ALBERT

Description: Reliable modeling of meandering fluvial reservoirs is challenging because of the heterogeneity in magnitude and pattern of porosity and permeability related to depositional and diagenetic features. Early mechanical and chemical alterations proceed along different pathways directly related to depositionally governed differences in textural and compositional parameters. In a well-constrained sedimentological framework and with relatively homogeneous conditions of detrital composition, this study aims to determine the effect of depositional fabric on early diagenetic processes and their collective effect on petrophysical properties (pore size distribution, open porosity, and permeability). A high-resolution qualitative and quantitative petrographic analysis is conducted on 22 fine- to very fine–grained sandstones from the main meandering fluvial facies of the channel (center and margin), point bar (lower, middle, and upper), scroll bar, and chute channel of a Triassic outcrop analog. The occurrence of small-scale internal heterogeneity associated with detrital matrix and suspension-settling laminae favors the compaction process and hinders early pore-filling cement precipitation that helps the preservation of primary porosity. Multivariate statistical treatment of data demonstrates that large (〉1 µm) and well-connected primary intergranular pores are the main contributors to permeability in the more heterogeneous samples. The distribution of the finer-grained sediment fraction is strongly facies related as a result of hydraulic sorting. Better understanding of linkages between depositionally predictable features and diagenetically induced heterogeneity may lead to realistic reservoir models and enhanced effectiveness of exploitation and bypassed-oil recovery strategies.

Description: Fractures are the main fluid-flow pathways in tight-oil sandstones, and they have a significant influence on tight-oil distribution, exploration, and development. Cores and image logs are commonly unavailable because of their high costs, so employing conventional logs for fracture detection is imperative for tight-oil sandstones. We compared the fracture-response characteristics of conventional logs based on two data sets, one from 8 cored wells with fracture intensities greater than 1 m –1 (3.3 ft –1 ) and the other from 11 cored wells with fracture intensities less than 0.5 m –1 (1.6 ft –1 ), with a case study of the Upper Triassic Yanchang Formation in southwest Ordos Basin, China. The results indicate that when tight-oil sandstones are more intensely fractured, the caliper log, acoustic log, compensated neutron log, density log, dual induction logs, and laterolog 8 present fracture responses to some extent. However, it is difficult to make a distinction between fractured and nonfractured zones using conventional logs in sandstones with smaller fracture intensities. The fracture-response intensities of conventional logs are weak, and they are influenced by fracture abundance, fracture occurrence, fracture scale, and mineral-filling degree. Moreover, lithology, fluids, and rock physical properties can cause fracturelike responses. Hence, some ambiguity exists when using conventional logs to directly identify fractures. Accompanying fracture-sensitive conventional logs with some methods to enhance fracture-response intensity and eliminate nonfracture influence could enable fracture identification in tight-oil sandstones.

Description: Accurate definition of structural style in subsurface interpretation is critically important for understanding the deformation history of fold-and-thrust belts, as well as assessing the petroleum prospectivity of structural traps. Using two- and three-dimensional seismic reflection surveys, well data, field mapping, forward models, and balanced cross sections, we describe the structural styles across the actively deforming southern Junggar fold-and-thrust belt in northwestern China, a basin undergoing petroleum exploration and development operations. Subsurface interpretations indicate several folds in the basin overlie Jurassic normal faults that were tectonically inverted in the Late Jurassic to Early Cretaceous. Following inversion, multiple detachment levels propagated northward from the Tian Shan and formed a series of imbricated fault-related folds. The most prominent fold trend in southern Junggar consists of the Tugulu, Manas, and Huoerguosi anticlines, which trap hydrocarbons in clastic Eocene reservoirs. These structures exhibit complex internal geometries, with coeval forethrusts and backthrusts forming imbricated structural wedges. In the latest stages of deformation, and continuing at present, the uppermost thrust sheet, the Southern Junggar Thrust (SJT), truncated the backlimbs of these structural traps, implying the SJT is a tectonically active, out-of-sequence thrust. From these interpretations, we present a model for how the southern Junggar fold-and-thrust belt developed from Jurassic to present. Moreover, we detail how fold growth, fault activity, and structural style affected charge histories, trap formation, and reservoir compartmentalization. Our results have direct implications for assessment of the southern Junggar petroleum system as well as other complex fold-and-thrust belts.

Description: Distinguishing axial and lateral sedimentary systems in rift basins is crucial for predicting reservoir distribution and quality, particularly where synrift strata are interrupted by mass transport complexes (MTCs). Upper Jurassic deep-marine synrift successions in the central North Sea have been studied to assess the temporal and spatial relationships of sediments and controls on reservoir quality. In the Late Jurassic, the central graben experienced erosion at rift margins, whereas adjacent grabens were starved and underfilled with marine sediments, supplied by axial and transverse systems. This study focused on sediments adjacent to a major intrabasinal high, the Josephine ridge. Data included seismic, wireline logs from 16 wells, and biostratigraphic and sedimentological analysis of 144 m (472 ft) of core. Synrift strata are dominated by mudstones but include MTCs interbedded with coarse sandstones at the rift margin and fine-grained turbidite sandstones in basinal depocenters. Petrographic and heavy mineral data indicate different provenance between MTCs and basinal turbidites. Turbidites correlate with periods of lowered relative sea level, during the initial rift phase, and record axial sediment supply. The composition of the MTCs corresponds to in situ strata on the adjacent Jade and Judy horsts. The distribution of MTCs implies formation by crestal collapse horsts during the rift climax and represents a transverse system, with no genetic relationship to axial turbidites. In starved deep-marine basins, fine-grained, well-sorted axial systems may provide the most extensive reservoirs. Transverse systems derived from isolated horsts are typically coarse-grained, poorly sorted, and spatially restricted, being unlikely to provide significant reservoir material.

Description: Shale oil and gas have been discovered in the lacustrine organic-rich Zhangjiatan Shale of the Upper Triassic Yanchang Formation, Ordos Basin, China. Core observations indicate abundant silty laminae in the producing shales. This study documents the stratigraphic distribution of silty laminae and their relationship with interlaminated clay laminae. The type, structure, and characteristics of pores and mineral composition of silty laminae were observed and analyzed through thin section and scanning electron microscopy, X-ray diffraction, low-pressure $${\mathrm{CO}}_{2}$$ and $${\mathrm{N}}_{2}$$ adsorption, mercury porosimetry, and helium pycnometry. Results from silty laminae are compared with those of clayey laminae. The frequency and thickness of silty laminae vary over a wide range. The thickness ranges from 0.2 to 4 mm and is 1.5 mm on average; the frequency ranges from 4 to 32 laminae/m and is 23 laminae/m on average. The thickness percentage of silty laminae in the measured segments ranges from 6% to 17%. Silty laminae consist of quartz, feldspar, mixed-layer montmorillonite, and chlorite. In comparison to clayey laminae, non-clay detrital grains are larger, quartz and feldspar are more common, and clay minerals are less abundant. Pores in silty laminae are primary interparticle, dissolutional, intercrystalline, and microfracture types. Mesopores (2–50 nm in diameter) and macropores (50 nm–1 μm) are common, whereas, micropores $$( 〈 2\hbox{ \hspace{0.17em}\hspace{0.17em} }\mathrm{nm})$$ are rare; the distribution of pore diameters is multimodal. However, microscopic pores with a diameter commonly smaller than 100 nm are common in clayey laminae. Thus, pore volume and surface area of micropores in silty laminae are less than those in the adjacent clayey laminae, and vice versa for meso- and macropores. The porosity of shales increases with the proportion of silty laminae in the shales. The silty laminae provide the storage space and flow conduit for oil and gas, and they play a significant role in the migration, accumulation, occurrence, and amount of gas in the shales.

Description: The Pleistocene Saturnia travertine (central Italy) represents a possible analog of the pre-salt continental carbonate reservoirs discovered in the Santos and other basins in the South Atlantic margin of Brazil. Two subhorizontal travertine tabular bodies, several tens of meters thick and extending over an area of $$15\hbox{ \hspace{0.17em}\hspace{0.17em} }{\mathrm{km}}^{2}$$ ( $$5.8\hbox{ \hspace{0.17em}\hspace{0.17em} }{\mathrm{mi}}^{2}$$ ), have been studied in two quarries. Facies variations and associated petrophysical properties were reconstructed applying a multidisciplinary approach. The Saturnia travertine, formed from a warm water spring, is composed of various stacked carbonate banks, separated by subaerial erosive phases and paleosols. The lacustrine tabular bodies, terraces, and sills are made of crystalline crust, shrub, pisoid, paper-thin raft, coated bubble, reed, and lithoclast-breccia facies. The $$\delta ^{13}\mathrm{C}$$ (from +4 to +8) supports an interpreted $${\mathrm{CO}}_{2}$$ volcanic mantle source, whereas, the $$\delta ^{18}\mathrm{O}$$ (from –9 to –5) is in agreement with warm meteoric waters. The $$^{87}\mathrm{Sr}/^{86}\mathrm{Sr}$$ ratio isotopic signature indicates a carbonate from dissolution of deep-seated carbonates. The facies reservoir properties were studied via porosity and permeability analysis of plugs, three-dimensional x-ray computer tomography, as well as image analysis on microscale under thin section and macroscale on large rock slabs to define various porosity indices. A strong heterogeneity of the petrophysical properties and variable connectivity were observed (porosity from 4% to 30% and permeability up to hundreds of md), but no compartmentalization of the carbonate bodies is present.

Description: The shale beds of the Khabour and Akkas Formations (Ordovician–Silurian) in Akkas field of western Iraq have been studied to determine their hydrocarbon-generation potential. The total organic carbon (TOC) values of the Khabour Formation were generally low and associated with low S2 and hydrogen index (HI) values indicating that this formation is not a hydrocarbon source, although this could reflect advanced thermal maturity. The gray-green shales of the upper part of the Akkas Formation also have low TOC and S2 values. On the other hand, the TOC, S2, and HI values of the black shales of the lower part of the Akkas Formation were high. The values indicate that the gray-green shales of the upper part of the Akkas Formation are not petroleum sources, whereas the black shales of the lower part can be regarded as potential hydrocarbon source rocks. Organic petrology studies reveal that marine amorphous organic matter is predominant, and no significant differences were observed between Khabour and Akkas samples in terms of organic-matter type. Molecular geochemical data also indicate that the kerogen of the two formations is of similar origin. The normal alkane distribution is unimodal, with a maximum at $${\mathrm{C}}_{16}\mbox{--}{\mathrm{C}}_{18}$$ , indicating marine algal organic matter. Rock-Eval $${T}_{\mathrm{max}}$$ and biomarker data indicate that the organic matter of the black shales of the lower part of the Akkas Formation is early mature, whereas the Khabour Formation is highly mature in the Akkas field.

Description: Significant amounts ( $$ 〉 150\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}/\mathrm{day}/\mathrm{well}$$ ) of water are currently being extracted from coalbed methane (CBM) wells in Permian–Carboniferous coal in the Liulin area of the eastern Ordos basin, China. Waters coproduced with CBM have common chemical characteristics that can be an important exploration tool because they relate to the coal depositional environment and hydrodynamic maturation of groundwater and can be used to guide CBM development strategies. The CBM production targets of the No. 3 and 4 coal seams from sandstone in the Shanxi Formation and No. 8, 9, and 10 coal seams in the karst of the Taiyuan Formation were deposited in fluvial-deltaic and epicontinental-sea environments, respectively. This paper combines CBM geology, hydrogeology, CBM recovery, and laboratory data to define mechanisms of CBM preservation including the important influence of groundwater. Relevant indices include fluid inclusions as an indicator of the hydraulic connection between the coal seam reservoir and the overlaying strata and the ensemble characteristics of total dissolved solids (TDS) contents of water, water production rates, and reservoir temperatures as an indication of the current hydraulic connection. The TDS contents of waters from the No. 3 and 4 and No. 9 and 10 coal seams are double those from the subjacent karst No. 8 coal seam, indicating the important control of fast flow in karst. Low-salinity fluid inclusions from the roof of the subjacent-karst No. 8 coal seam also indicate an enduring hydraulic connection with overlaying strata during its burial history. Relatively low current temperatures in the No. 8 (subjacent-karst) coal seam also infer a strong hydraulic connection and active flow regime. Deuterium concentrations are elevated in the mudstone-bounded No. 9 and 10 coal seams, further confirming low rates of fluid transmission. The gas contents of coal seams from the Taiyuan Formation are higher than those from the sandstone-bounded coal seams in Shanxi Formation, also correlating with low rates of water transmission and low permeability. Conceptual models for these fluvial-deltaic and epicontinental-sea environments that are consistent with geology, gas content, and gas and water production rate histories are of gas-pressure sealing for the Shanxi Formation and hydrostatic-pressure sealing for the Taiyuan Formation. These results confirm the important controls of hydrogeological conditions on the preservation of CBM and the utility of hydrogeological indicators in prospecting for CBM.

Description: Whereas the vast majority of discovered hydrocarbon reserves in Iraq reside in Cretaceous and Cenozoic reservoirs, numerous oil and gas fields have been discovered recently in deeper Jurassic and Triassic reservoirs in the Kurdistan region of Iraq. This study presents a Middle–Upper Jurassic thermal maturity map for the Kurdistan region of Iraq and demonstrates that regional first-order trends in Jurassic source rock maturity show a close correlation to the spatial distribution of oil gravities within the overlying Jurassic (and Cretaceous) reservoirs. This distribution is consistent with compartmentalization of the active source rock kitchens due to Zagros folding, resulting in relatively short-distance migration and charge of the anticlinal structures from the adjacent synclinal lows. The thermal maturity map confirms relatively low maturity over the Mosul high, where the Cretaceous and Cenozoic section overlying the source rock interval is relatively thin, and increasing maturity to the southeast as the thickness of the Cenozoic foredeep sediments increases toward the depocenter located in the southeastern Iraqi Zagros and the adjacent Iranian Zagros. The correlative trend in oil gravities is exemplified by the recent Jurassic discoveries: low to medium gravity oils (14–27° API) in Shaikan and Atrush to the northwest, light oil (39–47° API) in Mirawa and Bina Bawi, and gas condensate (55° API) in Miran West to the southeast. Understanding thermal maturity patterns and hydrocarbon fluid-type distributions will help to guide risk assessment for remaining prospectivity and future exploration drilling within the Kurdistan region of Iraq.

Description: The northern Flinders Ranges and eastern Willouran Ranges, South Australia, expose Neoproterozoic salt diapirs, salt sheets, and associated growth strata that provide a natural laboratory for testing and refining models of allochthonous salt initiation and emplacement. The diapiric Callanna Group (~850–800 Ma) comprises a lithologically diverse assemblage of brecciated rocks that were originally interbedded with evaporites that are now absent. Using stereonet analysis to derive three-dimensional information from two-dimensional outcrops of stratal geometries flanking salt diapirs and beneath salt sheets, we evaluate 10 examples of the transition from steep diapirs to salt sheets, 3 of ramp-to-flat geometries, and 2 of flat-to-ramp transitions. Stratal geometries adjacent to feeder diapirs range from a minibasin-scale megaflap to halokinetic drape folds to high-angle truncations and appear to have no relationship to subsequent allochthonous salt development. In all cases, the transition from steep diapirs to salt sheets is abrupt and involved piston-like breakthrough of thin roof strata, which permitted salt to flow laterally. We suggest two models to explain the transition from steep diapirs to subhorizontal salt: (1) salt-top breakout, where salt rise occurs inboard of the salt flank, thereby preserving part of the roof strata beneath the sheet; and (2) salt-edge breakout, where rise occurs at the edge of the diapir with no roof preservation. Lateral emplacement of salt sheets is dependent on the interplay between the rate of salt supply to the front of the sheet and the sediment-accumulation rate. When the ratio of salt-supply rate to sediment-accumulation rate is high to moderate, thrust advance produces base-salt flats and truncation ramps, respectively. Halokinetic folds are absent because the thrust emerges at the base of the sea-floor scarp and mass-transport complexes are rare as a result of relatively low scarp relief. If the ratio is low, pinned inflation leads to drape folding of the top salt and cover into a fold ramp, with occasional slumping of the sheet and its roof and further breakout on thrust or reverse faults. In the shallow-water depositional environments of South Australia, lateral emplacement of salt sheets occurred through some combination of thrust advance, extrusive advance, and open-toed advance, with no evidence for subsalt thrust imbricates, shear zones, or continuous rubble zones. In deep-water environments, such as the northern Gulf of Mexico, thrust imbricates and rubble zones, which represent slumped carapace, are more common. The presence of slumped carapace is caused primarily by higher topographic relief related to thicker hemipelagic roofs, a lack of dissolution, and gravity-driven transport of overburden strata to the toes of large canopies.

Description: This paper examines the discovery process in terms of changing exploration paradigms and describes a field discovered because of this change in mindset. Prior to the Umiak discovery all wells in the Mackenzie Delta had been drilled on structural highs. Reevaluation of two 30-yr-old dry holes along with existing two-dimensional (2-D) seismic data resulted in discovery of the Umiak gas field. This reappraisal led to recognition that a stratigraphic trap might exist between these two wells drilled in the early 1970s. The Kilagmiotak M-16 well contained 290 m (951 ft) of porous sandstone in the Eocene Taglu Formation, whereas the Umiak J-37 well, up dip and 11 km (6.8 mi) to the west, had no sandstone in the same interval. Examination of 2-D seismic lines found evidence of an updip sandstone pinchout beneath an angular unconformity on a tilted fault block. Strata in the tilted fault block below the unconformity contain strong amplitudes and flat spots. Interpretation of a subsequent three-dimensional (3-D) survey supported the play. A partnership of Alberta Energy Company (operator, now Encana), Anadarko, and Gulf Canada (now ConocoPhillips Canada) drilled the Umiak N-16 discovery well during 2004. Gas and some oil was found in gently dipping Eocene Taglu shoreface and delta front sandstones, and within gently folded foreset beds of the Eocene Richards Formation above a mid-Eocene unconformity. The Umiak N-05 appraisal well drilled a year later confirmed the discovery. Together these two wells delineate the fourth largest onshore gas accumulation on the Mackenzie Delta.

