3D Static Modeling and Petrographic Aspects of the Albian/Cenomanian Reservoir,Komombo Basin,Upper Egypt

Natural Resources Research - The Albian/Cenomanian reservoir is one of the two main reservoirs composing the petroleum system in the Komombo Basin. However, these reservoirs have not previously...     

Subsurface Structural Setting and Hydrocarbon Potentiality of the Komombo and Nuqra Basins,South Egypt: A Seismic and Petrophysical Integrated Study

Natural Resources Research - Sedimentary basins in south Egypt, in particular Komombo and Nuqra basins, have been paid more attention during the last few decades, due to their hydrocarbon...     

Integrated Petrophysical Modeling for a Strongly Heterogeneous and Fractured Reservoir,Sarvak Formation,SW Iran

Introducing and applying an appropriate strategy for reservoir modeling in strongly heterogeneous and fractured reservoirs is a controversial issue in reservoir engineering. Various integration approaches have been introduced to combine different sources of information and model building techniques to handle heterogeneity in geological complex reservoir. However, most of these integration approaches in several studies fail on modeling strongly fractured limestone reservoir rocks of the Zagros belt in southwest Iran. In this study, we introduced a new strategy for appropriate modeling of a production formation fractured rock. Firstly, different rock types in the study area were identified based on well log data. Then, the Sarvak Formation was divided into nine zones, and the thinner subzones were used for further fine modeling procedure. These subzones were separated based on different fracture types and fracture distribution in each zone. This strategy provided sophisticated distribution of petrophysical parameters throughout the grids of the model, and therefore, it can handle strong heterogeneity of the complex reservoir. Afterward, petrophysical parameters were used to produce an up-scaled 3D gridded petrophysical model. Subsequently, maps of petrophysical properties were derived for each zone of the Sarvak Formation. Evidences achieved in this study indicates Sarvak Formation zone 2 as the target production zone with better performance of reservoir rock and the southwestern part of the field as area of maximum porosity.     

Hydrocarbon Generation,In-Source Conversion of Oil to Gas and Expulsion: Petroleum System Modeling of the Duwi Formation,Gulf of Suez,Egypt

Natural Resources Research - A multiple forward 1D modeling approach on four wells in the Abu Rudeis-Sidri oil field has been performed in accordance with the plate tectonics and crustal...     

Palaeogeography and diachronous infill of an ancient deep‐marine foreland basin,Upper Cretaceous Cerro Toro Formation,Magallanes Basin

The details of how narrow, orogen‐parallel ocean basins are filled with sediment by large axial submarine channels is important to understand because these depositional systems commonly form in through‐like basins in various tectonic settings. The Magallanes foreland basin is an excellent location to study an orogen‐parallel deep‐marine system. Conglomerate lenses of the Upper Cretaceous Cerro Toro Formation have been previously interpreted to represent the fill of a single submarine channel (4–8 km wide, >100 km long) that funneled coarse detritus southward along the basin axis. This interpretation was based on lithologic correlations. New U/Pb dating of zircons from volcanic ashes and sandstones, coupled with strontium isotope stratigraphy, refine the controls on depositional ages and provenance. Results demonstrate that north‐south oriented conglomerate lenses are contemporaneous within error limits (ca. 84–82 Ma) supporting that they represent parts of an axial channel belt. Channel deposits 20 km west of the axial location are 87–82 Ma in age. These channels are partly contemporaneous with the ones within the axial channel belt, making it likely that they represent feeders to the axial channel system. The northern Cerro Toro Formation spans a Turonian to Campanian interval (ca. 90–82 Ma) whereas the formation top, 70 km to the south, is as young as ca. 76 Ma. Kolmogorov–Smirnoff statistical analysis on detrital zircon age distributions shows that the northern uppermost Cerro Toro Formation yields a statistically different age distribution than other samples from the same formation but shows no difference relative to the overlying Tres Pasos Formation. These results suggest the partly coeval deposition of both formations. Integration of previously acquired geochronologic and stratigraphic data with new data show a pronounced southward younging pattern in all four marine formations in the Magallanes Basin. Highly diachronous infilling may be an important depositional pattern for narrow, orogen‐parallel ocean basins.     

Three-Dimensional Petrophysical Modelling and Volumetric Analysis to Model the Reservoir Potential of the Kupe Field,Taranaki Basin,New Zealand

Natural Resources Research - This study addresses the three-dimensional (3D) petrophysical modelling and volumetric analysis of the Farewell Reservoir in the Kupe Field in the southern Taranaki...     

