Abstract Typical meter-scale lithofacies cycles from the Wolfcamp A in the Delaware and Midland Basins comprise basal carbonate facies overlain by calcareous or siliceous mudrocks. Siliceous mudstones are the most organic-rich facies with high total organic carbon (TOC > 3 wt. %), whereas thin carbonate beds have the lowest organic matter (OM) content among the lithofacies present (TOC < 1 wt. %). To determine if the thin carbonate-rich beds serve as either reservoir storage for migrated oil or act as a seal, three core intervals of meter-scale lithofacies cycles in the Wolfcamp A were selected for sampling and were analyzed using x-ray diffraction analysis, TOC, programmed pyrolysis analysis, and residual gas analysis from rock crushing. Oil saturation index (OSI) (the amount of free oil normalized by TOC; OSI = S1 × 100/TOC) is used as an indicator of oil enrichment or depletion in the reservoir, where S1 is volatile oil in programmed pyrolysis (temperature = 300°C). Both TOC-lean carbonate and TOC-rich mudstone lithofacies have high OSI in these meter-scale cycles (average OSI is 124.5 mg HC/g TOC for carbonate beds), indicating that migrated oil is present. Residual gas analyses show lower dryness values (C1/C1–5) and higher oil indicator values (100 × C4+5/C1–5) in TOC-lean carbonate beds compared to the TOC-rich mudstones, likely indicating a cumulative oil and gas charging effect through source rock maturation. Oil and gas generated at different stages of thermal maturation were partially expelled from OM-rich siliceous/calcareous mudstones into adjacent OM-lean carbonate beds. This study shows oil expulsion from source to adjacent carbonate beds is a key factor in variations of oil saturation in the Wolfcamp A.

ABSTRACT Point-bar deposits, although readily recognizable in most successions, are notoriously challenging to map and correlate accurately, particularly in the subsurface. Sedimentologic interpretations from microresistivity image logs, by contrast, offer an unparalleled method of accurately reconstructing point-bar architectural elements and mapping their distribution. Using an example from the Lower Cretaceous McMurray Formation, we demonstrate that the bedding dip profiles of stacked downstream migration, lateral accretion, and channel abandonment elements record the semicontinuous point-bar accretion of two erosionally juxtaposed large-scale channels. Microresistivity image-log analysis clearly demonstrates that bedding and architectural elements of these heterolithic point bars display discrete and predictable changes in dip angle and direction that are independent of autogenic variations in lithology. We advocate, therefore, that this approach be used to map the facies of point bars and predict their reservoir trends. The laterally accreted mud-sand couplets display a cyclic pattern that is consistent with a nonrandom recurring process. Based on the distribution of bioturbation in the mud beds and variations in sand-bed thicknesses, we argue that this recurring process was probably a monthly occurrence. By measuring the lateral-accretion bed thicknesses for what appears to be a 1-yr interval, a sedimentation rate of 86 cm/yr is estimated for these lateral-accretion beds. This deposition rate provides an upper limit required to deposit these point bars and improves the framing of the depositional model. We estimate that the two point bars in this study were each deposited over a period of a few hundred years.

ABSTRACT Mass-transport complexes (MTCs) are one of the most sedimentologically and seismically distinctive depositional elements in deep-water depositional systems. Seismic reflection data provide spectacular images of their structure, size, and distribution, although a lack of borehole data means there is limited direct calibration between MTC lithology and petrophysical expression or knowledge of how they may act as hydrocarbon reservoir seals. In this study, we evaluated the lithological and petrophysical properties and seismic characteristics of three deeply buried (>2300 m below the seabed) Pleistocene MTCs in the northern Gulf of Mexico. We show that (1) MTC lithology is highly variable, comprising a mudstone-rich debrite matrix containing large (4.5-km3), deformed, sandstone-rich blocks; (2) MTCs are generally acoustically faster and are more resistive than lithologically similar (i.e., mudstone-dominated) slope deposits occurring at a similar burial depth; (3) MTC velocity and resistivity increase with depth, likely reflecting an overall downward increase in the degree of compaction; and (4) the lowermost 15–30 m of the MTCs, which represent the basal shear zones, are characterized by relatively high P-wave velocity and resistivity values, likely caused by shear-induced overcompaction. We conclude that detailed analysis of petrophysical data, in particular velocity and resistivity logs, may allow recognition of MTCs in the absence of high-quality seismic reflection data, including explicit identification of the basal shear zone. Furthermore, the relatively thick basal shear zone, rather than the overlying and substantially thicker MTC itself, may form the primary permeability barrier and thus seal for underlying hydrocarbon accumulations.