Description: The Upper Cretaceous Tuscaloosa marine shale (TMS) is an oil play across central Louisiana and southwest Mississippi. The lower TMS is characterized by relatively high log resistivity (〉5 ohm-m) compared to the upper part, and this elevated resistivity zone (ERZ) has become the primary target zone. This study is to investigate the cause of variation in log resistivity based on the data of petrography, mineralogy, and organic matter property and porosity. The results suggest that log resistivity is not controlled by mineralogy or porosity; rather, it is associated with oil generation during organic matter maturation. Total organic carbon (TOC) content, Rock-Eval free hydrocarbon yield (S1), and hydrogen index (HI) in the studied core increase with depth. Porosity within organic matter (OM), measured by field-emission scanning electron microscopy (FE-SEM), is also higher within the ERZ. The correlated variations among TOC content, S1 values, OM porosity, and log resistivity suggest that the higher log resistivity resulted from in situ oil generation and that the OM pores were generated during oil generation. Thermal maturity varies little in the core; whereas the downward-increasing HI indicates an increasing abundance of oil-prone type II kerogen. Higher OM porosity appears to be related to the greater proportion of type II kerogen in the ERZ. The data set demonstrates that higher contents of TOC and oil-prone kerogen are the combined factors for higher oil generation, therefore, higher log resistivity in the ERZ. The study provides a quantitative relationship between OM porosity and oil generation.

Description: The number of Marcellus Shale gas wells drilled in the Appalachian basin has increased rapidly over the past decade, leading to increased interest in the highly saline water produced with the natural gas which must be recycled, treated, or injected into deep disposal wells. New geochemical and isotopic analyses of produced water for 3 time-series and 13 grab samples from Marcellus Shale gas wells in southwest and north central Pennsylvania (PA) are used to address the origin of the water and solutes produced over the long term (〉12 months). The question of whether the produced water originated within the Marcellus Shale, or whether it may have been drawn from adjacent reservoirs via fractures is addressed using measurements of $$^{228}\mathrm{Ra}/^{226}\mathrm{Ra}$$ and $$^{226}\mathrm{Ra}$$ activity. These parameters indicate that the water originated in the Marcellus Shale, and can be more broadly used to trace water of Marcellus Shale origin. During the first 1–2 weeks of production, rapid increases in salinity and positive shifts in $${\delta }^{18}\mathrm{O}$$ values were observed in the produced water, followed by more gradual changes until a compositional plateau was reached within approximately 1 yr. The $${\delta }^{18}\mathrm{O}$$ values and relationships between Na, Cl, and Br provide evidence that the water produced after compositional stabilization is natural formation water, the salinity for which originated primarily from evaporatively concentrated paleoseawater. The rapid transition from injected water to chemically and isotopically distinct water while $$ 〈 50\%$$ of the injected water volume had been recovered, supports the hypothesis that significant volumes of injected water were removed from circulation by imbibition.

Description: One of the challenges confronting carbon dioxide capture and sequestration (CCS) in geologic media over extended periods of time is determining the caprock sealing capacity. If the pressure of supercritical carbon dioxide $$({\mathrm{scCO}}_{2})$$ injected in the repository overcomes the caprock sealing capacity, leaking of $${\mathrm{scCO}}_{2}$$ may enter other porous formations, compromising the storage formation, or even may go back to the atmosphere, and thus the process of sequestration becomes futile. Carbon dioxide sealing capacity is controlled by two groups of parameters: (1)  texture (e.g., the pore-throat size, distribution, geometry, and sorting; median grain size, porosity, degree of bioturbation, specific surface area, preferred orientation of matrix clay minerals, orientation, and aspect of ratio of organic particles) and (2)  composition (mineralogical content, proportion of soft, deformable mineral grains to rigid grains, organic matter content, carbonate content, silt content, cementation, ductility, compaction, and ash content). The primary goal of this study was to investigate several parameters listed above and to estimate their respective contributions to sealing capacity to better understand its role in shale and carbonates. To assess the effect of textural and compositional properties on $${\mathrm{scCO}}_{2}$$ maximum retention column height, we collected 30 representative core samples from caprock formations in three counties (Cimarron, Texas, and Beaver) in the Oklahoma Panhandle. The study area was chosen because it hosts three depleted gas fields with a storage capacity of more than 35 million bbl and is situated at a crossroad leading to some significant $${\mathrm{CO}}_{2}$$ stationary sources from North Texas, South Kansas, and northern Oklahoma. We used mercury injection porosimetry, scanning electron microscopy (SEM), Sedigraph energy dispersive spectra (EDS), x-ray diffraction (XRD), Brunauer–Emmett–Teller-specific surface area, and total organic carbon (TOC) measurements to assess textural and compositional properties of collected samples. The range of $${\mathrm{scCO}}_{2}$$ column height for the samples used in this study is between 0.2 and 1358 m (0.66 and 4455 ft). The average $${\mathrm{scCO}}_{2}$$ column height is 351 m (1152 ft). The depth interval approximately 1400 m (4593 ft) could reach relatively high values of $${\mathrm{scCO}}_{2}$$ column height, up to 1200 m (3937 ft). The above-mentioned interval is composed of mainly Cherokee and Morrowan Formations (shale seals). Principal component analysis (PCA) was carried out to infer the possible relationships between textural and compositional parameters. Generally, composition of our samples (shales vs. carbonates and sandstones) indicates a relatively stronger control on caprock sealing capacity, although individual mineral makeup of shale samples seems not correlated with $${\mathrm{scCO}}_{2}$$ retention column heights. In the same time, many textural parameters play a significant role in determining the sealing capacity of carbonate caprocks.

Description: Using a seismic database from the Qiongdongnan Basin in the South China Sea, this study demonstrates that shelf-edge trajectories and stratal stacking patterns are reliable, but understated, predictors of deep-water sedimentation styles and volumes of deep-water sand deposits, assisting greatly in locating sand-rich environments and in developing a more predictive and dynamic stratigraphy. Three main types of shelf-edge trajectories and their associated stratal stacking patterns were recognized: (1) flat to slightly falling trajectories with negative trajectory angles ( $${T}_{\mathrm{se}}$$ ) (–2° to 0°) and negative shelf-edge aggradation to progradation ratios ( $$\mathrm{d}y/\mathrm{d}x$$ ) (–0.04 to 0) and associated progradational and downstepping stacking patterns with low clinoform relief ( $${R}_{\mathrm{c}}$$ ) (150–550 m [492–1804 ft]) and negative differential sedimentation on the shelf and basin ( $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ ) (–0.6 to 0); (2) slightly rising trajectories with moderate $${T}_{\mathrm{se}}$$ (0°–2°) and medium $$\mathrm{d}y/\mathrm{d}x$$ (0–0.04), and associated progradational and aggradational stacking patterns with intermediate $${R}_{\mathrm{c}}$$ (250–400 m [820–1312 ft]) and intermediate $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ (0–0.6); and (3) steeply rising trajectories with high $${T}_{\mathrm{se}}$$ (2°–6°) and high $$\mathrm{d}y/\mathrm{d}x$$ (0.04–0.10) and associated dominantly aggradational stacking patterns with high $${R}_{\mathrm{c}}$$ (350–650 m [1148–2132 ft]) and high $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ (1–2). Each trajectory regime represents a specific stratal stacking patterns, providing new tools to define a model-independent methodology for sequence stratigraphy. Flat to slightly falling shelf-edge trajectories and progradational and downstepping stacking patterns are empirically related to large-scale, sand-rich gravity flows and associated bigger and thicker sand-rich submarine fan systems. Slightly rising shelf-edge trajectories and progradational and aggradational stacking patterns are associated with mixed sand/mud gravity flows and moderate-scale slope-sand deposits. Steeply rising shelf-edge trajectories and dominantly aggradational stacking patterns are fronted by large-scale mass-wasting processes and associated areally extensive mass-transport systems. Therefore, given a constant sediment supply, then $${T}_{\mathrm{se}}$$ , $$\mathrm{d}y/\mathrm{d}x$$ , $${R}_{\mathrm{c}}$$ , and $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ are all proportional to intensity of mass-wasting processes and to amounts of mass-transport deposits, and are inversely proportional to the intensity of sand-rich gravity flows and to amounts of deep-water sandstone. These relationships can be employed to relate quantitative characteristics of shelf-edge trajectories and stratal stacking patterns to deep-water sedimentation styles.

Description: Cementation of sandstone by minor late barite and sphalerite is widespread in the Scotian Basin at burial depths 〉2 km (〉1 mi), providing information on fluid flow in the basin. The texture and geochemistry of these minerals were analyzed by scanning electron microscopy and electron microprobe on samples from conventional core. Barite and sphalerite postdate silica and carbonate cementation, occurring in veins or occupying secondary porosity. They occur with diagenetic chlorite, kaolinite, pyrite, titania minerals, kutnohorite, and Mn-siderite. This study relates barite and sphalerite to the salt-tectonic evolution of the basin, based on seismic interpretation, and the thermal history of the basin, based on fluid inclusion studies. Barite is readily transported in basinal fluids 〉100°C (212°F), yet is consistently a very late diagenetic mineral. This implies that the source of Ba is because of the late diagenetic breakdown of K-feldspars at 2–3 km (1–2 mi) depth, which is confirmed by covariation of Ba and Rb in sandstones. Sulfur isotope data suggest that the $${\mathrm{SO}}_{4}^{2+}$$ was derived from Argo Formation evaporites that include 1%–7% anhydrite. Sphalerite is mobile only in saline formation water 〉140°C (〉284°F) and requires long-distance transport through sandstones with Zn-rich Fe-Ti oxides. Active detachment faults on salt welds provide potential pathways and a source of salt for migrating formation water. The particularities of source and transport of both barite and sphalerite allow the pathways of basinal fluids and their relationship to active salt tectonics to be inferred, providing indirect dating of the later stages of diagenetic paragenesis corresponding to times of hydrocarbon charge.

Description: Net fluid production and pressure data were gathered to estimate the amount of $${\mathrm{CO}}_{2}$$ storage space available and the potential for additional oil recovery using $${\mathrm{CO}}_{2}$$ -enhanced oil recovery (EOR) in the Phacoides sandstone, McKittrick oilfield, San Joaquin Valley, California. The Phacoides reservoir has produced 61.5 million reservoir barrels of fluid, a volume equivalent to the subsurface capacity of 9.8 million metric tons of $${\mathrm{CO}}_{2}$$ . Reservoir pressure changes with fluid production suggest that injecting 1 million metric tons of $${\mathrm{CO}}_{2}$$ may raise reservoir pressures by 2 MPa (255 psi). We assume that the sealing capacity of the reservoir for $${\mathrm{CO}}_{2}$$ injection is equivalent to the conditions controlling the original hydrocarbon accumulation. If injection pressures exceed this limit, the $${\mathrm{CO}}_{2}$$ could leak through the caprock, from aging wellbores or along faults in the reservoir. Faulting has compartmentalized the reservoir into six major blocks with varying degrees of hydraulic communication. Injection wells will be required within each sealed fault block, resulting in additional costs for implementing a carbon capture and sequestration (CCS) project. Through $${\mathrm{CO}}_{2}$$ -EOR, an additional 17 million bbl of oil may be recoverable, thereby offsetting the cost of carbon storage. This is equivalent to 1.4 million metric tons of additional storage space. However, assuming that none of the carbon is captured, combustion of this additional oil will add approximately 7 million metric tons of $${\mathrm{CO}}_{2}$$ to the atmosphere, negating the available storage space in the reservoir and resulting in a net carbon gain to the atmosphere of 700,000 metric tons.

Description: Ore grade is one of the primary variables controlling the economic recovery of bitumen from oil sands reservoirs, hence there is a need for fast and reliable quantification of total bitumen content (TBC). This is typically achieved through laboratory-based Dean-Stark analyses of drill core samples. However, this method is time and labor intensive and destructive to the core sample. Hyperspectral imaging is a remote sensing technique that can be defined as reflectance spectroscopy with a spatial context, where high-resolution digital imagery (~1 mm/pixel [0.04 in./pixel]) is acquired and reflectance measurements are collected in each pixel of the image. This study compares two hyperspectral models for the determination of TBC from imagery of both fresh and dry core samples. For three out of four suites of fresh core, TBC was predicted within ±1.5 wt. % of the Dean-Stark data with both spectral models achieving correlations of $${R}^{2} 〉 0.97$$ . For a fourth fresh core and the dry core, larger margins of error were found because of some instances of overestimation. Surface roughness because of uneven oil distribution and small-scale fracturing is a potential source of error in some of the spectral TBC results, particularly for the dry core. Producing results within minutes with the additional benefit of being nondestructive to the core sample, hyperspectral imaging shows great potential to become a viable alternative method for bitumen content determination in oil sands.

Description: Many $${\mathrm{CO}}_{2}$$ -rich (up to 97% by volume) natural gas pools have been found in the continental margin basins of the northern South China Sea. By combining the geochemical data from 53 samples with their geologic backgrounds, this study investigated the origins and accumulation mechanism of $${\mathrm{CO}}_{2}$$ , and discussed the role of $${\mathrm{CO}}_{2}$$ in driving oil as it charged the reservoirs. The results reveal that the $${\mathrm{CO}}_{2}$$ gases in the Yinggehai basin originate mainly from the thermal decomposition of both Miocene calcareous shales and Paleozoic carbonates, and that $${\mathrm{CO}}_{2}$$ from mantle degassing is only a minor contributor. The $${\mathrm{CO}}_{2}$$ accumulations in the Yinggehai basin are mainly controlled by diapiric faults and episodic thermal fluid movements. The $${\mathrm{CO}}_{2}$$ gases in the eastern Qiongdongnan and western Pearl River Mouth basins are mainly related to magmatic or mantle degassing, and the volatiles from magmatic degassing during the igneous intrusion stage are the most likely major source of $${\mathrm{CO}}_{2}$$ in these reservoirs, with basement faults providing pathways for upward migration of $${\mathrm{CO}}_{2}$$ -rich mantle fluids. Natural displacements of oil by $${\mathrm{CO}}_{2}$$ appear to be common in the eastern Qiongdongnan and western Pearl River Mouth basins. The $${\mathrm{CO}}_{2}$$ -flooded oil or gas reservoirs have two common features that the present $${\mathrm{CO}}_{2}$$ gas pools or oil-bearing structures have residual oils representing prior charge, and are close to the basement faults that provide pathways along which the mantle-derived $${\mathrm{CO}}_{2}$$ -rich gas was migrated. The oils from prior hydrocarbon reservoirs have been naturally driven out by $${\mathrm{CO}}_{2}$$ to form secondary oil reservoirs in the eastern Qiongdongnan and western Pearl River Mouth basins. Therefore, a full understanding of the origin and distribution of $${\mathrm{CO}}_{2}$$ cannot just be used to trace hydrocarbon migration pathways, but also provide useful information for risk assessment prior to drilling.

Description: It has been suggested by some that methane contamination of water wells is the main negative consequence of the development of natural gas resources. Concurrently, speculation in academic white papers and in the press that methane may be toxic has resulted in public concern. In northern Pennsylvania, methane being released from groundwater and entering homes (so-called stray gas) has become a focus of this concern. This phenomenon was widespread decades before shale gas development was initiated. This paper reviews the available literature on the safety and health hazards associated with natural gas. It concludes that the risks to homeowners are highest from flash fires occurring in methane oxygen gas clouds at relatively low methane concentrations collecting in poorly ventilated, confined areas of houses such as basements. Such risks can be mitigated effectively and in most cases at minimal cost. Methane can result in death from hypoxia (lack of oxygen) but only at methane levels in the air of more than 60%, which are unlikely to develop except under exceptional circumstances. There is no evidence that low to moderate levels of exposure to methane in air have any toxic effect on humans, and evidence for such effects at very high levels (already fatal because of hypoxia) is equivocal. It seems likely that methane at concentrations at least as high as 2.5% may well have positive health benefits for some diseases.

Description: Micropores can constitute up to 100% of the total porosity within carbonate-hosted hydrocarbon reservoirs, usually existing within micritic fabrics. Here, three-dimensional computational representations of end-point micritic fabrics are produced using a flexible, object-based algorithm to further our understanding of the contribution that micropores make to flow. By methodically altering model parameters, we explore the state space of microporous carbonates, quantifying single and multiphase flow using lattice-Boltzmann and network models. In purely micritic fabrics, average pore radius (ranging from 0.26 to 0.44 μm) was found to have a positive correlation with single-phase permeability (1.7 to 2.7 md, respectively). Similarly, increasing average pore size resulted in decreasing residual oil saturation under both water-wet and 50% fractionally oil-wet states. Permeability was found to increase by an order of magnitude (from 0.6 to 7.5 md) within fabrics of varying total matrix porosity (from 18% to 35%) because of increasing pore size (0.37 to 0.56 μm, respectively), but minimal effect on multiphase flow was observed. Increased pore size due to micrite rounding notably increases permeability in comparison with original rhombic fabrics with the same porosity, but multiphase flow properties are unaffected. Finally, when moldic mesopores are added to a micritic matrix, they impact flow when directly connected. Otherwise, micropores control single-phase permeability magnitude. Importantly, recovery is dependent on both wetting scenario and pore-network homogeneity: under water-wet imbibition, increasing proportions of microporosity yield lower residual oil saturations. Together, these results quantify the importance of micropores in contributing to, or controlling, overall flow and sweep characteristics in such fabrics.

