ 22R hopanoic acids suggesting the oils have been degraded aerobically at some point in their history. It was also noted that the concentration of the C 31 ββ 22R hopanoic acid is higher in the shallower reservoirs than in the deeper reservoirs, possibly indicating slightly higher levels of degradation in the shallower reservoirs compared to the deeper reservoirs. A hydrocarbon accumulation model has been proposed for this field based on two main reservoir charging periods. The initial charge of crude oil was biodegraded, probably under anaerobic conditions. The second charging period occurred after (or together with) the uplift of the Wichita Mountains and subsidence of the southern part of the Anadarko Basin, leading to deeper burial of the source rock and production of higher-maturity oil, which subsequently filled the reservoirs containing the degraded oil and may still be recharging these shallow reservoirs today.

Description: The structural history of the Mississippi Canyon, Atwater Valley, western DeSoto, and western Lloyd Ridge protraction areas in the northeastern deep-water Gulf of Mexico is of a basin influenced by complex salt tectonics that controlled the formation of intraslope minibasins and sediment distribution. Large volumes of Middle Jurassic autochthonous salt (Louann Salt) were successively mobilized upward into younger sediments, forming three distinctive allochthonous salt layers: at the top Barremian, at the top Cretaceous, and within the Neogene interval. Four types of Neogene allochthonous salt systems are identified based on the geometry of the allochthonous salt bodies and associated faults, folds, and minibasins: (1) basement-controlled, (2) counterregional, (3) roho, and (4) fold-belt–related salt systems. The allochthonous salt systems are defined based on salt-body geometry, salt-stem geometry, associated fault network, and associated stratigraphic geometries. The distribution of the Neogene allochthonous salt systems is controlled by the original autochthonous salt thickness, the basement configuration, and the regional sediment-loading pattern. The basement-controlled Neogene salt systems are present in the eastern and northern part of the study area where little basinward gravitational gliding occurred. The counterregional and roho allochthonous salt systems are associated with the basinward evacuation of salt in response to extensive sediment loading. The fold-belt–related allochthonous salt systems are present in the southern part of the salt province where extensive shortening remobilized salt into and onto contractional structures. The detailed study of those Neogene allochthonous salt systems is used to build conceptual kinematic models for each style of salt system.

Description: The petroleum geology of the Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and western Lloyd Ridge protraction areas, offshore northern Gulf of Mexico, is controlled by the interaction of salt tectonics and high sedimentation rate during the Neogene and resulted in a complex distribution of reservoirs and traps. We evaluate 87 fields and discoveries: 51 with combined structural/stratigraphic traps (three-way closures), 19 with structural traps (four-way closures), and 17 with stratigraphic traps. Three of these discoveries are in Upper Jurassic eolian reservoirs; the remaining discoveries are in Neogene deep-water reservoirs. The tectono-stratigraphic evolution of the area is analyzed at 11 discrete intervals between 24 Ma and the present. Four stratigraphic external forms—troughs, bowls, wedges, and sheets—are integrated with the structural geology to understand the changing shape of subbasins and minibasins, primarily in a slope setting. This analysis shows how the allochthonous salt systems evolved over time and how salt movement affected sedimentation patterns and subbasin evolution. The study area includes some of the largest fields in the northern deep-water Gulf of Mexico, such as the Thunder Horse field, which produces from an anticlinal (turtle) structure, or the Mars–Ursa and associated fields with greater than 1.5 billion BOE estimated ultimate recovery, which developed with a counterregional allochthonous salt system. The remaining fields have considerably smaller reserves, which are controlled by the area within closure and the number of reservoir intervals. Most of fields in the study area are contained within sheet-shaped or wedge-shaped stratigraphic external forms and have four-way or three-way trapping configurations. These findings indicate the profound effect of mobile salt on the petroleum geology of the region.

Description: This study demonstrates the application of aeromagnetic surveys for locating late 1800s-era oil and gas wells in Hillman State Park. The study area in southwestern Pennsylvania offered several unique challenges to locating legacy wells. Location records for many of Pennsylvania’s legacy wells do not exist. Those that do exist are often incomplete and inaccurate, and old wells were commonly abandoned without effective plugging. Now, unplugged legacy wells may serve as vertical migration pathways for fluids and gas associated with modern oil and gas operations. Wells in Hillman State Park were abandoned in the early 1900s, leaving little evidence of a well site. However, the steel well casing commonly remained at the site. Between 1940 and 1960, 50% of the land area at Hillman State Park was surface mined for coal. The removal of coal overburden also removed the upper well casings in surface-mined areas to the depth of the coal. The wells were then buried under mine spoil during regrading operations. Today, much of Hillman State Park is covered in trees and dense vegetation, and locating wells with ground-level searches is difficult, time consuming, and often futile. The airborne magnetic survey used in this study identified well locations, including buried wells in mined areas, based on the unique magnetic signature of vertical, steel well casing. The results of the aeromagnetic survey were combined with aerial photography, historic maps, and high-resolution topographic data in a geographic information system to refine well locations prior to verification with a ground search.