Several fractal models have been widely used to evaluate the heterogeneity of tight sandstones based on mercury intrusion porosimetry (MIP). However, most of these models are pore fractal models rather than surface fractal models. Therefore, the suitability of existing surface fractal models for tight sandstones and the consistency of their results remain questionable. In the present work, a series of tight sandstones from the Upper Triassic Yanchang Formation, Ordos Basin, was studied. The relative pore surface heterogeneity degree was predicted using petrographic observations and petrophysical measurements. Three popular pore surface fractal models proposed by Neimark, Friesen and Mikula, and Zhang and Li were applied to calculate the surface fractal dimensions of these sandstones based on MIP data. The results of the fractal analyses from different models were not consistent. One or two regions could be identified by applying Neimark’s and Friesen and Mikula’s models. However, the results of the fractal analyses, obtained by using these two methods, were not consistent with the petrographic observations and petrophysical property measurements. In contrast, Zhang and Li’s model was applicable over the whole pore size range, and the results provided by their model were consistent with the petrographic observations and petrophysical property measurements: a negative correlation was observed between the fractal dimensions and porosity and permeability. Therefore, the fractal model proposed by Zhang and Li can be successfully used to characterize the pore surface roughness in this study.

The Nanpu sag is a typical petroliferous area in the Bohai Bay Basin. Crude oil density and viscosity, natural gas components and biomarker chemistry of crude oil, and shale sample extracts were analyzed to determine the characteristics and the origin of oil and gas and the effects of source rock on oil and gas distribution. The discovered heavy oil present in the shallow layers of the Liuzan, Gaoshangpu, and Laoyemiao regions are a product of biodegradation and oxidation. The crude oil samples from the offshore locations are low density and viscosity, indicating good preservation conditions. Biomarker compositions indicate that the crude oils can be divided into four types: A, B, C, and D. Both type A and D oils were sourced from the third member of the Shahejie Formation. Type A oil is primarily distributed in the Liuzan and Gaoshangpu regions, whereas type D oil is chiefly distributed in the nos. 1, 2, 5, and Beipu structural belts (SBs). Type B oil, derived from the third member of the Dongying Formation, is primarily distributed in the Laoyemiao, Gaonan, and Liunan SBs. The type C oil is primarily derived from the first member of the Shahejie Formation and is distributed in the Beipu and nos. 1–4 SBs. The hydrocarbons are primarily distributed in the regions where the thick source rocks interact with faults. The discovered natural gas in the Nanpu sag is primarily observed as dissolved gas in oil and free gas.