Description: Coal rank reflects the temperature of coalification, with higher rank coal forming at higher temperatures. If the temperature of coalification depended only on the Earth’s geothermal gradient, then the maximum rank of coal in a sedimentary basin should be directly proportional to the thickness of strata above the coal. This association does not occur in the Illinois Basin, a continental-interior basin in the midwestern United States, where the overall coal rank observed is higher than can be explained by past burial depth alone. Recognition of this anomaly has led many authors to suggest that hot groundwater flowing from south to north, during a Paleozoic basin-scale groundwater-migration event, increased coal rank. We analyzed vitrinite reflectance $$({R}_{\mathrm{o}})$$ , a measure of rank, as a function of depth in wells across the basin to determine how paleogeotherms, representing variation in temperature with depth, change with location. Our results show that the basin can be divided into three zones: (1) in the southern zone, the paleogeotherm varies irregularly with depth in strata above the sub-Absaroka unconformity (the contact separating Pennsylvanian and Mississippian strata); (2) in the central zone, the paleogeotherm displays a distinct inflection at the unconformity, for the rate of increase in $${R}_{\mathrm{o}}$$ with depth is greater above the unconformity than below the unconformity; and (3) the observed inflection in the paleogeotherm dies out northward, until, in the northern zone, the paleogeotherm has the same slope both above and below the unconformity. We propose that the inflection in the paleogeotherm of the central zone indicates that the hot groundwater responsible for causing an increase in coal rank flowed through a high-permeability zone just below the sub-Absaroka unconformity. This flow, which advected heat into Pennsylvanian strata above, cooled as it moved northward, so it did not influence the paleogeotherm in the northern zone. Preliminary studies of vein paragenesis, stable-isotope composition, and fluid-inclusions, as well as computer modeling of flow-related heat advection, support this proposal.

Description: This multidisciplinary study evaluates the structural and hydrogeologic evolution of Cretaceous-age reservoirs in the Putumayo basin, Colombia. We focused on the Eastern Cordillera fold-thrust belt along the southern Garzón Massif. Many important hydrocarbon accumulations occurred regionally along the proximal foreland basin and frontal fold-thrust belt defining the eastern margin of the northern Andes. To understand why recent Putumayo basin and adjacent thrust belt exploration has resulted in a wide range of oil quality and limited economic discoveries, we reconstructed the structural evolution, timing of oil migration, and timing of groundwater infiltration by (1) assessing regional trends in formation water, oil, and reservoir properties; (2) quantifying the timing of hydrocarbon generation and migration relative to trap formation using (a) two-dimensional (2-D) and three-dimensional seismic data to define and constrain a restorable balanced cross section from the Upper Magdalena Valley to the Putumayo foreland and (b) coupled one-dimensional thermal basin modeling; (3) evaluating the potential roles of Mesozoic extensional faulting and Paleogene shortening in the generation and preservation of structural traps; and (4) assessing groundwater influx from the modern foothills into the reservoir using a 2-D numerical groundwater flow model. We suggest that four-way closure is limited in the study area, where most foreland-verging structures create three-way fault closures that do not effectively trap light hydrocarbons. In addition, east-dipping structures and a relatively large reservoir outcrop area provide water infiltration pathways. Groundwater modeling suggests reservoirs were water washed by 2–200 million pore volumes since Andean uplift. Finally, average reservoir temperatures are 〈80°C (〈176°F), which further facilitated biodegradation.

Description: Potentiometric surfaces for Paleozoic strata, based on water well levels and selected drill-stem tests, reveal the control on hydraulic head exerted by outcrops in eastern Kansas and Oklahoma. From outcrop in the east, the westward climb of hydraulic head is much less than that of the land surface, with heads falling so far below land surface that the pressure:depth ratio in eastern Colorado is less than 5.7 kPa/m (0.25 psi/ft). Permian evaporites separate the Paleozoic hydrogeologic units from a Lower Cretaceous (Dakota Group) aquifer, and a highly saline brine plume pervading Paleozoic units in central Kansas and Oklahoma is attributed to dissolution of Permian halite. Underpressure also exists in the Lower Cretaceous hydrogeologic unit in the Denver Basin, which is hydrologically separate from the Paleozoic units. The data used to construct the seven potentiometric surfaces were also used to construct seven maps of pressure:depth ratio. These latter maps are a function of the differences among hydraulic head, land-surface elevation, and formation elevation. As a consequence, maps of pressure:depth ratio reflect the interplay of three topologies that evolved independently with time. As underpressure developed, gas migrated in response to the changing pressure regime, most notably filling the Hugoton gas field in southwestern Kansas. The timing of underpressure development was determined by the timing of outcrop exposure and tilting of the Great Plains. Explorationists in western Kansas and eastern Colorado should not be surprised if a reservoir is underpressured; rather, they should be surprised if it is not.

Description: In many tight-gas basins of the western United States distinguishing between productive and non-productive low-permeability sandstones, and predicting relative amounts of gas and water production is difficult. Comparison of gas shows, calculated water saturations, and saturation-height profiles between gas-productive and non-productive sandstones of equal reservoir quality all appear similar. Capillary pressure derived height functions are difficult to apply, and classic rock-typing procedures lack the predictive capability that is common to more traditional reservoirs. Basin reconstructions suggest the timing of petroleum charge and migration preceded maximum burial and uplift. This initial charge was likely a primary drainage displacement with reservoir porosity greater by a factor of 2-3 relative to values found today and permeability greater by 1-3 orders of magnitude. These reservoir systems became low-permeability following initial charge reflecting continued diagenesis throughout burial, subsequent uplift and erosion. With burial, decreasing pore volume caused water saturations and gas columns to increase. During uplift and erosion gas columns adjusted to changing structural configuration. In some cases this led to gas accumulations being leaked and spilled. In other cases, structural readjustment resulted in capillary imbibition and, in some cases, secondary (or higher order) drainage and imbibition. Within trapped accumulations, gas expansion upon uplift further increased gas columns. In cases where gas columns were spilled or within migration pathways imbibition led to residual or near-residual water saturations. Conventional formation evaluation is fundamentally rooted in concepts associated with primary drainage displacement. Tight-gas reservoirs that have experienced late uplift following an earlier phase of charge are unlikely to be characterized by primary drainage and are much more likely to be characterized by imbibition or secondary (or higher order) drainage and possibly imbibition. The hysteresis between primary drainage and imbibition or secondary (or higher order) drainage and imbibition in tight-gas reservoirs is significant and unlike many more traditional reservoirs does not tend to converge on a narrow range of values. Estimates of water saturation are scalar values and do not contain information that allows the saturation history and displacement direction to be deciphered. Recognition that reservoirs are unlikely to be in primary drainage equilibrium is a fundamental paradigm shift that impacts petroleum evaluation at all scales ranging from basin potential to completion decisions within a given well. Although this paper is written from the perspective of tight-gas petroleum systems, the principles are equally applicable to low-permeability oil reservoirs.

Description: Lithofacies, architectural-element abundance, and estimates of dune-bedform height and channel sinuosity from borehole images (BHIs) and well-exposed outcrops allow for an expanded interpretation of the fluvial stratigraphic architecture of the Upper Cretaceous Williams Fork Formation. Sedimentologic and stratigraphic data from outcrops and detailed core descriptions of the Williams Fork Formation, Piceance Basin, Colorado, were used to compare attributes of fluvial architectural elements to BHI characteristics and spectral-gamma-ray (SGR) log motifs. Results show a distinct set of criteria based on BHIs that aid in the interpretation of lithofacies and fluvial reservoir architecture. In contrast, a practical correlation does not exist between outcrop- and core-derived SGR log motifs or thorium and potassium abundances and fluvial lithofacies or architectural elements. Four electrofacies based on BHI characteristics (e.g., dip type, dip pattern, and color scheme) represent the most common fluvial lithofacies and are identified through comparison of paired, calibrated BHIs and core. Cross-bed-set thickness values from BHIs are used to calculate dune height as a proxy for flow energy. The lower and middle Williams Fork Formation represent low-energy meandering and higher energy braided systems, respectively, as evident by changes in channel sinuosity and architectural-element type. The upper Williams Fork Formation is divided into two intervals based on lithofacies, architectural elements, channel sinuosity, and net-to-gross ratio. The subdivision for the upper Williams Fork Formation represents a change from a lower energy, meandering fluvial system to a higher energy, lower sinuosity braided system as related to changes in accommodation through time.

Description: Petroleum (oil and gas) forms from the bacterial or thermal breakdown of kerogen during progressive burial in sedimentary basins. During times of petroleum generation, kerogens in organic-rich source rocks expel petroleum to form a fluid phase in the pore system, capable of migrating under hydrodynamic and buoyancy forces to ultimately escape to the surface or accumulate within petroleum traps in the subsurface. The relative timing of petroleum charge and trap formation is a vital component in the accumulation of petroleum deposits. Exhumed basins have been historically viewed as higher-risk targets for conventional petroleum exploration because of, inter alia, the switch-off of petroleum generation in the source rock at the commencement of cooling during exhumation. However, even at the switch-off point, the source rock may retain a significant volume of petroleum sorbed in kerogen and within its pore system. Herein we demonstrate that if the source rock is exhumed to shallower depths after peak burial, pore pressure reduction and the associated volumetric expansion of the petroleum—particularly of the gaseous—phase in the pore system will result in the discharge of additional petroleum into the adjacent carrier bed or reservoir formations. Because most onshore sedimentary basins are characterized by major exhumation events at some point in their history, this represents an additional and underappreciated mechanism for a late-stage petroleum charge in exhumed sedimentary basins. The modeling also indicates that both the initial, pre-exhumation, total gas storage capacity and the exhumation gas charge are likely to be volumetrically more significant for gas-bearing source rocks that have been exposed to higher initial pressures and lower thermal gradients. The concepts presented here also have implications for petroleum resources retained within unconventional shale reservoirs because high-graded shale plays may be associated with systems where the magnitude or rate of relative overpressure dissipation has limited exhumation charge from the unconventional to conventional reservoirs within the basin.

Description: An estimate or measurement of organic matter density is required for converting between the weight percent of total organic carbon (TOC) and the volume percent of organic matter for wireline log calibration; it is therefore important to recognize when significant changes in organic matter density occur. A method is presented for calculating organic matter density from measurements of crushed-rock dry grain density and Soxhlet-extracted TOC. I have investigated the thermal evolution of organic matter by tracking changes in the intrinsic density of organic matter as a function of thermal maturity. Organic matter density shows two step increases that correspond to the generation of liquid hydrocarbons in the oil window (up to ~1.2% vitrinite reflectance [ R o ]) and the conversion of organic matter to graphitelike carbon (more correctly, "turbostratic carbon") at high thermal maturity (〉4% R o ). Profound structural changes of organic matter may, in part, determine the maturity limits of source-rock tight liquids and shale-gas plays, particularly at high thermal maturity, where gas is hosted within the organic matter–hosted pore system.

Description: Apatite fission track (AFT) and vitrinite reflectance data from five exploration wells and three seafloor cores illuminate the thermal history of the underexplored United States Chukchi shelf. On the northeastern shelf, Triassic strata in the Chevron 1 Diamond well record apatite annealing followed by cooling, possibly during the Triassic to Middle Jurassic, which is a thermal history likely related to Canada Basin rifting. Jurassic strata exhumed in the hanging wall of the frontal Herald Arch thrust fault record a history of probable Late Jurassic to Early Cretaceous structural burial in the Chukotka fold and thrust belt, followed by rapid exhumation to near-surface temperatures at 104 ± 30 Ma. This history of contractional tectonism is in good agreement with inherited fission track ages in low-thermal-maturity, Cretaceous–Cenozoic strata in the Chukchi foreland, providing complementary evidence for the timing of exhumation and suggesting a source-to-sink relationship. In the central Chukchi foreland, inverse modeling of reset AFT samples from the Shell 1 Klondike and Shell 1 Crackerjack wells reveals several tens of degrees of cooling from maximum paleo-temperatures, with maximum heating permissible at any time from about 100 to 50 Ma, and cooling persisting to as recent as 30 Ma. Similar histories are compatible with partially reset AFT samples from other Chukchi wells (Shell 1 Popcorn, Shell 1 Burger, and Chevron 1 Diamond) and are probable in light of regional geologic evidence. Given geologic context provided by regional seismic reflection data, we interpret these inverse models to reveal a Late Cretaceous episode of cyclical burial and erosion across the central Chukchi shelf, possibly partially overprinted by Cenozoic cooling related to decreasing surface temperatures. Regionally, we interpret this kinematic history to be reflective of moderate, transpressional deformation of the Chukchi shelf during the final phases of contractional tectonism in the Chukotkan orogen (lasting until ~70 Ma), followed by renewed subsidence of the Chukchi shelf in the latest Cretaceous and Cenozoic. This history maintained modest thermal maturities at the base of the Brookian sequence across the Chukchi shelf, because large sediment volumes bypassed to adjacent depocenters. Therefore, the Chukchi shelf appears to be an area with the potential for widespread preservation of petroleum systems in the oil window.

Description: Advances in virtual outcrop technologies and their introduction to fracture characterization allow extraction of fracture data from very large and inaccessible areas. The recent development of automated or semiautomated methods for fracture extraction aims to reduce or avoid tedious, time-consuming, and biased manual interpretation of fractures from virtual outcrops. We present a benchmarking exercise between a previously proposed automated fracture picking method, manual picking, and fieldwork methods. Comparison between the three methods highlighted their relative advantages and limitations. The automated fracture picking method provided excellent results in terms of fracture orientation, size, spatial distribution, and density. Fieldwork is complementary to fracture extraction from virtual outcrops, and it should focus on quality control of remote sensing data, poorly exposed areas, small-scale observations, diagenesis, timing of fracture development, building conceptual models, and linking fracture stratigraphy to rock properties. We propose a best practice for the use and integration of manual and/or automated fracture extraction from virtual outcrop and fieldwork data for fracture characterization and modeling from outcrop analogs. We consider integration of different methods as the best way to improve the modeling exercise while reducing operational costs and risks.

Description: Because of its significant impact on relative permeability, capillary pressure, stimulation methods, and ultimate recovery, the wettability of reservoir rocks is a critical factor of the petroleum recovery process. However, characterizing the wettability of shale with extremely low matrix permeabilities is a challenging task because of the dominant presence of nanopores in shale and high heterogeneity of shale compositions at multiple scales. From spontaneous imbibition behavior that uses two types of imbibing fluid (water and n-decane), the present study examines the wettability characteristics of gas-window Barnett Shale samples taken from four different depths of Texas United 1 Blakely core in Wise County in Texas. Imbibition experiments were conducted in two directions: parallel and transverse to the lamination of the samples. A scaling method was used to analyze imbibition data, and observed imbibition behaviors were interpreted to infer the different wettability conditions of four samples with different mineralogy, total organic carbon content, and pore-throat size distribution. Our results show that wettability significantly affects fluid imbibition behavior and that four tested samples can be divided into three wettability categories: more water wet, mixed wet, and more oil wet. Overall, the variable wettability of Barnett samples will affect hydrocarbon storage, distribution, and production.

Description: The prolific Los Angeles basin in California may be the most petroliferous province on Earth per volume of sedimentary fill. However, because most exploration in the basin occurred prior to the advent of modern geochemical methods, genetic relationships among the various petroleum accumulations and their source rocks have remained speculative. A training set of 24 source-related biomarker and stable carbon isotope ratios for 111 non- or mildly biodegraded oil samples from the basin was used to construct a chemometric (multivariate statistics) decision tree. The decision tree allows genetic classification of additional oil or source-rock extract samples that might be collected. The decision tree identifies 6 tribes and a total of 12 genetically distinct oil families. The families have different bulk properties, such as API gravity and sulfur content, which were previously explained as resulting from secondary processes, including thermal maturity or biodegradation. However, the chemometric assignments are based on genetic properties that reflect distinct organofacies. The oil families occur in different locations and reservoir intervals in the basin, consistent with their origins from different organofacies of active source rock. The source-rock depositional environment for each oil family can be inferred using biomarker and isotope ratios. The samples show stable carbon isotope ratios for saturate and aromatic hydrocarbons that indicate different organofacies of Miocene marine source rocks. Tribes 1 and 2 straddle the central trough, mainly occur east of the Newport-Inglewood fault zone (NIFZ), and show evidence of proximal, clay-rich source rock deposited under suboxic conditions with elevated angiosperm input. Tribes 3–6 occur west of the NIFZ and show evidence of more distal, clay-poor source rock deposited under anoxic conditions. Geochemistry and stratigraphy of the oil tribes (1–6 below) suggest the following source-rock organofacies:

Description: The origin of the overpressure in the northern Qaidam Basin has not been clearly understood, which has caused some difficulties in hydrocarbon exploration. Using a compaction study, we applied a modified acoustic-velocity and effective-stress diagram to identify the overpressure transfer in the study area. This phenomenon has not been discussed in previous studies. For the present study, we approximately calculated the magnitude of the transfer overpressure and analyzed the cause of the overpressured aquifer at the crest of the anticline in the study area. Our study indicates that the effect of overpressure transfer is very distinct, and the largest contribution to the total overpressure is 57%. The main media of overpressure transfer include vertical faults and lateral conducting layers. The vertical faults can connect deep overpressured strata, and the lateral conducting layers can connect overpressured strata at the top and wing of the anticline. During anticline formation, the crest fractures, and then the overpressured water in the anticline wing flows into the fractured crest and forms the overpressure compartment that prevents the charging of deeper natural gas.