Description: Surface and airborne gas monitoring programs are becoming an important part of environmental protection in areas favorable for subsurface storage of carbon dioxide. Understanding structural architecture and its effects on the flux of fluids, specifically CO 2 and CH 4 , in the shallow subsurface and atmosphere is helping with designing and implementing next-generation monitoring technologies, including unmanned aerial vehicles (UAVs). An important aspect of this research is using subsurface fracture data to inform the design of flight pathways for UAVs in the Farnsworth oil unit of the Anadarko Basin. The target zone for CO 2 storage and enhanced oil recovery in the Farnsworth oil unit is in the upper Morrow sandstone at subsurface depths greater than 2000 m (6562 ft). Field study reveals that sandstone and chert in the High Plains Aquifer contain numerous joints that provide crucial insight into aquifer architecture and subsurface flow pathways. Properties of more than 1700 joints were measured in the field and in high-resolution satellite images. Two distinctive joint systems interpreted as a conjugate pair were identified in the study area. Joint spacing follows a lognormal statistical scaling rule. These fractures appear to be the product of an east–northeast regional compressive stress and may have a significant effect on flow in the High Plains Aquifer system. Based on the results of this research, design of UAV flight paths should be oblique to fractures in a way that maximizes the likelihood of CO 2 and CH 4 flux of systematic joints and cross joints.

Description: Development of geothermal energy in sedimentary basins is an attractive option given the availability of data from the oil and gas industry. Previous geothermal studies in sedimentary basins have focused on temperatures and petrophysical properties. In this study, the focus is placed on historical reservoir performance. In the Western Canada Sedimentary Basin, estimated temperatures and measured fluid production and injection rates at existing wells are combined to provide a per-well estimate of thermal power production. Nearly 700 of these hypothetical geothermal wells would produce 1 MW of power, and a total of 6 GW could be produced if all wells were converted to geothermal wells. Many of these wells may not be suitable for immediate use because of temperature anomalies resulting from injection of cooler water into target strata. Further research is needed to characterize the magnitude and extent of these anomalies. Geothermal potential should also be considered in the development of oil and gas resources in sedimentary basins.

Description: The stress regime in the Illinois Basin was investigated to assess how the rock column might respond to the injection of fluids, including coproduced formation brines and supercritical CO 2 .This response is a concern because injection practices could increase pore fluid pressure and potentially induce seismicity. Data were collected to determine the magnitude and orientation of a three-component stress field: vertical stress ( S v ) and minimum ( S h ) and maximum ( S H ) horizontal stresses. The S v was evaluated with a six-layer lithostratigraphic column. A two-layer pressure–depth S v model was generated for the central part of the basin, and a single pressure gradient model was constructed for the surrounding region. In the central part of the basin, the S v gradient is 24.9 MPa/km (1.11 psi/ft) to a depth of 2134 m (7000 ft), followed by a gradient of 27.1 MPa/km (1.20 psi/ft) below 2134 m (7000 ft). For the area surrounding the deep basin, the S v gradient was 25.5 MPa/km (1.13 psi/ft). The S h was evaluated from multiple data sources, primarily hydraulic fracture records or extended leak-off tests. The S h gradient calculations ranged from 24.1 to 27.3 MPa/km (1.07 to 1.21 psi/ft). The S h values for the basal Paleozoic clastic units are lower than those for units in the overlying horizons. The S H was based on a critically stressed model yielding values between 40.0 and 82.6 MPa/km (1.77 to 3.65 psi/ft). Stress orientation data for the Illinois Basin were collected from multiple sources. The orientation of S H across the study area is relatively uniform in strike at approximately N60°E. Marked deviations in S H result from localized structural discontinuities.

Description: This study assesses the feasibility of using offshore freshwater for improved oil recovery in passive-margin marine environments. Low-salinity waterflooding (〈5) has recently been shown, on average, to improve oil recovery by 14%. Hydrogeologists estimate that up to 3 x 10 5 km 3 (1.89 x 10 11 bbl) of fresh (〈1) water are sequestered in shallow (〈500 m [1640 ft] depth), permeable, poorly lithified sand, sandstone, and carbonate aquifers along passive margins, within 100 km (60 mi) of the present-day coastline in ocean-water depths up to approximately 50 m (164 ft). The offshore distribution of fresh–brackish water is analyzed for five vertical cross sections from offshore Australia, Suriname, Indonesia, and the United States. The distribution of offshore freshwater is compared with offshore platform locations in three oil-producing marine basins, including the North Sea, the Gulf of Mexico, and the Niger Delta. The continental-shelf cross sections host between 0.8 and 8.6 km 3 of fresh–brackish water (〈5) per kilometer of shoreline (8 x 10 9 to 8.7 x 10 10 bbl/mi of shoreline), most within 20 to 100 km (12 to 60 mi) from the coast in water depths of 10 to 50 m (33 to 164 ft). Because the majority of the offshore oil platforms are located less than 100 km (60 mi) from the shore, these resources could be used for low-salinity recovery. Cross sectional aquifer models of offshore fresh–brackish production indicate that a single, 1000-m (3280-ft)-long horizontal well could produce 19,200 m 3 /day (120,764 bbl/day) from a relatively permeable aquifer (10 –11 to 10 –12 m 2 [10,000 to 1000 md]) overlain by a moderately tight (~10 –15 m 2 [1 md]), confining unit for the typical life span of a well (30 yr).