ABSTRACT Despite the obvious link between hydrocarbon seepage at the surface and the activity of petroleum systems at depth, the majority of studies on seep carbonates concentrate on shallow aspects, whereas they are rarely oriented toward a source-to-sink perspective. Here, seep carbonates are conceptualized as a key element for analyzing petroleum systems at basin scale. Mapping of a 150-m-thick, 200-m-wide outcrop of the Lower Cretaceous slope wedge of the southeastern France Basin reveals two distribution patterns of seep carbonate concretions: (1) aligned in a continuous bed secant to the stratigraphy and (2) clustered in patches vertically stacked over 35 m. The δ13C signatures of the seep carbonates as light as −40‰ Peedee belemnite point toward a biogenic methane–dominated seepage. A set of turbidite channels pinching out right below the seep carbonates is seen as a potential gas trap, whereas biostratigraphic analysis indicates that the channels are coeval with a prominent black shale in the center of the basin. Any biogenic methane generated by the black shale could have used the channels as drains up to their pinch-out. The switch from a continuous seep carbonate level to stacked patches suggests initial widespread capillary leakage, followed by the opening of a preferential migration pathway. The distribution of seep carbonates thus appears dominated by breaching mechanisms of reservoir–cap-rock seals. This case study illustrates how seep carbonate mapping, in combination with the tectono-sedimentary context of each basin, may be a valuable tool for petroleum geologists.

Bedding-parallel veins of fibrous calcite (also called “beef”) occur in many sedimentary basins, especially those containing low-permeability strata with organic source material for petroleum. The formation of such veins is commonly linked with fluid overpressure in these source rocks. In this review, we demonstrate that beef veins are most commonly present in foreland basins worldwide or in basins that recorded a compressive tectonic period. The formation of beef veins is related to two main phases: (1) the initiation of bedding-parallel fracture and (2) the infilling of the fracture. Previous structural studies have shown that formation of beef veins occurred during a period of compressive stress activity. This is especially the case for the Wessex Basin (United Kingdom) and the Neuquen Basin (Argentina). In this paper, we provide more observations for other basins: the Cordillera Oriental (Colombia), the Paris Basin (France), the northern Pyrenees (France), the Uinta Basin (United States), the Tian Shan Mountains (central Asia), and the Appalachian Mountains (United States). In the Paris Basin, beef vein formation is dated at 155 Ma (U/Pb calcite method) and is coeval with the compressional deformation in the eastern part of the basin. Because of the timing of generation for such veins and even if the theory and the experiments of fracturing demonstrate that bedding-parallel fractures can be generated only with a distributed fluid overpressure, the formation of beef veins seems to be a consequence of both fluid overpressures and a compressional tectonic stress.

ABSTRACT X-ray fluorescence chemostratigraphy of the Cenomanian–Turonian Woodbine and Eagle Ford Groups in the southern parts of the East Texas Basin highlights significant mudstone chemical heterogeneities that commonly are difficult to observe or quantify at the macroscale. Several key elements, namely, Ca, Si, Mo, Mn, and Ni, were correlated to depositional conditions and used in a hierarchical cluster analysis to characterize five chemical facies (i.e., “chemofacies”) across 10 cored intervals of the Woodbine and Eagle Ford Groups: (1) argillaceous, organic-matter poor; (2) transitional, organic-matter poor; (3) transitional, organic-matter moderate; (4) calcareous, organic-matter rich; and (5) calcareous, organic-matter moderate. Characterizations of organic matter richness, mineralogy, and environmental conditions of deposition were established by correlating between key element abundances, total organic carbon measurements, x-ray diffraction measurements, and petrographic observations of lithologic composition, bioturbation, and sedimentary textures. Combined analysis of elemental geochemistry, stratigraphy, and petrographically observed sedimentary textures indicates that all chemofacies were deposited in an intrashelf basin above storm wave base. The most organic-rich chemofacies was deposited on a dominantly dysoxic distal shelf. Mudstone organic matter enrichment is driven dominantly by the minimization of siliciclastic dilution and secondarily enhanced by oxygen restriction. Regional correlations of chemofacies within a sequence stratigraphic framework developed from previous outcrop and subsurface work indicate a clear relationship between interpreted stratigraphy and chemofacies deposition. Generally, the highstand sequence sets of the Woodbine Group and upper Eagle Ford formation are dominated by mineralogically clay-rich, organic matter–lean, siliciclastic sedimentation and contain poor-quality source rock. Conversely, the transgressive sequence set of the lower Eagle Ford formation is dominated by organic matter–rich pelagic carbonate accumulation and contains excellent-quality source rock.