Geology and regional significance of the Sarnoo Hills,eastern rift margin of the Barmer Basin,NW India

The Barmer Basin is a poorly understood rift basin in Rajasthan, northwest India. Exposures in the Sarnoo Hills, situated along the central eastern rift margin of the Barmer Basin, reveal a sedimentary succession that accumulated prior to the main Barmer Basin rift event, and a rift‐oblique fault network that displays unusual geometries and characteristics. Here, we present a comprehensive study of Lower Cretaceous sedimentology on the basin margin, along with a detailed investigation of rift‐oblique faults that are exposed nowhere else in the region and provide critical insights into Barmer Basin evolution. Lower Cretaceous sediments were deposited within a rapidly subsiding alluvial plain fluvial system. Subsequent to deposition, the evolving Sarnoo Hills fault network was affected by structural inheritance during an early, previously unrecognised, rift‐oblique extensional event attributed to transtension between India and Madagascar, and formed a juvenile fault network within the immediate rift‐margin footwall. Ghaggar‐Hakra Formation deposition may have been triggered by early rifting which tectonically destabilised the Marwar Craton prior to the main northeast–southwest Barmer Basin rift event. The identification of early rifting in the Barmer Basin demonstrates that regional extension and the associated rift systems were established throughout northwest India prior to the main phase of Deccan eruptions. Inheritance of early oblique fault systems within the evolving Barmer Basin provides a robust explanation for poorly understood structural complications interpreted in the subsurface throughout the rift. Critically, the presence of syn‐rift sedimentary successions within older oblique rift systems obscured beneath the present‐day Barmer Basin has significant implications for hydrocarbon exploration.     

From 2D to 3D Modeling of Mineral Prospectivity Using Multi-source Geoscience Datasets,Wulong Gold District,China

Natural Resources Research - The Wulong gold district (WGD) is located at the northeastern margin of the North China Carton (NCC) on the Liaodong Peninsula, China. The results of early mineral...     

Integrated 3D forward stratigraphic and petroleum system modeling of the Levant Basin,Eastern Mediterranean

The Eastern Mediterranean Levant Basin is a proven hydrocarbon province with recent major gas discoveries. To date, no exploration wells targeted its northern part, in particular the Lebanese offshore. The present study assesses the tectono‐stratigraphic evolution and related petroleum systems of the northern Levant Basin via an integrated approach that combines stratigraphic forward modeling and petroleum systems/basin modeling based on the previous published work. Stratigraphic modeling results provide a best‐fit realisation of the basin‐scale sedimentary filling, from the post‐rift Upper Jurassic until the Pliocene. Simulation results suggest dominant eastern marginal and Arabian Plate sources for Cenozoic siliciclastic sediments and a significant contribution from the southern Nilotic source mostly from Lower Oligocene to Lower Miocene. Basin modeling results suggest the presence of a working thermogenic petroleum system with mature source rocks localised in the deeper offshore. The generated hydrocarbons migrated through the deep basin within Jurassic and Cretaceous permeable layers towards the Latakia Ridge in the north and the Levant margin and offshore topographic highs. Furthermore, the basin model indicates a possibly significant influence of salt deposition during Messinian salinity crisis on formation fluids. Ultimately, the proposed integrated workflow provides a powerful tool for the assessment of petroleum systems in underexplored areas.     

Deep-Lacustrine Shale Heterogeneity and Its Impact on Hydrocarbon Generation,Expulsion, and Retention: A Case Study from the Upper Triassic Yanchang Formation,Ordos Basin,China

The Chang-7 shale of the Upper Triassic Yanchang Formation was deposited in a deep-lacustrine environment in the southwest part of the Ordos Basin. It is characterized by a strong lithological heterogeneity, consisting primarily of pure shale and sandy laminated shale. This study explored the impact of sandy laminae in the thick pure shale on hydrocarbon generation, retention, and expulsion, which were rarely considered in previous studies. Based on core observation, thin section, and geochemical analysis, the hydrocarbon generation, retention, and expulsion characteristics were obtained for both pure shale and sandy laminated shale. In general, the Chang-7 shale stays at low mature to mature thermal evolution stage and has good hydrocarbon generation potential. It contains mainly Type II kerogen with an average total organic carbon (TOC) of 2.9% and average (S₁?+?S₂) of 8.2 mg/g. Compared with sandy laminated shale, pure shale contains more retained liquid hydrocarbon and has a higher amount of asphaltene and nitrogen–sulfur–oxygen (NSO) polarized components, indicating a relatively weak hydrocarbon expulsion process. The middle part of a thick pure shale retains more liquid hydrocarbon and has higher percentages of asphaltene and NSO polarized components than that of the top and basal part of the shale where sandy laminae occur. The difference in hydrocarbon retention capacity is interpreted to have been primarily caused by the comparatively higher reservoir quality of the sandy laminated shale, having higher amount of brittle minerals and larger pores than the pure shale. Polymer dissolution and nanopore adsorption are also key factors in hydrocarbon retention and component partition. Based on this study, we suggest that sandy laminated shale, which receives most of the hydrocarbon from adjacent pure shale, should be the current favorable shale oil exploration targets. Even though pure shale contains high hydrocarbon potential, its development is still pending improved technologies, which could solve the challenges caused by complicated geological conditions.