Description: There is a common belief that we can expect to add value to a prospect or prospect portfolio by improving the prospect chance of success (Pg) as a consequence of acquiring information and doing work. Established laws of probability dictate that this is incorrect. We do expect new information to add value to the exploration cycle, but not by an expectation of improving the prospect risk. New information may result in an increase or a decrease of Pg, but the expected result (the average of all possible outcomes) is zero change. Moreover, for a typical exploration prospect (Pg 〈 0.5), we expect that new information will downgrade more prospects Pg than are upgraded. Real-world prospect data are neither suitable nor publically available to study this. Instead, the concept is explored using an analogous process (prenatal prediction of fetus gender) for which good statistics exist, and by creating a synthetic prospect that can be analyzed in a repeatable way. The results support the predictions made above.

Description: The Marathon 1 Mesquite well was drilled in Hamilton County, Texas, targeting the Barnett Shale with late oil window maturity. Combining a large suite of petrologic and high-resolution organic geochemical analyses on 120 core samples, we have been able to document qualitatively and quantitatively the effects of petroleum retention within and expulsion from five intervals within the Barnett Shale. Lithological heterogeneities control the composition and amount of retained fluids; the sorption of oil by solid organic matter is important in all intervals. Applying empirical formulas, we have been able to demonstrate not only that retention is primarily controlled by total organic carbon (TOC), but also that the "live" or "labile" component, rather than "dead" or "inert" carbon, constitutes the most active sorptive sites. Additional retention in the micropores provided by biogenic microcrystalline quartz (sponge spicules) accounts for the sweet spot defined by an "oil crossover" in the 9.14-m (30-ft) thick second interval. The fluorescing oil occurring in the axial chamber of the sponge spicules and that sorbed on organic particles are together enriched in saturated hydrocarbons, whereas the dispersed oil from the adjacent interval 3 is depleted in this compound class. Mass-balance calculations reveal that short-distance migration of petroleum into this "reservoir" interval (second) fractionates the generated oil into a higher quality oil by preferential retention in the order polar compounds 〉 aromatic hydrocarbons 〉 saturated hydrocarbons within the underlying organic matter and clay-rich third interval (source unit). Furthermore, molecular fractionation, i.e., a preferential expulsion of lower molecular weight hydrocarbons (n-alkanes) could be calculated. An additional practical result for source rock assessment is that corrected S2 (petroleum generated by pyrolysis) and TOC values should be calculated by combining Rock-Eval pyrolysis data on whole rocks and rocks following Soxhlet extraction. Using parameters based on unextracted rock only, the expulsion of petroleum is systematically overestimated and the degree of kerogen conversion is, therefore, concomitantly underestimated.

Description: The exploitation of hydrocarbon reserves in naturally fractured reservoirs composed of different types of rocks has drawn considerable attention from the fracture characterization research community because of the importance of fractures to the prediction of fluid flow. One of the most common methods for rapidly analyzing fracture features is the scanline technique, which provides an estimate of fracture density and frequency. Despite the confidence provided by the systematic use of this method, errors and uncertainties caused by sampling biases exist. The problems caused by these uncertainties can detrimentally affect the construction of a computational model due to misleading trends. This study evaluated the uncertainty caused by sampling biases in the scanline data of opening-mode fractures in outcrops of naturally fractured Aptian laminated limestone from the Crato Formation, Araripe Basin, northeastern Brazil. The Monte Carlo method was chosen to introduce random values into the sampled values, which enabled us to verify the importance of errors in the accuracy of the method of representing the fracture network. In this study, errors and uncertainties were grouped into one parameter, termed the coefficient of uncertainty, which was defined as the ratio between the uncertainties, created by the errors and artifacts introduced artificially, and the original scanline data. The propagation of errors and uncertainties in the scanline data to the coefficients of the corresponding power law were determined. This evaluation can be applied in the construction of more reliable geomechanical models using analog geological models for naturally fractured reservoirs.

Description: Characterizing natural fracture systems involves understanding fracture types (faults, joints, and veins), patterns (orientations, sets, and spacing within sets), size distributions (penetration across layering, aperture, and trace length), and timing relationships. Traditionally, observation-based relationships to lithology, mechanical stratigraphy, bed thickness, structural position, failure mode, and stress history have been proposed for predicting fracture spacing along with the relative abundance of opening-mode fracture versus faults in fractured rocks. Developing a conceptual fracture model from these relationships can be a useful process to help predict deformation in a fractured reservoir or other fractured rock systems. A major pitfall when developing these models is using assumptions based on general relationships that are often site specific rather than universal. In this paper, we examine a mixed carbonate-shale sequence that is cut by a seismic-scale normal fault where fracture attributes do not follow commonly reported fracture relationships. Specifically, we find (1) no clear relationship between frequency (or spacing) of opening-mode fractures (joints and veins) and proximity to the main fault trace and (2) no detectable relationship between fracture spacing and bed thickness. However, we did find that (1) the frequency of small-displacement faults is strongly and positively correlated with proximity to the main fault trace, (2) fracture networks change pattern and failure mode (extension versus shear fracture) from pavement to pavement through the mechanically layered stratigraphic section, and (3) faults are more abundant than opening-mode fractures in many areas within the fracture network. We interpret that the major fracturing initiated near maximum burial under relatively high-differential stress conditions where shear failure dominated and that mode-1 extension fracturing occurred later under lower differential stress conditions, filling in between earlier formed shear fractures. We conclude that whenever possible, site-specific observations need to be carefully analyzed prior to developing fracture models and perhaps a different set of fracture network rules apply in rocks where shear failure dominates and mechanical stratigraphy influences deformation.

Description: Thousands of shale gas wells have been drilled and hydraulically fractured across the state of Pennsylvania over the past decade, and more wells are being drilled each year. The drilled lengths of these wells and the amount of water being used to hydraulically fracture (frac) them continue to increase. These increases have led to an increase in the volume of wastewater being produced each year. However, the ratio of energy produced per barrel of wastewater has increased significantly over the past six years. Recent data show the volume of wastewater produced in one year is approximately 20% of the volume of frac water used in that same year. With changes in state policies, drilling companies in Pennsylvania have been recycling most of their wastewaters over the past few years. The development of various treatment technologies and brine-resistant frac mixtures has allowed companies to recycle this wastewater for use in future frac jobs. Use of this recycled water does not appear to be having a significant effect on production of oil or gas from wells. Recycling wastewater can be very cost-competitive when compared to options such as disposal via waste-treatment plants or injection wells.

Description: Shale gas development in the United States has revolutionized energy production and supply, making the nation energy independent for the first time in decades. However, many people remain concerned that the large-scale hydraulic fracturing necessary to recover hydrocarbons from shale may degrade the environment, including groundwater. Improving the understanding of how groundwater may be impacted by shale gas development requires field monitoring at multiple sites on different shale plays under a variety of climates and hydrologic conditions. Such monitoring has been difficult to achieve because of a lack of access to commercial sites and an absence of funding to drill dedicated research wells.

Description: Many different rock intervals are used for brine disposal injection in the Appalachian Basin. The study area was defined as eastern Kentucky, Ohio, Pennsylvania, and West Virginia. Brine injection in the study area has increased from approximately 6–7 million barrels (bbl) per year in the early 2000s to 17.6 million bbl in 2012, mostly due to shale gas activity. A review of geologic properties and subsurface distribution of rock formations used for injection is useful to understand brine disposal operations in the region. Operational data on injection rates and pressures were compiled for 2008–2012 for more than 300 class II brine disposal wells. Several class II brine disposal wells were monitored with continuous wellhead pressure loggers to estimate reservoir properties and understand injection operations. Project results provide a catalog of injection rates for the various formations, which range from hundreds to more than 100,000 bbl per month per well. Hydrologic analysis of depleted hydrocarbon reservoirs and deep saline formations in the study area indicates that there is a large capacity for brine disposal, but the characteristics of the rock formations may limit injection rates. Based on hydrocarbon production and brine injection volumes from 2008 to 2012, approximately 9984 bbl of brine were routed to class II brine disposal wells per billion cubic feet gas production, which suggests ultimate demand of up to 706–2290 million bbl brine disposal related to unconventional Marcellus and Utica plays. Understanding the geology and operational history of the injection zones is critical to support safe, reliable, and environmentally responsible brine disposal in the region.

Description: Disposal of the liquid wastes generated during extraction of unconventional oil and gas resources in North America is increasingly becoming a constraint to development. Currently, the bulk of these wastes is disposed of by injection into deep bedrock formations. In certain development areas, the presence of suitable disposal formations is scarce, or disposal operations are difficult to site given area constraints. To address this challenge, a process of identifying high-value disposal targets (i.e., formations and locations) was developed using a combination of hydrogeological principles, multicriteria analysis, and geospatial mapping. This paper outlines the process developed to identify potential disposal targets to support oil sand development in Alberta and the results obtained.

