Marine and Petroleum Geology最新文献

The geometry, orientation and stacking patterns of sedimentary geobodies play a key control on fluid migration within subsurface reservoirs, aquifers, and repositories. Outcrops and more recently virtual outcrops are commonly used as analogues to characterise geobody architecture and stacking. Traditionally, both reservoirs and their analogues are described with respect to the bulk proportion of different facies and architectural elements within the system. These are combined with geometric measurements of the different geobodies to describe heterogeneity.

This study presents a new methodology for quantifying the range of facies proportions within architectural element panels taken from outcrop analogues. This method measures the facies proportions within a series of vertical profiles and considers the statistical distribution, rather than the simple mean across the entire panel. The basic premise being that within a layer cake system, the spread in facies proportions will be very narrow whereas in a more “jigsaw” type system the spread will be much wider.

To test this hypothesis, a series of nine virtual outcrops from a range of clastic depositional systems including fluvial, shallow marine and deep marine settings, have been analysed. Depositional facies (architectural elements) were interpreted in LIME and a series of depositional strike-orientated orthorectified panels were extracted. The panels were then analysed, and the extracted facies proportions were translated to “net sand” distribution. Results were then compared with conventional analysis of reservoir heterogeneity.

Different depositional systems show distinct patterns. When arranged in depositional dip order, there is a systematic decrease in sand distribution spread down dip with significant resets at the boundaries between the major gross depositional environments (continental, shallow marine/shelf, deep marine).

The present study used well log and seismic data to determine the main lithology types, characterize and evaluate the reservoirs properties and discuss about the hydrocarbon quality and productivity in the onshore south of the Rio Del Rey Basin (RDRB). The main results show seven lithologies inside the Isongo, Diongo and Nguti including clays, sandstones and clayey sandstones, the most dominant, and limestones, dolomites, sandstone limestones and clayey limestones, the less dominant. Seventeen reservoir zones with fifteen gas-bearing and two oil-bearing were identified in the Miocene sands of the Isongo, Diongo and Nguti Formations and very few in the Upper Oligocene sands of Akata Formation. The average values of petrophysical parameters obtained are V_shale (13.26–31.3%), NTG (64.48–87.07%), ∅_eff (18.54–26.60%), ∅_avg (23.27–33.59%), S_w (4.84–11.10%), S_hc (88.90–95.16%), and K (1258.96–2187.26 mD). It shows that the identified reservoirs are of the good quality and can be commercially viable for the gas. Knowing that the RDRB and the neighbouring ones (Niger Delta, Rio Muni and Gabon basins which are OPEC members) have good petrophysical parameters, findings from this investigation show that the key difference between RDRB and others lay on the low continuity and vertical extension of these reservoirs, as well as the lower sedimentary thickness (6–7 km), the tectono-stratigraphic architecture and the production essentially focused on the Miocene horizons.

We present a geochronological and structural study of the sedimentary architecture of the Vaca Muerta-Quintuco System and Mulichinco Formation in Sierra de Reyes and La Yesera anticlines along the Andean front within the Neuquén Basin. Remote sensing mapping coupled with fieldwork has allowed us to analyse an Auquilco-related secondary detachment anticline in the Sierra de Reyes that exhibits growth strata within the Vaca Muerta-Quintuco and Mulichinco formations, with a decrease in growth rate at the top of the uppermost formation. Numerical ages based on ⁸⁷Sr/⁸⁶Sr ratios of calcite shells indicate that anticline growth occurred from Late Jurassic to Early Cretaceous between 148.65 and 132.5 Ma. These ages also allowed us to correlate the Vaca Muerta-Quintuco System in Sierra de Reyes with a published NW-SE seismic transect that traverses the entire Neuquén Basin and extends to the Andean front within the study area. The correlation reveals a coeval period of compression during the growth of the Sierra de Reyes, Loma la Lata and Río Neuquén highs (antiforms), constraining a regional period of intraplate contraction during the latest Jurassic and Early Cretaceous in the Neuquén Basin.

Pyrobitumens, abundant in the Sichuan Basin, SW China, serve as indicators of past oil reservoirs. Currently, estimates of gas generation during oil cracking rely solely on pyrobitumen content with a uniform conversion rate. This study delves into reservoir fluid heterogeneity influenced by factors such as gravitational segregation, deasphaltene processes, biodegradation, and thermochemical sulfate reduction. It recommends a comprehensive geological analysis of pyrobitumens for precise estimation. The research underscores oil heterogeneity within the reservoir, with light oil prevalent in the upper column and heavy oil accumulating at the base. Oil cracking initiates in polar-enriched zones due to deep burial, high temperatures, and low activation energy requirement, leading to concentrated pyrobitumen zones at the column base and/or in highly permeable zones. Pyrobitumens are primarily found in dissolution pores and fractures, aiding in identifying their precursors through optical structure and elemental analysis. Methane production per unit weight of pyrobitumen is lower in pyrobitumen concentrated zones, typically at the column base, compared to dispersed pyrobitumen in the upper oil column. Relying solely on residual pyrobitumen content and a single conversion ratio for oil cracking formed methane estimation may result in misleading interpretations. The study proposes a mass balance calculation method, incorporating the atomic H/C ratio, to examine the gas yield-pyrobitumen relationship. Insights gained from the Sichuan Basin can offer valuable information for resource and environmental impact assessments in other basins with thermally cracked oils.

