Porosity serves as a critical parameter in shale oil reservoir evaluation and resource quantification. Limitations in evaluation principles and shale heterogeneity lead to varying effectiveness among different methods. Moreover, solvent extraction may cause fluid retention, toxicity risks, and data distortion, compromising the accuracy of shale oil resource assessment. This study proposes the Shale-tT1/T2 (a nuclear magnetic resonance (NMR) method combining longitudinal relaxation and transverse relaxation for shale porosity) porosity evaluation methodology for conventional core shales as an innovative approach, using sealed core samples from the fourth member of the Shahejie Formation, Dongying sag as the study object. A NMR-based NMR-tT1/T2 model was established to characterize sealed core shale fluid porosity (ttotal1), residual fluid porosity (t 1) in conventional cores after surface exposure, and saturation-fluid porosity (t 2) in pressurized-saturated shales. Total porosity (ttotal2) is obtained by summing the two-stage results (t 1 + t 2). Results demonstrate high consistency between sealed core porosity (ttotal1) and Shale-tT1/T2-derived porosity (ttotal2), with error coefficients systematically decreasing as porosity increases. This method avoids core extraction and solvent-induced pore distortion, significantly improving detection efficiency. As an eco-friendly solution addressing fidelity challenges in shale porosity assessment, it can be rapidly adopted as a primary method for porosity determination in shale oil reserve evaluation and resource quantification.
Unconventional reservoirs have received attention for their potential to fulfill energy supply, requiring techniques like hydraulic fracturing to enhance production. In Argentina's Neuquen Basin, the Agrio Formation has recently emerged as a promising unconventional play due to its similarities with Vaca Muerta Formation, the primary source rock. This study focuses on deposits of the lower Pilmatue Member, characterized by mudrock successions accumulated during transgressive periods, recognized as source rocks with three potential intervals. These intervals exhibit high total organic carbon, thicknesses >20 m, and type II/II-III kerogen, highlighting their hydrocarbon generation potential. Despite well-documented geochemical and sedimentological features, limited information exists on geomechanical properties and heterogeneity. This study applies a multiproxy approach analyzing variability in organic-rich intervals, focusing on mineralogical, textural and mechanical properties, such as strength and hardness. Additionally, interfaces and surface roughness were characterized. The dominant lithologies include marls, shales, and fine-grained limestones, with minor sandstones, tuffs, and concretions. Allochemic mudrock microfacies characterize mudrocks, whereas limestones feature sparse biomicrite, micrite, and muddy allochem limestone. High quartz/carbonate and low clay content correlate with higher mechanical properties. Furthermore, studies of diagenetic textures reveal that rock strength increases with the degree of diagenesis. Vertical variability is low in organic level (OL)1 but increases in OL2-OL3, marked by frequent interfaces with low roughness. These findings enhance understanding of Pilmatue Member's heterogeneity, guiding well landing and hydraulic fracturing strategies. This integrated approach offers a robust model for optimizing unconventional reservoir exploitation and evaluating other plays.
Acceleration of sea-level rise, coupled with natural and humaninduced reductions in sediment supply, has resulted in unpreceRecent projections indicate widespread inundation of existing wetlands by the year 2050, including most of the Mississippi Delta, the Everglades, and the Louisiana Chenier Plain. In addition, barrier islands, peninsulas, and mainland beaches are experiencing rapid erosion. These changes are a stark reversal from the stability and growth of these coastal settings during the last 4000 yr. Indeed, current rates of change outpace those of the Early Holocene, when sea level was rising at about the same rate as today, but sediment supply to the coast was not impeded by the alteration of sediment supply and dispersal systems. Unfortunately, Gulf Coast states have been slow to recognize the magnitude of the problem, but there is still time to slow the rate of change and reduce its impacts.
The timing and origin of fluid activity are crucial for understanding the relationship between hydrocarbon accumulation and tectonic events. In this study, we conducted an integrated analysis combining petrography, geochemistry, fluid inclusion analysis, and laser ablation-sector field-inductively coupled plasma-mass spectrometry U-Pb geochronology of multiphase calcite veins collected from the Triassic Qinglong Formation carbonate reservoir in the Huangqiao area of the Subei Basin. Six phases of calcite veins were identified: C1 (141.9 +/- 3.4 Ma), C2 (115.3 +/- 2.8 Ma), C3 (97.03 +/- 0.43 Ma), C4 (85.29 +/- 0.25 Ma), C5 (circa 60 Ma), and C6 (circa 42-38 Ma). Primary oil inclusions are exclusively present in the C1, C2, and C5 veins, indicating distinct episodes of hydrocarbon migration. The fluid sources varied: C1 veins originated from hydrocarbon fluids mixed with formation water; C2 veins formed from deep hydrothermal fluids related to Tanlu fault zone activity; C3 and C4 veins derived from formation water mixed with meteoric water; C5 veins formed from intraformational water mixed with deep-seated strata water; and C6 veins sourced from deep-seated, strontium-rich crustal fluids. The ages and fluid sources of the calcite veins correspond well to key tectonic events, as well as hydrocarbon accumulation and subsequent reservoir modification accompanied by hydrocarbon leakage in the Huangqiao area. Stage I: The first phase of oil accumulation (vitrinite reflectance [Ro] = 0.7%) occurred under compressional tectonics related to the early Yanshanian orogeny. Stage II: Reservoir modification was driven by hydro-thermal activity associated with the Tanlu fault zone. Stage III: Reservoir damage as late Yanshanian uplift brought the reservoir near the surface, allowing meteoric water infiltration. Stage IV: Main hydrocarbon accumulation (Ro = 0.85%) due to rapid stratigraphic burial in an extensional setting associated with Pacific plate subduction.
The middle Cretaceous (Albian) Mauddud Formation is a complexly layered limestone reservoir of approximately 117-m thickness in the Raudhatain and Sabiriyah fields. Stratigraphic trends in reservoir quality are strongly related to smaller (fourth-order) depositional sequences, and there is a large-scale upward-increase in quality through the third-order highstand systems tract that makes up most of the formation. Depositional envir-onments and textures show only subtle correlation with porosity and permeability within the proximal, inner-ramp facies, but the more distal, muddier deposits have distinctly lower reservoir quality. Petrography reveals overall volumetric dominance of micropores over macropores. Karst surfaces are not observed in the studied cores, but meteoric water may well have been important during early diagenesis. Heterogeneity of reservoir quality results in large degree from heavily calcite-cemented nodules and thicker cemented zones, with the heavily cemented masses distinguished from surrounding porous limestone by the absence of oil staining. The nodular cementation was probably localized by burrowing and was partly supplied by early dissolu-tion of locally concentrated aragonitic green algae. Field-wide compilations of core and log data reveal trends of upward poros-ity increase from the flanks to the crest of each field that are similar to the porosity trends of giant domal oil fields in Abu Dhabi and the North Sea, where late calcite cementation was inhibited by oil accumulation. The maximum crest-flank porosity difference due to late cementation is approximately 10 vol. %. This study was performed to provide input for building reservoir models, but has broader significance for understanding the impact on reservoir quality of depositional environments, cemented nodules, sequence stratigraphy, and the preservation of crestal porosity by oil in many other microporous limestone reservoirs.