Description: 〈span〉〈div〉ABSTRACT〈/div〉The upper zone of the Lower Cretaceous Kharaib Formation (151–177 ft [46–54 m] thick in the studied wells) is a major oil reservoir in several giant oil fields. Wide variations in porosity and permeability of this zone have been shown to result from both the inhibition of burial cementation by oil in the crest of each field and localized cementation adjacent to stylolites, combined with the more subtle influence of widely varying depositional mud content and grain size. The present study examines these relationships in closer detail, using core and petrographic observations from two wells on the oil-filled crest and two wells on the water-filled flanks of a giant domal oil field.Although porosities are higher overall in the crestal cores, each well shows wide variations within each of seven main groupings of the samples by depositional texture. This heterogeneity results mainly from the distribution of clay, which is concentrated along depositional laminations and causes widely varying porosity losses in all textures by promoting stylolite development and associated calcite cementation. Higher clay abundance (and lower porosity) within the upper and lower 12–17 ft (4–5 m) of the reservoir reflects increased influx of siliciclastic fines across the epeiric Barremian carbonate platform immediately following and preceding, respectively, third-order falls in global sea level. Most (95%) of porosity-permeability data from the studied wells lie within Lucia rock-fabric class 3, showing distinct but relatively subtle differences between texture groups, whereas a subordinate part of the data from the upper, relatively mud-poor third of the reservoir plot at higher permeabilities. Development of a predictive model for the petrophysical heterogeneity of this example requires a combination of the following: (1) a diagenetic model for porosity controls; (2) the use of a modestly higher porosity-permeability transform (upper class 3) in the upper part of the reservoir than in the lower reservoir (lower class 3); and (3) a recognition of the scattered and widely varying occurrences of exceptionally high permeabilities in the upper reservoir.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In the Paleocene to Eocene Wilcox Group in the northern Gulf of Mexico, exploration targets are reaching into deep to ultradeep burial depths. At these great depths, reservoir quality (porosity and permeability) becomes an important risk factor in determining the chance of encountering an economic reservoir. Major controls on reservoir quality are pore types and abundances, pore-throat sizes, and pore network composition. These factors can be analyzed by integrating petrographic, core plug porosity and permeability, and mercury injection capillary pressure (MICP) analyses. The Wilcox sandstones are mostly lithic arkoses and feldspathic litharenites that contain primary interparticle pores, secondary dissolution pores, and micropores. However, these pore types evolve with depth and temperature. As temperature increases, the relative abundance of primary interparticle pores decreases, whereas the relative abundance of secondary dissolution pores and nano- to micropores increases. Associated with this evolution of pore networks with increasing temperature, there is a decrease in reservoir quality. This decrease in reservoir quality is caused by a transition to finer pore-throat sizes that correspond to changes in pore types. Petrographic analysis provides information on pore types, core plug porosity and permeability analysis provides information on volume of pores and effectiveness of flow, and MICP analysis provides information on pore-throat radius distribution. Through forecasting the pore network in the target temperature zone, a realistic porosity versus permeability transform can be selected to estimate permeability from wire-line log porosity.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Canning Basin is a largely unexposed and underexplored frontier basin, formed mostly in the Paleozoic. Geological knowledge of this basin is based predominantly on sparse regional “vintage” two-dimensional seismic and small three-dimensional (3-D) seismic surveys and less than 230 exploration wells. Following seismic interpretation, an integrated interpretation was completed on airborne gravity gradiometer (AGG), magnetic, seismic, well, and complementary data along the southwestern margin of the Fitzroy trough and Gregory subbasin. Seismic data were reinterpreted using AGG data to produce a better constrained geological model. A basement structure map, two intrasedimentary structure maps, and a formation distribution map were produced. The interpretation of seismic profiles, validated through 2.5-dimensional gravity gradiometer modeling, is essential to this workflow.Repeatedly reactivated west–northwest and northwest structural trends, inherited from Proterozoic orogenies, respectively delineate the Fitzroy trough and the Gregory subbasin with its northwestern structural extension into the Fitzroy trough, the Gregory subbasin trend. Subsidence occurred during two periods of extension. An asymmetric extensional system of the Fitzroy trough controlled Ordovician–Silurian deposition of the Carribuddy Group. Devonian–Carboniferous subsidence defines the Gregory subbasin trend. This Pillara extension reactivated structures in the east of the Fitzroy trough. Simultaneous activity of both extensional fault systems and growth faulting controlled the facies and thickness distribution of carbonates and clastics of the early Carboniferous Fairfield Group. The Meda and Fitzroy transpressional phases inverted faults of the Gregory subbasin trend and Fitzroy trough, producing prospects by structural interference.The improved understanding of tectono-stratigraphic relationships, including the 3-D distribution of carbonate reservoirs, benefited the planning of seismic surveys, prospect evaluation, drilling, and acreage relinquishment.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Thermal conductivity is a major influencing factor on subsurface conductive heat transport and resulting temperature distribution, which in turn is a key parameter in basin modeling. Basin modeling studies commonly use representative literature values of thermal conductivity despite their impact on modeling results. We introduce a workflow for quantifying the effect of uncertain thermal conductivity on subsurface temperature distribution and thus on basin modeling results and test this workflow on a two-dimensional generic model from the Nordkapp Basin; a prior ensemble of possible models is conditioned according to Bayes’ theorem to incorporate prior knowledge of temperature data. This conditional probability yields a posterior ensemble of temperature fields with a significantly reduced standard deviation. To verify our approach, we use five characteristic scenarios from the posterior ensemble for transient petroleum systems modeling. How considering uncertain thermal conductivity affects variance in hydrocarbon generation is assessed by modeling corresponding vitrinite reflectances (〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉).Temperature uncertainty increases with depth. It also increases with increasing offset from the salt diapirs, which can be associated with a large lateral heat-flow component in the complex tectonic environment of the Nordkapp Basin. The introduced workflow can reduce temperature uncertainty significantly, especially in regions with high prior uncertainty. The 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 is very sensitive to changes in thermal conductivity because the onset depth of the gas window in the Nordkapp Basin may vary by up to 800 m (2600 ft) within the 95% confidence interval. This demonstrates the importance of quantification of the uncertainty in thermal conductivity on thermal basin modeling.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Yinggehai–Song Hong Basin has received a large amount of terrigenous sediment from different continental blocks since the Paleogene. The Yingdong slope, which is located on the eastern side of this basin, is an important potential gas province, but the provenance of the marine sediments in this area are poorly understood. The detrital zircon U-Pb geochronology of sedimentary rocks from the lower Miocene to Quaternary is examined in this study to investigate the temporal and spatial variations in provenance since the early Miocene. The U-Pb ages of detrital zircon range from 3078 to 30 Ma, suggesting that sediment input is derived from multiple sources. Detailed analyses of these components indicate that both the Red River and Hainan are likely the major sources of the sediments on the Yingdong slope, with additional minor contributions from central Vietnam (eastern Indochina block) and possibly the Songpan–Garze block. Variations in the dominant detrital zircon populations within stratigraphic successions display an increasing contribution from the Red River since the middle Miocene. This resulted from the progradation of the Red River Delta in the northern basin and may have also been influenced by regional surface uplift and associated climate changes in East Asia. This study shows that the Red River has had a relatively stable provenance since at least the early Miocene, indicating that any large-scale drainage capture of the Red River should have occurred before circa 23 Ma.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Jurassic black mudstone and coal beds in the central Junggar Basin, northwestern China, are the major source rocks for the basin with type II〈sub〉2〈/sub〉 and type III (gas-prone) kerogens. Widespread overpressures are developed in the Jurassic stratigraphic interval. Sonic and resistivity logs display strong characteristic responses of overpressure in the mudstones, with anomalously high acoustic traveltimes and low resistivity compared with the normally pressured mudstones. The overpressured Jurassic sediment sequences appear to have undergone normal compaction because the mudstones exhibit no anomalously low bulk density. The overpressured mudstones deviate from the normally pressured mudstones in density–effective vertical stress space. The overpressure in the Jurassic source rocks is, therefore, not caused by disequilibrium compaction. The overpressured Jurassic sandstone reservoirs are predominantly oil and gas saturated or oil bearing. The well-log responses of the overpressured mudstones and seismic velocity characteristics indicate that the top depth of the overpressure zone ranges from 3800 to 4600 m (12,500 to 15,100 ft), corresponding to formation temperatures of approximately 94°C to 111°C (∼201°F to 232°F), with estimated vitrinite reflectance values of 0.6% to 0.75%. The Jurassic source rocks with overpressure are capable of generating hydrocarban at present and are currently overpressured. All the evidence suggests that the overpressure in the Jurassic source rocks in the central Junggar Basin is caused by hydrocarbon (HC) generation. The overpressure evolution was modeled quantitatively in response to pressure changes caused by HC generation during basin evolution. The results indicate that multiple episodes of overpressure development and release occurred within the Jurassic source rocks, suggesting multiple episodes of HC expulsion. The timing and numbers of these episodes of HC expulsion were thus determined from the modeled overpressure evolution.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Thermal properties of rocks are essential parameters for investigating the geothermal regime of sedimentary basins, and they are also important factors in assessments of hydrocarbon and geothermal energy resources. The Tarim Basin, the largest basin located in the north of the Tibetan Plateau, northwestern China, has great hydrocarbon resource potential and is an ongoing target for industry exploration. However, the thermal properties of sedimentary rocks within the basin are yet to be systematically investigated at a basin scale, thereby limiting our understanding of the thermal regime in the basin. Here, we collected 101 samples of sedimentary rocks and measured their thermal properties. Our results show that the ranges (and means) of thermal conductivity, radiogenic heat production, and specific heat capacity are 1.08–5.35 W/mK (2.52 ± 0.99 W/mK), 0.03–3.24 μW/m〈sup〉3〈/sup〉 (1.24 ± 0.87 μW/m〈sup〉3〈/sup〉), and 0.75–1.10 kJ/(kg·°C) (0.87 ± 0.07 kJ/(kg·°C)), respectively. Volumetric heat capacity and thermal diffusivity at the temperature of 40°C range from 1.61 to 2.79 MJ/(m〈sup〉3〈/sup〉·K) (2.26 ± 0.25 MJ/[m〈sup〉3〈/sup〉·K]) and 0.44–2.95 × 10〈sup〉−6〈/sup〉 m〈sup〉2〈/sup〉/s ((1.12 ± 0.53) × 10〈sup〉−6〈/sup〉 m〈sup〉2〈/sup〉/s), respectively. The thermal properties vary considerably for different lithologies, even within the same lithotype, indicating that thermal properties alone cannot be used to distinguish lithology. Thermal conductivity increases with increased burial depth, density, and stratigraphic age, suggesting the dominant influence is porosity variation on thermal conductivity. Furthermore, a strong contrast in the thermal properties of rock salt and other sedimentary rocks perturbs the geothermal pattern, which should be taken into consideration when performing basin modeling.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The relationship between base metal deposits, especially Mississippi Valley–type (MVT) Pb–Zn deposits, and hydrocarbons is not well constrained. This is despite the fact that hydrocarbons generally occur in MVT deposits; the ores are emplaced in the same temperature range as hydrocarbon maturation and migration, and the deposits commonly occur in proximity to metal-rich black shales. Better understanding should lead to better exploration models for both hydrocarbons and MVT deposits. This connection is better understood with the help of Pb isotope patterns. Sphalerite Pb isotope compositions from the northern Arkansas and Tri-State mining districts and Woodford–Chattanooga and Fayetteville Shales were determined to assess the potential of shales as source rocks for the ore metals. The ores in both districts have a broad range of Pb isotope ratios and define linear trends, suggesting mixing of Pb from two distinct end members. Current results and previous depositional environment studies indicate the following: (1) shales deposited mainly under nonsulfidic anoxic conditions represent the less radiogenic end member, or (2) shales are the only source of ore metals. Given the array of organic molecules, each with their own thermochemical range, and the ways metals can be associated with them, the release of metals may cover varying ranges. Thus, the compositions of the released fluids would change through time and not have a single static composition, closely approximating the isotopic composition of the released metals at various times. Mineralization derived from a dynamically evolving fluid may show apparent end members, without the need to call on mixing of fluids from separate sources.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉A subaqueous clinoform system has been identified from high-quality three-dimensional seismic data from the northeast Exmouth Plateau, North West Shelf, Australia, and was interpreted as a shelf–slope–basin clinoformal component of a Jurassic fluviodeltaic system (the Legendre delta). Several geomorphological features associated with shelf-slope development and subsequent rift tectonics were identified, including (1) submarine channels at slope to basin floor; (2) gullies on the slope; (3) slumps on the shelf; and (4) canyons, canyon-derived gravity flow deposits, and a fan lobe developed in subsequent rift processes.The results of this study provide insights into the controlling factors on the sinuosity, degree of erosion, and sediment gravity flows of channels developed at slope to basin-floor settings, which shed light on the way fluvial sands were transported across the shelf and slope to the basin floor. The geometries and distributions of gravity flow deposits, if confirmed by drilling, may serve as an analog for reservoir prediction in the deep-water fluviodeltaic settings. The gullies on the slope were interpreted as a result of dilute, sheetlike flows. The slumps on the shelf were interpreted as a result of nonslope-related causes.The syntectonic canyons, the canyon-derived gravity flow deposits, and the fan lobe present vivid examples of the erosion and sedimentation processes during active rift tectonics and have significant implications for understanding the rift processes of the North West Shelf, Australia, as well as other rift-related basins.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Giant petroleum accumulations worldwide with burial depths more than 7000 m (〉23,000 ft) occur mostly in Mesozoic and Cenozoic reservoirs and yield predominantly natural gas. Recently, however, a giant oil accumulation with reservoir depths between 7000 m (23,000 ft) and 8000 m (26,000 ft) was discovered in the lower Paleozoic section in the southern part of the Halahatang region in the Tarim Basin, China. Petroleum sourced from lower Paleozoic rocks is contained in Ordovician karst fracture-cave reservoirs and sealed by Middle–Upper Ordovician limestones and mudstones. The newly discovered superdeep accumulation is among the deepest black single-phase oil accumulations worldwide and opens up new avenues for petroleum exploration in deep-marine carbonate reservoirs. Reservoir pressures are between 75 MPa (10,878 psi) and 85 MPa (12,328 psi), with pressure coefficients between 1.2 and 1.7 and temperatures ranging between 140°C (284°F) and 172°C (342°F). Charging and accumulation of petroleum occurred during the late Hercynian orogeny, followed by subsequent gradual deep burial, which took place before rapid subsidence beginning circa 5 Ma. Following subsidence, the thickness of overlying strata increased by more than 2000 m (〉6600 ft) before finally attaining current depth. Therefore, this oil accumulation represents a well-preserved ancient petroleum system. Based on the geochemical features of oils and gases, the crude oils can be classified as mature, sourced from mixed marine organofacies of shale, marl, and carbonate, whereas the gases were cogenerated with oils. Despite very high present-day reservoir temperatures, no oil cracking has occurred because of the relatively short exposure of oils to high temperatures in a low geothermal gradient regime. Thus, there is significant exploration potential under similar conditions for liquid petroleum in superdeep strata. Faults and reservoirs are major factors controlling petroleum accumulation. Interlayer karsts with excellent fracture-cavity connectivity developed adjacent to faults, generally resulting in the enrichment of oil and gas along fault zones. High-quality reservoirs in this area are easy to identify because they exhibit strong bead-like amplitude features in seismic sections. Wells located near faults produce relatively large amounts of oil and gas. Effective karst fracture-cave reservoirs with noncracked oil may exist below 8000 m (26,000 ft) in the Tarim Basin and represent a significant exploration target in China.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Substantial amounts of petroleum were recently discovered in the Carboniferous andesite, tuff, breccia, and basalt reservoirs of the Chepaizi uplift in the western Junggar Basin. However, the charging history of the Carboniferous petroleum reservoir is poorly understood. Oil–oil correlation studies indicate that all of the oils were mainly derived from the middle Permian Wuerhe Formation source rocks, possibly mixed with a small contribution from Carboniferous Baogutu Formation source rocks in the neighboring Changji sag. Based on the petrographic and microthermometry of fluid inclusions, two hydrocarbon charging episodes are defined; these episodes were characterized by a low-peak-range homogenization temperature (〈span〉Th〈/span〉) distribution (80°C–90°C) and high salinity (13.22–13.42 wt. % NaCl) and a high-peak-range 〈span〉Th〈/span〉 distribution (120°C–130°C) and low salinity (4.89–11.72 wt. % NaCl), respectively. Through one-dimensional basin modeling and pressure–volume–temperature–composition simulation, the burial-thermal histories for wells P61, P66, P668, and P663 were reconstructed, and their trapping temperatures of the hydrocarbon inclusions were calculated to be higher than their corresponding highest paleotemperature (i.e., 56.8°C, 53.7°C, 60.9°C, and 58.1°C, respectively), implying fast hydrocarbon charging processes promoted by deep hydrothermal fluids. Associated with the hydrocarbon generation history, sealing process of the Hongche fault, and regional tectonic evolution, these two hydrocarbon charging events were deduced as the adjustments of oils previously accumulated along the Hongche fault zone, because of the tectonic extension in the Paleogene and regional tilting in the Neogene, respectively. The general direction of oil charging was traced from south to north and from east to west, as indicated by the molecular parameters of nitrogen-bearing compounds and C〈sub〉20〈/sub〉 + C〈sub〉21〈/sub〉 triaromatic steroids/C〈sub〉20〈/sub〉 + C〈sub〉21〈/sub〉 + C〈sub〉26〈/sub〉–C〈sub〉28〈/sub〉 triaromatic steroids (TA(I)/TA(I+II)), which roughly coincided with the active fracturing.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Modern oil and gas seismic surveys commonly use areal arrays that record continuously, and thus routinely collect “excess” data that are not needed for the conventional common reflection point imaging that is the primary goal of exploration. These excess data have recently been recognized to have utility not only in resource exploration but also for addressing a diverse range of scientific issues.Here we report processing of such discarded data from recent exploration surveys carried out in southeastern New Mexico. These have been used to produce new three-dimensional (3-D) seismic reflection imagery of a layered complex within the crystalline basement as well as elements of the underlying crust. This enigmatic basement layering is similar to that found on industry and academic seismic reflection surveys at many sites in the central United States. Correlation of these reflectors with similar features encountered by drilling in northwestern Texas suggest that they may be part of an extensive, continental-scale network of tabular mafic intrusions linked to Keweenawan rifting of the igneous eastcentral Unites States during the late Proterozoic. More importantly, this analysis clearly demonstrates that the new generation of continuously recorded 3-D exploration datasets represent a valuable source of fresh information on basement structure that should be examined rather than discarded. Such basement information is not only important to understanding crustal evolution, it is directly relevant to assessing risks associated with fossil fuel extractions, such as induced seismicity related to waste water injection.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The detailed depositional systems and basin evolution of Lower Cretaceous coal-bearing strata in the Erlian Basin of northeastern China were analyzed based on extensive borehole and outcrop data. A total of 7 facies associations are interpreted and consist of 14 distinct lithofacies, with lithologies including conglomerates, sandstones, siltstones, mudstones, shales, and coals. Five third-order sequences were recognized, and their internal lowstand, transgressive, and highstand systems tracts were defined based on six key sequence stratigraphic boundaries. These boundaries were represented by regional unconformities, basal erosional surfaces of incised valley fills, interfluvial paleosols, and abrupt depositional facies-reversal surfaces. Sequences I–V correspond to the rift-initiation stage, the early-rift climax stage, the late-rift climax stage, the immediate postrift stage, and the late postrift stage of the basin, respectively. The preferred sites for coal accumulation were braided fluvial delta plain, meandering fluvial delta plain, and littoral–shallow lake environments. The major coal seams formed during the early and late transgressive systems tract of sequences III, IV, and V, which were well developed in the eastern, northeastern, and northeastern parts of the Erlian Basin, respectively. Three coal depositional models were summarized in the sequence stratigraphic framework, including types 1, 2, and 3, corresponding to the Newark type, Newark–Richmond type, and Richmond type, respectively. These coal depositional models were closely related to the basin evolution. These results could provide preferred depositional environments and favorable areas of coal and coalbed methane (CBM) for the exploration and development of coal and CBM in the Erlian Basin, with the Jiergalangtu, Huolinhe, Baiyinhua, and A’nan sags recommended as the key sags.〈/span〉

Description: Some recent publications promote one-run, open-system pyrolysis experiments using a single heating rate (ramp) and fixed frequency factor to determine the petroleum generation kinetics of source-rock samples because, compared to multiple-ramp experiments, the method is faster, less expensive, and presumably yields similar results. Some one-ramp pyrolysis experiments yield kinetic results similar to those from multiple-ramp experiments. However, our data for 52 worldwide source rocks containing types I, II, IIS, II/III, and III kerogen illustrate that one-ramp kinetics introduce the potential for significant error that can be avoided by using high-quality kinetic measurements and multiple-ramp experiments in which the frequency factor is optimized by the kinetic software rather than fixed at some universal value. The data show that kinetic modeling based on a discrete activation energy distribution and three different pyrolysis temperature ramps closely approximates that determined from additional runs, provided the three ramps span an appropriate range of heating rates. For some source rocks containing well-preserved kerogen and having narrow activation energy distributions, both single- and multiple-ramp discrete models are insufficient, and nucleation-growth models are necessary. Instrument design, thermocouple size or orientation, and sample weight likely influence the acceptable upper limit of pyrolysis heating rate. Caution is needed for ramps of 30–50°C/min, which can cause temperature errors due to impaired heat transfer between the oven, sample, and thermocouple. Compound volatility may inhibit pyrolyzate yield at the lowest heating rates, depending on the effectiveness of the gas sweep. We recommend at least three pyrolysis ramps that span at least a 20-fold variation of comparatively lower rates, such as 1, 5, and 25°C/min. The product of heating rate and sample size should not exceed ~100 mg °C/min. Our results do not address the more fundamental questions of whether kinetic models based on multiple-ramp open-system pyrolysis are mechanistically appropriate for use in basin simulators or whether petroleum migration through the kerogen network, rather than cracking of organic matter, represents the rate-limiting step in expulsion.

Description: In this study, we develop a model discrete fracture network (DFN) for the unconventional, naturally fractured Tensleep Sandstone oil reservoir at Teapot Dome, Wyoming. Reservoir characterization is based on three-dimensional (3D) seismic data, fracture image logs from Teapot Dome, and field observations of the Tensleep exposure in the Alcova anticline and Fremont Canyon areas. Image logs reveal that the dominant reservoir fracture set trends parallel to the present-day maximum horizontal compressive stress ( $${S}_{\mathrm{Hmax}}$$ ) inferred from drilling induced fractures. Analog field studies of the Alcova anticline and Fremont Canyon suggest fracture heights and lengths are power-law distributed, while the fracture spacing distribution is best described as log-normal. Image-log–derived fracture apertures are also log-normally distributed. These properties are incorporated into a model DFN. We assume subseismic folds, faults, and fracture zones control fracture intensity distribution and use composite 3D seismic attributes to locate subtle changes in seismic response interpreted to result from subseismic structure. Directional curvature defines aperture-opening strain normal to the dominant reservoir fracture set. Seismic attributes are scaled and combined to control fracture intensity variations in the model. Grid-cell porosity and permeability distributions derived from the DFN suggest the presence of northeast–southwest-trending reservoir compartments. We suggest that enhanced oil recovery operations may be optimized using lateral $${\mathrm{CO}}_{2}$$ injection and production wells oriented along interpreted compartment boundaries at high angles to $${S}_{\mathrm{Hmax}}$$ . This combination of $${\mathrm{CO}}_{2}$$ injection and production laterals could help maximize $${\mathrm{CO}}_{2}$$ storage and hydrocarbon recovery in depleted reservoirs and in down-dip residual oil zones.

Description: 〈span〉〈div〉ABSTRACT〈/div〉Different from most tight oil reservoirs, the tuffaceous tight oil of the Tiaohu Formation is not in situ oil, and no close contact exists between the source rock and reservoir in the Malang sag (Santanghu Basin, China). This study determined the mechanism of hydrocarbon accumulation of this tuffaceous tight oil reservoir through an integrated analysis of oil–source rock correlation, reservoir characteristics, and rock wettability combined with a comprehensive analysis of geological conditions. An oil–source rock correlation using biomarkers and stable carbon isotopes shows that the crude oil originated from underlying source rocks in the Lucaogou Formation. The oil in the tuffaceous tight reservoir is not indigenous but has migrated over a long distance to accumulate in these reservoirs. Faults and fractures that developed at the end of the Cretaceous are the oil migration pathways. Vitric and crystal-vitric tuffs constitute the main rock types of the tuffaceous tight reservoir. Matrix-related pores in the tuffs mainly comprise interparticle pores between minerals and dissolution intraparticle pores formed by devitrification. The adsorption of polar components of the oil generated from original organic matter in the tuff leads to wettability of lipophilicity, which is the main reason for hydrocarbon charging and accumulation. To our knowledge, this is the first comprehensive study reporting this finding.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Predicting vertical and lateral facies variations in various depositional environments remains a major challenge in the oil and gas industry because it impacts petroleum system assessments and the associated exploration-risking phase. The use of multidisciplinary constraints (geomorphology, geology, geophysics) in forward stratigraphic models sheds light on the complex interaction of local, regional, and global driving mechanisms that influence sediment transport and deposition along continuously evolving landscapes. In this paper, we develop an integrated statistical approach to examine the sensitivity of forward stratigraphic models in complex salt provinces to several parameters, including water discharge, sedimentary load, grain size and associated diffusion coefficients, and slope. This statistical analysis was applied to the Barremian–Albian sequence of the central Scotian Basin (Canada) and highlights the influence of complex salt kinematics on sediment pathway diversion and accumulation around salt domes and canopies. Forward stratigraphic modeling results point to regions of higher probability of Lower Cretaceous sandy reservoirs. Automating simulation runs significantly reduced the time required to achieve a statistically valid number of simulations and allowed the sensitivity of the model to be evaluated.〈/span〉

Description: 〈span〉In his comment on our paper about the hyperpycnites in the Triassic Yanchang Formation, G. Shanmugam puts forward that hyperpycnites do not exist. Consequently, he considers our interpretation that hyperpycnal flows are an important depositional process in the Yanchang Formation to be invalid. We unravel his arguments and demonstrate that evidence supports our assertion that hyperpycnal flows were an important sedimentary process in the lake in which the Yanchang Formation accumulated. Moreover, we provide proof from modern observations that hyperpycnal flows do exist in lakes.〈/span〉