Description: Wells in the Piceance Basin show anomalous large-magnitude (up to 200 mV), large-interval (〉2000 ft [610 m]) self-potential (SP) log responses in the Mesaverde gas-producing interval that can be best explained by electrokinetic potential resulting from water flow toward producing Mesaverde wells. Water flow is compartmentalized by capillary seals that are formed when gas generated from coals saturates adjacent thinly bedded sandstones and shales. Capillary seals can be identified by shifts in the SP baseline. The first wells drilled in an area with no previous Mesaverde production have very little SP response, as is expected in tight sandstones with single- to double-digit microdarcy permeability. After Mesaverde production is established in a new area, the SP log begins to show stepwise changes to more negative values beginning in the upper Mesaverde and becoming increasingly more negative with increased depth. The magnitude of the change to more negative values increases with time in an area of active Mesaverde production; some of the more recent SP logs have negative deflections of over 200 mV. This type of SP anomaly has not been reported before, and these anomalies can be used to identify large-scale water movement within a reservoir.

Description: Jimusar sag, which lies in the Junggar Basin, is an important tight oil study area in China. However, the properties and origin of the crude oil and the geochemical characteristics of the tight oil from the Lucaogou Formation have not yet been studied. In the present study, 23 crude oil samples from the Lucaogou Formation were collected for analysis, including physical properties (density and viscosity), bulk composition, saturated hydrocarbon gas chromatography–mass spectrometry, and calculation of various biomarker parameters. Source rock evaluation and porosity permeability analysis were applied to the mudstones and siltstones. To analyze the hydrocarbon generation history of the Lucaogou source rocks, one-dimensional basin modeling was performed. The oil-filling history was also investigated by means of basin modeling and microthermometry. Biomarkers of suitable source rocks (total organic carbon content is 〉1%, summation of the free and volatile hydrocarbon and remaining hydrocarbon generative potential is 〉6 mg HC/g rock, and vitrinite reflectance is between 0.7% and 1%) were analyzed for oil–source correlation. The results indicate that low-maturity to mature crude oils originated from the source rocks containing terrigenous organic matter, which were deposited in a saline lake. The source rocks are of mainly type II kerogen. Oil in the lower section of the Lucaogou Formation is relatively dense and viscous and has elevated nonhydrocarbon content. In addition, a higher proportion of bacteria and algae is shown to have contributed to the formation of crude oil in the lower section when compared with the upper section of the Lucaogou Formation. Oil–source correlations demonstrate that not all mudstones within the Lucaogou Formation contribute to oil accumulation. Thin section observation indicates organic macerals surround the grains of some siltstones within the porous and permeable subsections, which proves the siltstones contribute to hydrocarbon generation. Crude oils from the upper and lower sections mainly originate from thin-bedded mudstones interbedded and siltstones within the porous and permeable subsections. The mudstones over or beneath the porous and permeable subsections consist of seals and prevent the vertical movement of oil by capillary forces. Despite being thicker, mudstones between the two porous and permeable subsections make no obvious contribution to the oil accumulation because of their low permeability and distance from the porous and permeable subsections, which is consistent with the principle of near-source charging for tight oil accumulations. Lucaogou oil has been charged twice, once from 235 to 210 Ma and again from 180 to 150 Ma, coinciding with oil generation time.

Description: The Triassic Yanchang Formation contains the main oil-bearing strata in the Ordos Basin, central China. But the sedimentology of the Upper Triassic is still under debate, and flood-generated, hyperpycnal-flow deposits and their implications for unconventional petroleum development have long been overlooked. Our study indicates that hyperpycnites are well developed in the seventh oil member of the Yanchang Formation. They are characterized by couplets of upward-coarsening intervals and upward-fining intervals, separated by microscale erosion surfaces. The origination of hyperpycnal flows was controlled mainly by episodic tectonic movements and the humid climate. The deposits extend from distributary estuaries into the deep lake, have intercalations of dark shales and tuffs, and coexist with debrites and turbidites as a result of the progradation of subaqueous fans. The hyperpycnites have implications for unconventional petroleum reservoirs, because the flows supplied not only large amounts of coarse grains and organic material to the deep-water, fine-grained central lake sediments but also affected the ecosystems, resulting in a higher total organic carbon content in the sediments.