Carbon dioxide foam injection stands as a promising method for enhanced oil recovery (EOR) and carbon sequestration. However, accurately predicting its efficiency amidst varying operational conditions and reservoir parameters remains a significant challenge for conventional modeling techniques. This study explores the application of machine learning (ML) methodologies to develop a robust model for matching experimental values in CO₂ foam flooding scenarios. Leveraging a comprehensive dataset encompassing diverse surfactants and rock types, with varied porosity and permeability, our model demonstrates accurate predictions across a wide spectrum of conditions. By focusing on key parameters such as foam apparent viscosity, interfacial tension (IFT), injected foam volume, initial oil saturation, porosity, and permeability, we unveil the pivotal role of these factors in determining CO₂ foam EOR performance. Through rigorous analysis, we identify the relative importance of each input parameter, with injected foam volume, apparent viscosity, and IFT emerging as dominant factors. The most accurate model was deep neural network (DNN) (R² value of 0.99). Higher foam viscosity and lower IFT were found to significantly enhance oil recovery rates, though their effects plateau beyond certain thresholds (apparent viscosities above 1200 cP and IFT values below 0.2 mN/m). The findings underscore the potential of ML-driven approaches in enhancing CO₂ foam EOR predictions, offering insights crucial for optimizing foam flooding performance across diverse reservoir settings.

Depositional events have a significant impact on the terrestrial redox conditions and provide evidence for studying the organic matter enrichment. The objective of this study was to evaluate the influence of volcanic and turbidity current events on benthic redox conditions during the Upper Triassic Chang 7 member (Ch7) of the Ordos Basin. To address these issues, the varying sedimentological settings, paleoredox conditions, and relationships between the redox environment and depositional events were investigated via sedimentary analysis of the profiles, microscopic analysis, organic geochemical analysis, and elemental geochemical data. The fine-grained sediments in the Chang 7₃ submember (Ch7₃) consist of abundant organic matter, collophanite, and framboidal pyrite. However, in the upper part of the Ch7 member, there was a decrease in organic matter, a decrease in the number of microorganisms, and an increase in pyrite size, indicating that the oxic environment is not favorable for organic matter enrichment. The element and geochemical proxies show similar vertical variations and redox changes. Volcanic activity can bring substantial amounts of material or elements to the basin. The enrichment of Hg and S exhibited considerable variation, ranging from 8.7 to 274.4 ppb and from 0.16 to 4.53 wt%, respectively, which influenced the organic matter accumulation through the flourishing and death of microorganisms and redox changes in the benthic environment of the terrestrial basin. As the lake basin shrinks, the Ti and Al contents increase with increasing frequency of turbidity current events, and the terrestrial debris transported to the lake basin gradually increases while carrying large amounts of oxygen and affecting sedimentation rates, contributing to the destruction of the reducing conditions of the benthic environment, subsequently, influencing organic matter accumulation. These results will be helpful in understanding the effect of multiple depositional events on organic matter enrichment in lacustrine basins.

The Paleogene lacustrine delta–turbidite facies sandstones of the Third Member of the Shahejie Formation (Es₃) in the Linnan Depression have abundant tight oil resources. Movable fluids can independently characterize reservoir fluid mobility and recovery efficiency, which are essential for accurate reservoir assessment and efficient development and evaluation of oil reservoirs. Systematic research on the distribution patterns and controlling factors of movable fluids in the tight sandstone reservoirs of the Linnan Depression is lacking. To address this gap, this study employs multi-gradient centrifugation combined with Nuclear Magnetic Resonance (NMR) to characterize fluid mobility and determine the lower limit of the movable fluid pore radius (LLMPR) in various lithofacies of lacustrine delta-turbidite facies sandstones. In conjunction with core descriptions, thin section observations, X-ray diffraction (XRD) analysis, gas permeability tests, and High-pressure mercury injection (HPMI) data, this research explicates the macroscopic impacts of depositional and diagenetic processes and the microscopic effects of pore structure on fluid movability. The study identifies four lithofacies (delta front facies massive siltstone (DFMS)、delta front facies laminated siltstone (DFLS)、slump turbidite facies siltstone (STS), and slump turbidite facies calcareous siltstone (STCS)) with corresponding pore structures and space types (I-micropores, II-micropores, mesopores, macropores). DFLS and DFMS feature well-developed primary intergranular and intragranular dissolution pores, high HPMI mercury intrusion saturation, and large average pore radius, primarily contributing to fluid mobility through mesopores and macropores with movable fluid saturation of 56.1% and 52.9%, respectively. In contrast, STS and STCS mainly comprise mesopores and micropores with lower movable fluid saturation of 33.5% and 27.5%, influenced by clay filling and carbonate cementation, resulting in poor connectivity. Macroscopically, better-sorted delta-front sand bodies develop connected pores within rigid quartz and feldspar particle frameworks, increasing the proportion of mesopores and macropores. Microscopically, reservoir properties, RQI, maximum invasion saturation, displacement pressure, and average pore radius significantly influence fluid movability. As centrifugal force increases, fluid output from pores slows, and the LLMPR decreases exponentially. At an optimal centrifugal force of 2.75 MPa, the LLMPR in the Linnan Depression is calculated to be 0.033 μm. Based on these insights, a fluid mobility model for lacustrine delta front-turbidite facies tight sandstones is established, identifying DFMS and DFLS as the optimal lithofacies for movable fluids. This study provides theoretical references for understanding and effectively developing deep tight sandstone reservoirs.