Description: 〈span〉〈a href="https://pubs.geoscienceworld.org/aapgbull#b27"〉Yang et al. (2017b)〈/a〉 have advocated the importance of hyperpycnites by using a genetic facies model proposed for deposits of hyperpycnal flows by 〈a href="https://pubs.geoscienceworld.org/aapgbull#b14"〉Mulder et al. (2003)〈/a〉. The problem is that the authors have ignored experimental flume results and other empirical field data that discredited the model. This discussion is a rigorous evaluation of data, documentation, and the facies model.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉We analyze western Caribbean structural styles and depositional controls associated with Late Cretaceous–Cenozoic deformational events using a 1600-km (994-mi)-long, regional, northwest–southeast transect extending from the Cayman Trough in Honduras to northern Colombia. Different structural provinces defined along the transect include (1) the Cayman Trough and adjacent Honduran borderlands marking the North American–Caribbean transtensional plate boundary characterized by late Eocene–Holocene fault-controlled depocenters; (2) the Nicaraguan Rise that includes continental Paleocene–Eocene rocks deposited in sag basins, which are overlain by relatively undeformed Miocene–Holocene carbonate and clastic shelf deposits of the northern Nicaraguan Rise, following a Late Cretaceous convergent phase; (3) the Colombian Basin that includes thick Miocene clastic depocenters and the localized presence of Upper Cretaceous rocks overlying the basement and where much of the subsidence is likely isostatic and flexurally driven given its proximity to the subduction zone of northern Colombia; (4) the south Caribbean deformed belt, an active, accretionary prism produced by the subduction of the Caribbean large igneous province beneath the South American plate, which has deformed the Cenozoic prism and fore-arc section and produced thrust-fault–controlled accommodation space for upper Miocene–Holocene piggyback deposits; and (5) the onshore Cesar–Rancheria Basin in northern Colombia, which has recorded the uplift of its bounding mountain ranges, the Sierra de Santa Marta massif to the west and Perija Range to the east. Plate reconstructions place the various crustal provinces along the transect into the context of the Late Cretaceous–Cenozoic deformation events that can be partitioned into strike-slip, convergent, and extensional components.〈/span〉

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

Description: 〈span〉〈div〉ABSTRACT〈/div〉Helium and nitrogen variations in Panhandle–Hugoton field (PHF) gases are products of interaction between hydrocarbon gas from the Anadarko basin and at least two water masses with dissolved nitrogen and helium. The two most distinct water masses are from the Palo Duro basin (highest He/N〈sub〉2〈/sub〉) and the Hugoton embayment (lowest He/N〈sub〉2〈/sub〉). Geochemical data indicate several hundred million years of helium generation in porous rock. Helium migrated to the gas by diffusion through water-saturated rock and by west-to-east water flow.Sediment and basement helium generation and helium migration were modeled to validate timing and source of PHF helium. Models indicate a predominantly sedimentary helium source with some basement helium charge on the Amarillo uplift. Helium in the central and eastern PHF diffused from underlying rocks, whereas gases on the west and southwest sides were enriched in nitrogen and helium delivered by hydrodynamic water flow.Nitrogen in high-nitrogen gases was probably sourced as ammonium released from clays by cation exchange with brines derived from overlying salt units. The amount of mudrock (nitrogen and helium source) relative to other potential helium sources (arkose, radioactive dolomite) correlates to decreasing gas He/N〈sub〉2〈/sub〉.The high helium concentrations in PHF gases result from multiple favorable circumstances. Old pore water accumulated dissolved helium during hundreds of millions of years of helium generation in sediment. High water/gas and low pressure favored higher helium concentrations in gas. Hydrodynamic flow delivered helium-rich pore water from basins west of the PHF.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉As an important unconventional and alternative resource, shale gas has attracted worldwide attention. The breakthrough pressure is a major factor in the generation and migration of shale gas as well as in the evaluation of the caprock sealing capacity. Carboniferous shales are considered to have great potential for the exploitation of shale gas; thus, investigations of the breakthrough pressure and gas effective permeability are significant. Two shale samples taken from the Carboniferous Hurleg Formation in the eastern Qaidam Basin, China, were chosen to conduct breakthrough experiments to investigate the effects of water saturation and CO〈sub〉2〈/sub〉–CH〈sub〉4〈/sub〉 mixed mole fractions on the breakthrough pressure and gas effective permeability. Prior to the experiments, various relevant parameters (e.g., the porosity, mineral composition, and organic geochemistry; the total organic content, thermal maturity and kerogen type; and microstructure) of these samples were also measured.The results of our breakthrough experiments show that the breakthrough pressure increases with the water saturation and decreases with the CO〈sub〉2〈/sub〉 mole fraction in the gas mixture. The situation for the gas effective permeability is just the opposite. Pore-size distribution measurements indicate that there are many nanoscale micropores that can easily be blocked by water molecules. This results in the reduced connectivity of gas pathways; thus, the breakthrough pressure increases and the gas effective permeability decreases with increasing water saturation. The breakthrough pressure decreases with the CO〈sub〉2〈/sub〉 mole fraction because the interfacial tension of the CO〈sub〉2〈/sub〉–water system is smaller than that of the CH〈sub〉4〈/sub〉–water system. The viscosity of the CO〈sub〉2〈/sub〉–CH〈sub〉4〈/sub〉 mixture was found to increase with the CO〈sub〉2〈/sub〉 mole fraction by fitting a series of values under the same temperature and pressure conditions, leading to an increase in the gas effective permeability. Furthermore, CO〈sub〉2〈/sub〉 molecules are smaller than CH〈sub〉4〈/sub〉 molecules, making it easier for CO〈sub〉2〈/sub〉 to move across pathways. After each breakthrough experiment, the CO〈sub〉2〈/sub〉 mole fraction in the effluent was less than that in the injected gas, and it increased over time until reaching the initial injected gas composition. This is because the adsorption and solubility of CO〈sub〉2〈/sub〉 in water are greater than those of CH〈sub〉4〈/sub〉. This study provides practical information for further investigations of shale gas migration and extraction and the sealing capacities of caprocks.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉A comprehensive study on rift stratigraphy requires a solid understanding of sequence architecture along the steep margins of rift basins. This study analyzes an Eocene lacustrine sequence along the steep margin of the Dongying depression in eastern China through integrated core, well-log, and three-dimensional seismic analyses. The lacustrine sequence is bounded by unconformities and their correlative conformities at the base and top and consists of three systems tracts, namely an early expansion systems tract (EEST), late expansion–early contraction systems tract (LEECST), and late contraction systems tract (LCST), which record a lake expansion–contraction cycle. These systems tracts differ in thickness and development of depositional systems. The EEST is the thickest and contains well-developed marginal and basinal fan systems with an overall retrogradational stacking pattern. The well-developed fan systems are the most striking features within the sequence. The LEECST is the most widespread and contains dominantly profundal–sublittoral deposits. The LCST is the thinnest, with poorly developed fan systems, and is characterized by significant erosion by fluvial incision. The variable thickness and development of depositional systems in the three systems tracts are the responses to the interplay of sediment supply and accommodation space. Accommodation space establishes the framework for sedimentary infill, and sediment supply determines spatial distribution and temporal evolution of depositional systems within each systems tract. This study provides a lake expansion–contraction scheme to divide a lacustrine stratigraphic sequence into systems tracts and highlights the feasibility of applying this approach in studying sequence stratigraphy along the steep margin of a lacustrine rift basin. The results also provide understandings for the development, distribution, and evolution of depositional systems and their controlling factors along the steep margin of other rift basins in the world.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The purpose of this work is to identify genetic affinities among 48 crude oil samples from the onshore and offshore Santa Maria basins. A total of 21 source-related biomarker and stable carbon isotope ratios among the samples were assessed to assure that they were unaffected by secondary processes. Chemometric analysis of these data identifies six oil families with map and stratigraphic distributions that reflect organofacies variations within the Miocene Monterey Formation source rock. The data comprise a training set that was used to create a chemometric decision tree to classify newly collected oil samples. Three onshore families originated from two synclines, which may contain one or more pods of thermally mature source rock. Multiple biomarker parameters indicate that the six oil families achieved early oil window maturity in the range of 0.6%–0.7% equivalent vitrinite reflectance. The offshore oil samples consist of one family from Point Pedernales field and two families from the “B” prospect. Geochemical characteristics of these families indicate origins under differing water column and sediment oxicity and carbonate versus siliceous and detrital input in ‘carbonate,’ ‘marl,’ and ‘shale’ organofacies like those in the lower calcareous–siliceous, carbonaceous marl, and clayey–siliceous members of the Monterey Formation elsewhere in coastal California. The corresponding lithofacies and organofacies appear to be linked to the early–middle Miocene climate optimum and subsequent paleoclimatic cooling after circa 14 Ma, a systematic up-section increase in the stable carbon isotope composition of related oil samples, decreased preservation of calcium carbonate shells from planktic foraminifera and coccoliths, and increased preservation of clay-sized siliceous shells of diatoms and radiolarians. The results show that organofacies within the Monterey source rock are responsible for many of the geochemical differences between the oil families. This paleoclimate–organofacies model for crude oil from the Monterey Formation can be used to enhance future exploration efforts in many areas of coastal California.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Twenty-four oils produced from the Woodford Shale and overlying Mississippian strata in central Oklahoma were characterized geochemically to determine their possible source(s). The 168 core samples from the Woodford and Mississippian sections of 14 wells in central Oklahoma were initially characterized by total organic carbon (TOC), Rock-Eval, and vitrinite reflectance, and select samples (TOC 〉 1.0 wt. %) were subjected to biomarker analyses to characterize source input, depositional environment, maturity, and oil-to-source rock correlations. Thermal maturity parameters indicate the Woodford Shale is immature to marginally mature in Payne County, Oklahoma, and shows a progressive increase in maturity toward the southwest. Close to the Nemaha uplift, the Woodford is in the main stage of oil generation. It is proposed that the oils in this area have three possible origins: (1) Oils produced from the Woodford and overlying Mississippian strata have similar fingerprints, suggesting the Woodford Shale and overlying Mississippian strata are in communication; (2) oils produced near the Nemaha uplift (Logan and western Payne Counties) were sourced from the Woodford but had a significant Mississippian source contribution based on source-specific biomarkers; (3) oils east of the Cherokee platform (eastcentral Payne County) share strong Woodford source characteristics, and they were not generated in situ from the immature Woodford Shale but probably migrated from the Woodford Shale in the deeper part of the Anadarko Basin in southern Oklahoma. These results are consistent with the findings that indicate abundant marine coarse-grained biogenic silica (radiolarian-rich) chert facies found in eastcentral Payne County may contribute to good reservoir petrophysical properties, suggesting the Woodford Shale may not be a source in this area but simply a tight reservoir.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Primary depositional mineralogy has a major impact on sandstone reservoir quality. The spatial distribution of primary depositional mineralogy in sandstones is poorly understood, and consequently, empirical models typically fail to accurately predict reservoir quality. To address this challenge, we have determined the spatial distribution of detrital minerals (quartz, feldspar, carbonates, and clay minerals) in surface sediment throughout the Ravenglass Estuary, United Kingdom. We have produced, for the first time, high-resolution maps of detrital mineral quantities over an area that is similar to many oil and gas reservoirs. Spatial mineralogy patterns (based on x-ray diffraction data) and statistical analyses revealed that estuarine sediment composition is primarily controlled by provenance (i.e., the character of bedrock and sediment drift in the source area). The distributions of quartz, feldspar, carbonates, and clay minerals are controlled by a combination of the grain size of specific minerals (e.g., rigid vs. brittle grains) and estuarine hydrodynamics. The abundance of quartz, feldspar, carbonates, and clay minerals is predictable as a function of depositional environment and critical grain-size thresholds. This study may be used, by analogy, to better predict the spatial distribution of sandstone composition and thus reservoir quality in ancient and deeply buried estuarine sandstones.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Petroleum types in the Eagle Ford resource play span the range from black oil to dry gas and are produced along regional trends that are largely maturity controlled. A total of 61 shale samples covering all maturity zones were evaluated to document organic richness, organic matter type, and maturation characteristics using established geochemical parameters. Pyrolysis experiments were then performed to simulate the generation of petroleum fluids. Termed the “PhaseSnapShot” approach, one or more target wells with known fluid properties were used as reference; a match with that composition was made using next-formed fluids generated from the shale in a closely located well of slightly lower thermal maturity than the target well(s). Phase behavior predictions from the model were calibrated using a regional pressure–volume–temperature (PVT) database compiled from the public domain. The conceptual model that best matched the PVT data were comprised of two reactive components: (1) a mixture of kerogen and bitumen that generated petroleum within the low permeability shale matrix and (2) bitumen in zones of enhanced porosity within the matrix. The combined generation of gas from both of these components as well as the strong retention of C〈sub〉7+〈/sub〉 fluids in the matrix during production were required to match the calibration data. Retention of oil was needed over a broad thermal maturity range (Rock-Eval 〈span〉Tmax〈/span〉 release: 440°C –475°C). A key result of this forward model is that phase behavior and bulk compositional properties of hydrocarbons can be quickly and effectively predicted using mature shale samples as long as calibration data from PVT reports are available.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Mapping of seismic and lithological facies is a very complex process, especially in regions with low seismic resolution caused by extensive salt layers, even when only an exploratory view of the distribution of the reservoir facies is required. The aim of this study was to apply multi-attribute analysis using an unsupervised classification algorithm to map the carbonate facies of an exploratory presalt area located in the Outer high region of the Santos Basin. The interval of interest is the Barra Velha Formation, deposited during the Aptian, which represents an intercalation of travertines, stromatolites, grainstones and spherulitic packstones, mudstones, and authigenic shales, which were deposited under hypersaline lacustrine conditions during the sag phase. A set of seismic attributes, calculated from a poststack seismic amplitude volume, was used to characterize geological and structural features of the study area. We applied k-means clustering in an approach for unsupervised seismic facies classification. Our results show that at least three seismic facies can be differentiated, representing associations of buildup lithologies, aggradational or progradational carbonate platforms, and debris facies. We quantitatively evaluated the seismic facies against petrophysical properties (porosity and permeability) from available well logs. Seismic patterns associated with the lithologies helped identify new exploration targets.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Dibei gas field is a large tight gas field located in the Kuqa subbasin, Tarim Basin, northwestern China. The reservoir is within the Lower Jurassic Ahe Formation (J〈sub〉1〈/sub〉a) and has porosity and permeability ranges of 2%–8% and 0.01–1 md, respectively. Two episodes of hydrocarbon charge are identified based on a detailed study of fluid-inclusion petrography and microthermometry, fluorescence spectroscopy characteristics, and the thermal maturity of both gas and light oil. Low-maturity oil as represented by hydrocarbon inclusions with yellow-green fluorescence entered the reservoir circa 23–12 Ma, whereas high-maturity hydrocarbons, as indicated by hydrocarbon inclusions with blue-white fluorescence, have charged the reservoir since 5 Ma. The hydrocarbon charge process combined with porosity evolution determined the present gas–water distribution characteristics in the Dibei gas field. Porosity in the J〈sub〉1〈/sub〉a sandstone reservoir was relatively high during the first episode of hydrocarbon charge, which allowed oil to migrate upward and accumulate in structural highs under buoyancy. From 5 Ma to the present, the Dibei gas field experienced strong tectonic compression associated with intense thrust-fault reactivation, causing deformation and oil leakage from the reservoir. Continuous tight sand deposits along the slope areas, located far away from the active faults, became favorable accumulation sites for gas derived from the underlying Triassic source rocks. Hydrocarbon accumulation along the slope area in the Ahe Formation is dominantly controlled by equilibrium between hydrocarbon-generation pressure and capillary pressure.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉This study examines the influences on fluid flow within a shale outcrop where the networks of two distinct paleoflow episodes have been recorded by calcite-filled veins and green alteration halos. Such direct visualization of flow networks is relatively rare and provides valuable information of fluid-flow behavior between core and seismic scale.Detailed field mapping, fracture data, and sedimentary logging were used over a 270 m〈sup〉2〈/sup〉 (2910 ft〈sup〉2〈/sup〉) area to characterize the paleo–fluid-flow networks in the shale. Distal remnants of turbidite flow deposits are present within the shale as very thin (1–10 mm [0.04–0.4 in.]) fine-grained sandstone bands. The shale is cut by a series of conjugate faults and an associated fracture network, all at a scale smaller than seismic detection thresholds. The flow episodes used fluid-flow networks consisting of subgroups of both the fractures and the thin turbidites. The first fluid-flow episode network was mainly comprised of thin turbidites and shear fractures, whereas the network of the second fluid-flow episode was primarily small joints (opening mode fractures) connecting the turbidites.The distribution of turbidite thicknesses follows a negative exponential trend. which reflects the distribution of thicker turbidites recorded in previous studies. Fracture density varies on either side of faults and is highest in an area between closely spaced faults. Better predictions of hydraulic properties of sedimentary-structural networks for resource evaluation can be informed from such outcrop subseismic scale characterization. These relationships between the subseismic features could be applied when populating discrete fracture networks models, for example, to investigate such sedimentary-structural flow networks in exploration settings.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The middle Cambrian Maryville–Basal sands in the interval of 4600–4720 ft (1402.1–1438.7 m) in the Kentucky Geological Survey 1 Hanson Aggregates well (i.e., muddy sandstones separated by sandy mudstones) were evaluated to determine effective porosity (ϕ〈sub〉〈span〉e〈/span〉〈/sub〉), clay volume (〈span〉Vc〈/span〉), and supercritical CO〈sub〉2〈/sub〉 storage capacity. Average porosity and permeability measured in core plugs were 8.71% porosity and 2.17 md permeability in the Maryville sand and 10.61% porosity and 15.79 md permeability in the Basal sand. The ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 were calculated from the density log using a multiple-matrix shaly sand model to identify four formation lithologies: muddy sandstone, sandy mudstone, dolomitic mudstone, and dolomitic claystone. Average ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 calculated in the Maryville sand were 8.9% and 35.3%, respectively, and an average of 8.7% and 41.2% in the Basal sand, respectively. Calculated ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 exhibits a good match with porosity measured in core plugs. Prior to step-rate testing, static reservoir pressure was 2020 psi (13.9 MPa), representing a 0.435 psi/ft (9.8 kPa/m) hydrostatic gradient, which is consistent with other underpressured reservoirs in Kentucky. The interval fractured at 2698 psi (18.0 MPa), yielding a fracture gradient of 0.581 psi/ft (12.7 kPa/m). Pressure falloff analysis suggests a dual-porosity/dual-permeability reservoir consistent with core data. Estimated 50th percentile supercritical CO〈sub〉2〈/sub〉 storage volume supercritical CO〈sub〉2〈/sub〉 storage volume, using 7% porosity cutoff for determining net reservoir volume, is 0.538 tons/ac (1.33 t/ha). Thin reservoir sands, low porosity and permeability, and low fracture gradient, however, preclude the Maryville–Basal sands as large-volume deep-saline CO〈sub〉2〈/sub〉 storage reservoirs in this area.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Porosity–permeability transforms were generated using an extensive data set covering two oil-bearing formations in Ohio: the Clinton Sandstone in eastern Ohio and the Copper Ridge Dolomite in central Ohio. The reservoirs were selected because of their historical importance as oil producers and their potential as targets for CO〈sub〉2〈/sub〉 use for enhanced oil recovery and associated geological storage. The porosity-permeability transforms generated in this study have coefficients of determination that are nearly double those in the published literature. Methods applying other information (e.g., lithofacies type and reservoir depth) to improve the transforms are also discussed. Ultimately, it was determined that although subdividing the Clinton Sandstone data by geologically similar areas constrained the porosity and permeability values, the data for most areas were too limited to yield robust correlations. Thus, the range of possible outcomes should be determined using the transform derived from all available data. The Copper Ridge values were largely not constrained when subdivided by depth.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Pennsylvanian–Middle Triassic Cooper Basin is Australia’s premier conventional onshore hydrocarbon-producing province. The basin also hosts a range of unconventional gas play types, including basin-centered gas and tight gas accumulations, deep dry coal gas associated with the Patchawarra and Toolachee Formations, and the Murteree and Roseneath shale gas plays.This study used petroleum systems analysis to investigate the maturity and generation potential of 10 Permian source rocks in the Cooper Basin. A deterministic petroleum systems model was used to quantify the volume of expelled and retained hydrocarbons, estimated at 1272 billion BOE (512 billion bbl and 760 billion BOE) and 977 billion BOE (362 billion bbl and 615 billion BOE), respectively. Monte Carlo simulations were used to quantify the uncertainty in volumes generated and to demonstrate the sensitivity of these results to variations in source-rock characteristics.The large total generation potential of the Cooper Basin and the broad distribution of the Permian source kitchen highlight the basin’s significance as a world-class hydrocarbon province. The large disparity between the calculated volume of hydrocarbons generated and the volume so far found in reservoirs indicates the potential for large volumes to remain within the basin, despite significant losses from leakage and water washing. The hydrocarbons expelled have provided abundant charge to both conventional accumulations and to the tight and basin-centered gas plays, and the broad spatial distribution of hydrocarbons remaining within the source rocks, especially those within the Toolachee and Patchawarra Formations, suggests the potential for widespread shale and deep dry coal plays.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The strike-slip fault systems in the central Tarim Basin, China, afford an exceptional opportunity to document the structural characteristics and evolution process of small displacement intracratonic strike-slip faults using three-dimensional seismic reflection data. These strike-slip faults display subvertical segments at depth and en echelon normal fault zones where relatively shallow. Fault segmentation and flower structures can be commonly observed in plan view and cross-section view, respectively.Consistent with the notion that segment coalescence is the fundamental process for fault evolution, the mean segment length of representative strike-slip faults examined in this study is positively correlated to the measured fault offset. The width of the en echelon normal fault zone is positively correlated with the estimated maximum overburden thickness. The integrated data sets suggest that the evolution of the conjugate fault array followed a sequential evolution process instead of forming simultaneously. The switch in slip direction of the master fault of the conjugate fault array is attributed to the change of stress orientation. Regarding individual strike-slip faults, increase in displacement induces the formation of faults with lower fault-array angles linking initially formed en echelon normal faults. In cross sections, throughgoing fault surfaces can also form, connecting the lower subvertical fault segment and the upper en echelon normal faults.The presented data sets and evolution models established in this study can be used as tools to better predict the structural attributes of subsurface strike-slip fault systems with important consequences for reservoir formation and hydrocarbon accumulation in the Tarim Basin in particular, and in ancient marine basins in general.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Static formation temperature (〈span〉SFT〈/span〉) can be estimated from temperatures measured during wire-line logging (〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉). A large number of correction models for obtaining 〈span〉SFT〈/span〉 from 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 have been suggested. Several studies have shown that 〈span〉SFT〈/span〉s yielded by such models are off by an average of 6°C–10°C (43°F–50°F) at burial depths of 1.5–3.5 km (0.9–2.2 mi) and thus have the potential to cause serious issues in thermal and hydrocarbon generation models. This paper explores the causes for erroneous 〈span〉SFT〈/span〉 predictions generated from 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 measurements and identifies factors that should be addressed to generate a globally applicable correction model. We also present an improved empirical correction model for 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 data from eight oil and gas fields, located on the Norwegian continental shelf. The new empirical model was designed to give correct average 〈span〉SFT〈/span〉 predictions and is applicable to single 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 measurements. It has been validated against temperatures recorded during drill-stem testing, which closely represent local 〈span〉SFT〈/span〉s. The expression yields improved results compared with other correction models applied to the data set. However, the average error in computed 〈span〉SFT〈/span〉 values varies by up to 10°C (18°F) between the investigated hydrocarbon fields. We conclude that these variations result from differences in operational practices such as fluid circulation and drilling velocities. Therefore, current empirical and physical models for 〈span〉SFT〈/span〉 prediction from 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 require local calibration. It is also suggested that more accurate compilations and analyses of operational data could lead to improved and more globally applicable models.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The petroleum system concept spans the spatial and temporal extent of all elements and processes required for the generation and preservation of petroleum. The critical moment of a petroleum system is the moment with the highest probability for the generation–migration–accumulation of hydrocarbons. It is an important concept in petroleum exploration risk assessment because the stratigraphic and geographic extents of a petroleum system are determined at the critical moment. In petroleum systems, thermal history data, burial history data, and vitrinite reflectance data may be unavailable, unreliable, or incomplete; this introduces significant uncertainty in the choice of the critical moment. We present here a quantitative probabilistic framework for estimating the critical moment and quantifying the associated uncertainty in such cases. We define a probabilistic early bound and late bound for the critical moment (which, combined together, we term the critical range) and then estimate the moment with the highest numerical probability of generation–migration–accumulation. We define the uncertainty associated with the critical moment as half the absolute value of the critical range. In cases with little ambiguity or duplicity in the timing of petroleum system elements and processes, the critical range converges to one point, which is also the critical moment. The probabilistic framework introduces consistency to the critical moment estimation problem and quantifies the level of uncertainty in the estimation. This reduces the risk involved in petroleum exploration assessment.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Very limited literature is available relating to gas production from ultradeep (〉9000 ft [〉2700 m]) coal seams. This paper investigates permeability enhancement in ultradeep coal seams of the late Carboniferous and early Permian to Late Triassic Cooper Basin in central Australia, using a time-lapse pressure transient analysis (PTA) approach for a pilot well. The gas production history and three extended shut-in periods are used to construct the time-lapse PTA for the study well. A new approach is introduced to construct a permeability ratio function. This function allows the calculation of permeability change resulting from competition between the compaction and coal-matrix shrinkage effects.Pressure transient analysis indicates that gas flow is dominated by a bilinear flow regime in all extended pressure buildup tests. Hence, reservoir depletion is restricted to the stimulated area near the hydraulic fracture. This implies that well-completion practices that create a large contact area with reservoirs, such as multistage hydraulically fractured horizontal wells, may be required for achieving economic success in these extremely low-permeability reservoirs. The permeability ratio is constructed using the slope of the straight lines in bilinear flow analysis. Because of uncertainty in average reservoir pressure, probabilistic analysis is used and a Monte Carlo simulation is performed to generate a set of possible permeability ratio values. The permeability ratio values indicate that coal permeability has increased during the production life of the wellbore because of the coal-matrix shrinkage effect. Permeability enhancement in this ultradeep coal reservoir has offset the effect of permeability reduction caused by compaction, which is beneficial to gas production.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Nanometer to micrometer mica and illite separates of indurated Cambrian and Ordovician oil-bearing sandstones from the Hassi Messaoud field (Algeria) were extracted, x-rayed, observed by scanning and transmission electron microscopy, and K-Ar dated. Electron microscope observations revealed typical euhedral shapes for the mica to illite particles of most size fractions; almost no odd-shaped detrital crystals were detected. The combined results document several generations of mineralogical and morphological identical mica to illite crystals that could not be differentiated by the traditional identification methods. Illite and mica genesis was multiphased with crystallization episodes at 340 ± 10 (ca. Middle Mississippian), 280 ± 10 Ma (ca. early Permian), and 170 ± 10 Ma (ca. Middle Jurassic). Younger than the stratigraphic age of the host rocks, which is incompatible with a detrital origin, the two older mica ages confirm that the hydrocarbon generation and emplacement had to start after the Variscan tectonothermal event and before exhumation of the meta-sediments. The younger K-Ar ages at 135 to 110 Ma (ca. Early Cretaceous) relate to further crystallization episodes, whereas those at circa 295, 265, and 210 Ma probably correspond to variable mixtures of the older and younger mica to illite end-members. Three average K-Ar values are statistically significant: the oldest at 340 ± 10 Ma corresponds to the start of the Variscan tectonic activity, and the intermediate at 280 ± 10 Ma sets its end, both episodes probably modifying the reservoir capacities of the potential hydrocarbon host rocks. The ages at 170 ± 10 Ma identify a further diagenetic activity characterized by illitization of dickite-type precursors in local reservoirs. These younger ages could correspond to the hydrocarbon charge into reservoirs, which stopped diagenetic illitization at a present-day depth of approximately 4000 m (∼13,000 ft).〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉This paper analyzes regional hydrogeological conditions and divides the study area into three hydrogeological types and seven hydrogeological units, to investigate hydrogeology and its effect on coalbed methane (CBM) enrichment in the southern Junggar Basin, China. From this work, it is found that the groundwater flow paths in the study area are the joint effects of south-to-north and west-to-east flows. This study also shows that microbial gases are widely developed, although the depth limit of microbial gas occurrence is still unclear in the study area. Microbial CO〈sub〉2〈/sub〉 reduction is the leading formation path in the study area, except for the Houxia region, where fermentation is the formation mechanism. The abnormally high CO〈sub〉2〈/sub〉 in stagnant zones (i.e., water flow is slow and stagnant) is mainly associated with methanogenesis, whereas relatively low CO〈sub〉2〈/sub〉 (microbial or thermogenic) is present where water flow is active. The average CBM content within the Xishanyao Formation changes within various hydrogeological units; moreover, the average CBM content within the Badaowan Formation of the same hydrogeological unit (e.g., Fukang) suggests that the hydrogeological and CBM enrichment conditions are different within various structural types. Overall, the hydrogeological conditions exert control on the gas content in the study area; that is, the gas content is high in stagnant zones. Finally, influenced by supplemental microbial gases, changes in the CBM oxidation zone are relatively complex in the study area, the depth of which has no obvious correlation with hydrogeological conditions and changes significantly from west to east.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉How and when sediment moves from terrestrial sources to deep-water sinks is a significant area of research. We have used an array of seismic, borehole, and gravity core data sets to explore the timing and magnitude of sediment-routing to Pearl River slope over the last 478 k.y. As predicted by existing sequence stratigraphic models, most sediment dispersal to deep water is shown to have occurred during glacial sea-level falls; however, clastic detritus was still being transported into deep water during interglacial sea-level rises. We suggest that sediment routing to deep water during interglacial sea-level rise is caused by summer monsoon strengthening and resultant warmer and wetter climates, both of which have enhanced effective precipitation and sediment supply. Although some models for the delivery of sediment to deep-water basins stress the importance of proximity of canyon heads and coeval shorelines, we observed that sediment routing to deep water could occur regardless of the distance between channel head and coeval shorelines. In the present case, the success of delivery is related to the combined effects of (1) the short duration and high amplitude of sea-level oscillations during the past 478 k.y. and (2) the enhanced sediment supply caused by more humid climates and greater temperature difference between glacial and interglacial period. This hypothesis is supported by (1) observations that outer Pearl River deltas prograded as an apron over preexisting shelf edges for 10–15 km (6–9 mi) and (2) the occurrence of slope channels extending back to prodelta reaches of Pearl River shelf-edge deltas.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The discovery of carbonate gas fields in the Middle Triassic Leikoupo Formation of the Sichuan Basin has a complex history. In recent years, a series of structural fields have been discovered in the western Sichuan Basin. Their discovery confirms the immense exploration potential of the Leikoupo Formation. In this study, we analyze the characteristics of Leikoupo Formation exploration plays using exploration wells and test data, aiming to provide a reference for further discoveries. The Leikoupo Formation represents the uppermost unit in the Sichuan marine carbonate platform succession. During its deposition, the whole basin was characterized by a restricted and evaporitic platform. Two classes of reservoirs developed. One is pore–fracture reservoirs, in marginal platform and intraplatform shoals, and another is fracture–vug reservoirs in the karstic weathering crust of the formation-capping unconformity. Three hydrocarbon accumulation models were established for the Leikoupo Formation based on the spatial and temporal relationship among the source, reservoir, and cap rocks. Two types of exploration plays are present in the Leikoupo Formation, that is, shoal (including intraplatform shoal and marginal platform shoal) dolomite plays and karstic dolomite weathering crust plays (including intraplatform shoal karst and marginal platform shoal karst). The western Sichuan depression in the karstic slope belt presents immense exploration potential because of a proximal hydrocarbon supply, charging via an extensive fracture network, shoals and karstic reservoir, a good seal rock of terrestrial mudstone, and potential composite hydrocarbon accumulations in stratigraphic traps, making it a promising area for future exploration.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Carbonaceous debris (CD) within uranium-bearing strata has been studied in the Daying uranium deposit of the northern Ordos Basin, northern China. The influence of radiogenic heat from uranium on organic matter maturation was investigated through a series of tests including measurements of vitrinite reflectance (〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉), fission-track (FT) analysis in quartz grains, and the calculation of the radiogenic heat production rate of the samples. The results show that 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 in uranium-bearing strata generally increases as the burial depth increases, indicating that CD experienced normal burial coalification. However, 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 values of the samples rich in uranium are 0.062% 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 higher than those without uranium mineralization. Vitrinite reflectance bears a positive relationship with uranium content, and an inverse relationship with distance to the closest sandstone rich in uranium, indicating that uranium enrichment enhances organic matter maturation. The production of uranium decay makes FT observable in quartz grains, and the intensity of decay increases with proximity to the uranium ore body. The calculated radioactive heat production rate from the uranium ore body is 6.857 × 10〈sup〉−5〈/sup〉 W/m〈sup〉3〈/sup〉. During the long-term stable decay, as the uranium ore body theoretically results in an abnormal increase in temperature of 52°C without consideration of the loss of heat conduction, heat convection, and thermal radiation, this would yield a theoretical 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 increase of 0.209% 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉, reasonably greater than the observed. Therefore, the long-term stable radiogenic heat produced by uranium ore body can slightly enhance organic matter maturation, which is instructive in uranium prospecting.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The purpose of this study is to deconstruct the relationship between the Leaf River anticline and the preglacial bedrock paleotopography at the eastern terminus of the Plum River Fault Zone in Ogle County, Illinois, using a geostatistical approach. The contour maps derived from the elevation models provided detailed depictions of the ancient bedrock landscape and subsurface structure in the study area. The Leaf River anticline is interpreted to be a component of hanging-wall anticline at the terminus of the Plum River Fault Zone. The topographic high created by the anticline controlled local drainage and led to the development of the Leaf River paleovalley prior to the Pleistocene. The catastrophic failure of an ice damn during the Illinois glacial episode carved a glacial spillway into the north flank of the Leaf River anticline that interfaced with a tributary of the Leaf River paleovalley. This rerouted the preglacial drainage network and permanently diverted the ancient Rock River to its modern-day position. Ultimately, the subsurface geometry of the Leaf River anticline and its relationship to the local bedrock paleotopography were revealed by the elevation models. The position and development of the Leaf River paleovalley and glacial spillway interpreted in this study aligned with the regional interpretations for the evolution of the ancient bedrock landscape established in prior works. However, this study revealed that the Leaf River anticline and, by association, the terminus of the Plum River Fault Zone extend farther east into the region than indicated by prior works.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In the last decade, production of shale gas has tremendously increased, and the need for local pre-exploitation baseline data on dissolved natural gas in aquifers has been stressed. This study investigated the origin of hydrocarbons naturally present in shallow aquifers of the Saint-Édouard area (Québec, eastern Canada), where the underlying Utica Shale is known to contain important gas resources that have not yet been exploited. Groundwater and shallow bedrock gas samples were collected and analyzed for isotopic composition of alkanes (δ〈sup〉13〈/sup〉C and δ〈sup〉2〈/sup〉H〈sub〉C1–C3〈/sub〉), dissolved inorganic carbon (δ〈sup〉13〈/sup〉C〈sub〉DIC〈/sub〉), and radiocarbon in methane and DIC (〈sup〉14〈/sup〉C〈sub〉DIC〈/sub〉, 〈sup〉14〈/sup〉C〈sub〉CH4〈/sub〉). This multi-isotope approach proved enlightening, and results revealed that (1) most of the methane in the region is of microbial origin; (2) partial contribution of thermogenic gas occurs in 15% of the wells; (3) processes such as late-stage methanogenesis and methane oxidation are responsible for ambiguous methane isotopic compositions; and (4) both microbial and thermogenic gas originate from the shallow bedrock aquifer, with the exception of one sample likely coming from deeper units. The thick succession of shales overlying the Utica Shale thus appears to act as an effective migration barrier for the shallow aquifers. However, evidence of upward migration of old brines near major fault zones indicates that these may serve as a preferential migration pathway over a certain depth but most likely no more than approximately 200–500 m (∼650–1640 ft). The geochemical framework presented here will hopefully be useful in other research projects, especially when conventional indicators of natural gas origin provide ambiguous results.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Urbanization modifies the natural water cycle. In this study, a weighted-rating multicriteria analysis was adopted to quantify the runoff index and to assess the impact of urbanization on the water cycle. The considered parameters are (1) slope, (2) permeability of soil, and (3) rainfall. Using the land use map, a runoff risk map was established. The approach was applied to Manouba catchment. The main results revealed that between 2004 and 2014, the area with a high runoff index increased from 32% to 39%. The runoff risk increased; in 2004, the high class covered 18% of the watershed area. This value became 30% in 2014. Results demonstrate that urbanization affects hydrological processes. This method is appropriate in other similar watersheds to estimate the runoff index.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉To better understand controls on the origin and evolution of brackish groundwater, the hydrogeochemistry of brackish groundwaters was studied within the Triassic Dockum Group across the Midland Basin in Texas. The suitability of Dockum Aquifer water for use in hydraulic fracturing fluid was examined because the area overlies the largest and most productive tight oil province in the United States. Groundwater generally flows southward and eastward across the basin. Transmissivities indicate that water yield from the Dockum Aquifer is mixed. Higher salinity (up to ∼100 g/L), group I water is found mainly in the center and western parts of the basin; chemistry of these meteoric waters is controlled by water–rock interaction with salinity increasing along its flow path via dissolution of halite and anhydrite, followed by salinity-enhanced carbonate dissolution and/or cation release from clays. Along the down-gradient basin margins, lower salinity (〈7.5 g/L), group II waters of various ion compositions are more commonly found. Group II waters are also meteoric but from local recharge including downward flow from the Edwards–Trinity or other aquifers. Despite having lower salinity, the water in the down-gradient southern and eastern margins of the basin can exceed acceptable SO〈sub〉4〈/sub〉 limits for cross-linked gel fluids. Generally, the majority of the water in the basin is suitable for use with slick-water hydraulic fracturing. Findings from this research provide important information on the complex controls on the chemistry of brackish groundwater and their potential beneficial uses in the oil and gas industry.〈/span〉

Description: Tidal heterolithic sandstones are commonly characterized by millimeter- to centimeter-scale intercalations of mudstone and sandstone. Consequently, their effective flow properties are poorly predicted by (1) data that do not sample a representative volume or (2) models that fail to capture the complex three-dimensional architecture of sandstone and mudstone layers. We present a modeling approach in which surfaces are used to represent all geologic heterogeneities that control the spatial distribution of reservoir rock properties (surface-based modeling). The workflow uses template surfaces to represent heterogeneities classified by geometry instead of length scale. The topology of the template surfaces is described mathematically by a small number of geometric input parameters, and models are constructed stochastically. The methodology has been applied to generate generic, three-dimensional minimodels (9 m 3 [~318 ft 3 ] volume) of cross-bedded heterolithic sandstones representing trough and tabular cross bedding with differing proportions of sandstone and mudstone, using conditioning data from two outcrop analogs from a tide-dominated deltaic deposit. The minimodels capture the cross-stratified architectures observed in outcrop and are suitable for flow simulation, allowing computation of effective permeability values for use in larger-scale models. We show that mudstone drapes in cross-bedded heterolithic sandstones significantly reduce effective permeability and also impart permeability anisotropy in the horizontal as well as vertical flow directions. The workflow can be used with subsurface data, supplemented by outcrop analog observations, to generate effective permeability values to be derived for use in larger-scale reservoir models. The methodology could be applied to the characterization and modeling of heterogeneities in other types of sandstone reservoirs.

Description: Tidal heterolithic sandstone reservoirs are heterogeneous at the submeter scale because of the ubiquitous presence of intercalated sandstone and mudstone laminae. Core-plug permeability measurements fail to sample a representative volume of this heterogeneity. Here, we investigate the impact of mudstone drape distribution on the effective permeability of heterolithic, cross-bedded tidal sandstones using three-dimensional, surface-based "minimodels" that capture the geometry of cross beds at an appropriate scale. The impact of seven geometric parameters has been determined: (1) mudstone fraction, (2) sandstone laminae thickness, (3) mudstone drape continuity, (4) toeset dip, (5) climb angle of foreset–toeset surfaces, (6) proportion of foresets to toesets, and (7) trough or tabular geometry of the cross beds. We begin by identifying a representative elementary volume of 1 m 3 (~35 ft 3 ), confirming that the model volume of 9 m 3 (~318 ft 3 ) yields representative permeability values. Effective permeability decreases as the mudstone fraction increases, and it is highly anisotropic: vertical permeability falls to approximately 0.5% of the sandstone permeability at a mudstone fraction of 25%, whereas the horizontal permeability falls to approximately 5% and approximately 50% of the sandstone value in the dip (across mudstone drapes) and strike (parallel to mudstone drapes) directions, respectively. Considerable spread exists around these values, because each parameter investigated can significantly impact effective permeability, with the impact depending upon the flow direction and mudstone fraction. The results yield improved estimates of effective permeability in heterolithic, cross-bedded sandstones, which can be used to populate reservoir-scale model grid blocks using estimates of mudstone fraction and geometrical parameters obtained from core and outcrop-analog data.

Description: Fault damage zones in porous sandstones commonly exhibit networks of deformation bands reflecting crushing and reorganization of grains associated with small-scale, localized displacement. Deformation bands introduce anisotropic, order-of-magnitude reduction of effective permeability, which will affect fluid flow in reservoir rocks. We here present a method for incorporating these features in industrial-type reservoir models. The method involves the use of a three-dimensional fault zone grid generation technique that allows property modeling on a discrete high-resolution fault zone grid without refining the entire reservoir model. Deformation band data from 106 outcrop scan lines of fault damage zones were classified into discrete fault facies defined according to deformation band density. The distributional pattern of fault facies in the data exhibits recurrent spatial relationships, which could be reproduced using truncated Gaussian simulation in the modeling process. The frequency distribution of deformation band density for each facies was analyzed, and average density values were assigned to each facies for calculating cell permeability. Permeability anisotropy was handled by approximating the relationship between deformation band densities in different directions based on published high-resolution fault zone maps and cross sections. Fluid-flow simulations were carried out on several damage zones models, and results were benchmarked against models with conventional fault rendering without damage zones. Simulation results show that flow paths, remaining oil distribution, and reservoir responses in models incorporating damage zones deviate from models employing conventional fault representation without damage zones, and these differences increase as deformation band permeability decreases.

Description: Rock-based studies of the Eagle Ford Group of Central Texas demonstrate that mudrock deposition is more complicated than previously supposed. X-ray diffraction, x-ray fluorescence, total organic carbon (TOC), and log data collected from eight cores and two outcrops demonstrate that bottom-current reworking and planktonic productivity are primary depositional controls, acting independently from eustatic forcing. Central Texas Eagle Ford facies include (1) massive argillaceous mudrock, (2) massive foraminiferal calcareous mudrock, (3) laminated calcareous foraminiferal lime mudstone, (4) laminated foraminiferal wackestone, (5) cross-laminated foraminiferal packstone–grainstone, (6) massive bentonitic claystone, and (7) nodular foraminiferal packstone–grainstone. High degrees of lateral facies variability, characterized by pinching and swelling of units, lateral facies changes, truncations, and locally restricted units, are observed even at small lateral scales (50 ft [15 m]). At 10 mi (16 km) and greater lateral spacings, core and geochemical data significantly underestimate intraformational facies variability. Approximately 73% of units can be successfully correlated across a distance of 500 ft (152 m), 35% are traceable across 1 mi (1.6 km), and only 16% of beds are correlative across 10 mi (16 km). Geochemical proxies (enrichment in molybdenum and other trace elements) indicate that maximum anoxia occurred within the Bouldin Member despite being composed of the most calcareous and high-energy facies. Comparison of total gamma ray (GR) logs to computed GR logs is requisite, because GR alone may provide misleading determination of facies, TOC content, depositional environment, and sequence stratigraphic implications.

Description: Studies suggest that nanometer-scale pores exist in organic matter as a result of thermal decomposition of kerogen. Depending on the host rock lithology, organic pores could be the primary storage for hydrocarbon accumulation in unconventional petroleum plays. Although various methods are publicly available, estimation of organic porosity remains a challenge because the procedures involve certain simplification or some implicit assumptions on the calculation of initial total organic carbon (TOC). In this study, we propose a revised method to address some of these issues. A model of estimating hydrocarbon expulsion efficiency is developed and incorporated into the calculation of initial TOC, thus producing an estimate of organic porosity with an improved mass balance. The method has been tested and compared with estimates using other methods based on a Rock-Eval data set in the literature. An application of the method to a large data set from the Upper Devonian Duvernay Formation petroleum system in the Western Canada Sedimentary Basin reveals that the modification has a significant effect on the estimated organic porosity. This study also indicates that organic porosity in the Duvernay Formation ranges greatly from none in immature intervals to 〉6% in highly mature and organic-rich shale intervals. Scanning electron microscope images of immature and mature organic-rich shale samples of the Duvernay Formation show a progressive increase in organic porosity with increasing thermal maturity, supporting the proposed model calculation. The presence of a large volume of organic porosity in mature shale intervals suggests a significant amount of hydrocarbon may be stored in the organic nanopores in the Duvernay Formation.

Description: Hydrocarbon exploration in the Berkine–Ghadames Basin in southern Tunisia has generally followed global economic trends. In recent years, improvements in seismic data acquisition combined with experience gained in log interpretation in low-resistivity reservoirs have resulted in oil and gas discoveries in the Upper Silurian Acacus Formation, enriching the hydrocarbon potential of the Berkine–Ghadames Basin in southern Tunisia. Presently, the Tunisian daily oil production is approximately 43,000 bbl, about half of which comes from the fields located in southern Tunisia and is produced from the Acacus Formation. The Berkine–Ghadames Basin is an intracratonic basin formed during the Pan-African Orogeny. It covers an area of approximately 350,000 km 2 (135,135 mi 2 ) and extends into Algeria, Libya, and Tunisia. The sedimentary section within the basin ranges from Cambrian to present and is approximately 7000 m (23,000 ft) thick in the depocenter. The basin has experienced several tectonic events, which have modified its architecture and affected the petroleum systems and hydrocarbon pathways. In this study, the main elements of the petroleum geology systems are described. With the geochemical modeling results, the petroleum potential, hydrocarbon generation, expulsion time, and quantity of hydrocarbon are assessed. The main petroleum systems are also defined. They are represented by the Silurian Tannezuft hot shale source rock with Ordovician Djeffara and Silurian Acacus reservoirs, by Silurian Tannezuft hot shale with Kirchaou reservoirs, and by the Devonian Aouinette Ouinine Formation Member III source rock with Kirchaou reservoirs. The hydrocarbon traps in the area are mainly structural types. The study describes and emphasizes the hydrocarbon migration pathway mechanism from source rocks to traps. To predict and derisk future drilling locations, fairway maps are generated for the three plays: Ordovician, Silurian, and Triassic. Although the paper focuses on southern Tunisia, an attempt is made to introduce Libyan and Algerian knowledge to evaluate the basin in a regional context.

Description: The recognition, correlation, and quantification of oil mixtures remain challenging in petroleum system studies. Most prolific basins have multiple source rocks that generate petroleum over wide ranges of maturity. Compound-specific isotopic analyses of alkanes (CSIA-A) and diamondoids (CSIA-D) are very effective for determining hydrocarbon mixtures. Quantitative diamondoid analysis (QDA) and CSIA-D provide a unique advantage for source correlation of thermally altered liquids or condensates and for condensate mixtures with black oil. Biomarker fingerprints, QDA, and various CSIA methods were applied to 37 oil and condensate samples to investigate the existence of deep sources and to identify and deconvolute cosourced oil mixtures. The data were used to unravel the components of mixed oil having widely diverse levels of maturity in the north–central West Siberian basin. Three oil families and their locations are recognized in the basin. One of the families appears to be composed of oil mixtures derived from two end-member families that originated from the Upper Jurassic Bazhenov and Lower to Middle Jurassic Tyumen source rocks. Our results suggest that a significant part of the gas in the giant gas fields of north–central western Siberia (e.g., Urengoi and Yamburg) is of thermogenic origin. The source of this thermal gas, which was formerly assigned to various source origins, was determined to be the Tyumen Formation. Some samples in the basin also show mixtures of noncracked Bazhenov oil with cracked Tyumen condensate. The area where prevalent oil cracking has occurred was determined from QDA.

Description: The elemental chemostratigraphy of the Upper Cretaceous Niobrara Member of the Mancos Shale shows that six chemostratigraphic zones can be identified in the Piceance Basin, Colorado, based on geochemical data. Chemostratigraphic correlations of nine wells spaced 20 mi (~32 km) apart closely match lithostratigraphic correlations made using gamma-ray and deep-resistivity wireline logs. Lithologic interpretations made from wireline logs indicate that the Niobrara Member and equivalent strata consist primarily of interbedded calcareous shale and shaley limestone facies that increase in thickness to the northwest in the basin. The geochemical data suggest that during deposition of the Niobrara Member, anoxia and calcium enrichment increased to the east of the basin, whereas terrestrial input and clay enrichment increased to the northwest. Element crossplots suggest that a large part of the silicon is detrital and that the Niobrara Member becomes an increasingly more clastic than carbonate system to the west and northwest. The log R –derived total organic carbon (TOC) calculated using a sonic-resistivity overlay analysis technique shows that the Niobrara Member comprises organic-rich and organic-poor deposits. Average TOC values range between 1 wt. % (in organic-poor deposits) and 2.37 wt. % (in organic-rich deposits), with higher TOC values recorded in the southern and eastern parts of the basin. Relative-rock brittleness estimates from element and TOC data show the stratigraphic variability of alternating ductile (TOC rich, Ca and Si/Al poor) and brittle (TOC poor, Ca and Si/Al rich) intervals for the Niobrara Member.

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

Description: The Vaca Muerta–Quintuco system (uppermost lower Tithonian–lower Valanginian) is a thick shallowing-upward sedimentary cycle consisting of dark bituminous shales, marlstones, limestones, and sandstones, cropping out in the Neuquén Basin, west–central Argentina. This paper analyzes three outcrop sections in Chos Malal area, northem Neuquén province. Detailed facies analysis allows us to differentiate six facies associations, representing basinal to proximal outer ramp facies of a homoclinal carbonate ramp system (Vaca Muerta Formation) and basinal to shoreface facies of a mixed carbonate–siliciclastic shelf system (Quintuco Formation), prograding westward from the eastern margin of the basin. Two sequence hierarchies were recognized: 5 composite depositional sequences (third order) and 15 high-frequency sequences (fourth order). Fluctuations in organic matter content within the Vaca Muerta Formation suggest a relationship with depositional sequences, finding the highest values associated with transgressive systems tract, whereas the transition to the Quintuco Formation shows a strong decrease in total organic carbon. The x-ray diffraction studies show an increase of clay minerals and quartz in the transgressive systems tract of the Vaca Muerta Formation and an increase in the content of calcite in highstand systems tracts. This pattern is reversed in the Quintuco Formation. Our sequence stratigraphic approach contributes to the understanding of the relationship between organic matter, clay minerals, facies, stacking pattern, and relative sea level changes in this exceptional shale oil and shale gas unconventional reservoir. This study may be helpful for a better postulate of petrophysical and geomechanical models for unconventional exploration.

Description: Conduit fault zones and fault zones that can accommodate long-distance along-fault flow are well-documented phenomena. In reservoir simulation models, flow within these features is more correctly captured using volumetric representations of fault zones instead of employing standard two-dimensional fault planes. The present study demonstrates a method for generating fault envelope grids on full-field reservoir models, within which fault cores (i.e., regions where most of fault zone displacement is accommodated) are modeled. The modeled fault core elements are lenses and slip zones. They are defined as facies units and populated in the fault envelope grids using combined object-based simulation and deterministic techniques. Using the facies property, four reservoir simulation models are generated by modulating fault core thickness and slip zone type and permeability. Membrane slip zones (slip zones that act as partial barriers to fluid flow) cause the fault cores to form baffle–conduit systems. Along-strike positioned injector–producer pairs focus flow into the fault cores, decreasing sweep efficiency. In contrast, injected fluids of injector–producer pairs positioned to drain perpendicular to the fault cores are partitioned and distributed by the fault cores and therefore increase overall sweep efficiency. In reservoir models with conduit slip zones (slip zones that enhance flow along them and act as partial barriers to flow across them), the fault cores act as thief zones. Fluids preferentially move through the fault cores toward the nearby producers instead of through sedimentary layers with high permeability. Sweep efficiency in the reservoir models with conduit fault cores has less dependency on injector–producer configuration. Our study suggests that the improved realism added by incorporating volumetrically expressed fault cores substantially influences forecasts of field behavior and consequently should be considered during oil and gas production planning.