     

Variogram Identification Aided by a Structural Framework for Improved Geometric Modeling of Faulted Reservoirs: Jeffara Basin, Southeastern Tunisia

This article describes a proposed work-sequence to generate accurate reservoir-architecture models, describing the geometry of bounding surfaces (i.e., fault locations and extents), of a structurally complex geologic setting in the Jeffara Basin (South East Tunisia) by means of geostatistical modeling. This uses the variogram as the main tool to measure the spatial variability of the studied geologic medium before making any estimation or simulation. However, it is not always easy to fit complex experimental variograms to theoretical models. Thus, our primary purpose was to establish a relationship between the geology and the components of the variograms to fit a mathematically consistent and geologically interpretable variogram model for improved predictions of surface geometries. We used a three-step approach based on available well data and seismic information. First, we determined the structural framework: a seismo-tectonic data analysis was carried out, and we showed that the study area is cut mainly by NW–SE-trending normal faults, which were classified according to geometric criteria (strike, throw magnitude, dip, and dip direction). We showed that these normal faults are at the origin of a large-scale trend structure (surfaces tilted toward the north-east). At a smaller scale, the normal faults create a distinct compartmentalization of the reservoirs. Then, a model of the reservoir system architecture was built by geostatistical methods. An efficient methodology was developed, to estimate the bounding faulted surfaces of the reservoir units. Emphasis was placed on (i) elaborating a methodology for variogram interpretation and modeling, whereby the importance of each variogram component is assessed in terms of probably geologic factor controlling the behavior of each structure; (ii) integrating the relevant fault characteristics, which were deduced from the previous fault classification analysis, as constraints in the kriging estimation of bounding surfaces to best reflect the geologic structure of the study area. Finally, the estimated bounding surfaces together with seismic data and variogram interpretations were used to obtain further insights into the tectonic evolution of the study area that has induced the current reservoirs configuration.     

3D Modeling of Large-Scale Geological Structures by Linear Combinations of Implicit Functions: Application to a Large Banded Iron Formation

Natural Resources Research - Implicit methods for modeling geological structures such as stratigraphy and faults have been developed for more than a decade, and they have made automatic model...     

Insights into syndepositional fault movement in a foreland basin; trends in seismites of the Upper Cretaceous,Wahweap Formation,Kaiparowits Basin,Utah, USA

The Upper Cretaceous Wahweap Formation accumulated in the active Cordilleran foreland basin of Utah. Soft‐sediment deformation structures are abundant in the capping sandstone member of the Wahweap Formation. By comparing with well‐established criteria, a seismogenic origin was determined for the majority of structures, which places these soft‐sediment deformation features in a class of sedimentary features referred to as seismites. A systematic study of the seismite trends included their vertical and horizontal distribution and a semi‐quantitative intensity analysis using a scale from 1 to 5 that is based on magnitude, sedimentary structure type, and the predominance of inferred process of hydroplastic deformation, liquefaction or fluidization. In addition, orientations of soft‐sediment fold axes were recorded. Construction of a northwest‐to‐southeast stratigraphic and seismite intensity cross‐section demonstrates: (1) reduction in stratigraphic thickness and percentage of conglomerates to the southeast, (2) the presence of lower seismite, middle nonseismite, and upper seismite zones within the capping sandstone (permitting subdivision of the capping sandstone member), and (3) elimination of the nonseismite zone and amalgamation of the lower and upper seismite zones to the southeast. Regional isoseismal contour maps generated from the semi‐quantitative analysis indicate a decrease in overall intensity from northwest to southeast in the upper and lower seismic zones and in sandstone within 5 m stratigraphically of the contact between the upper and capping sandstone members. In addition, cumulative seismite fold orientations support a west–northwest direction towards regional epicentres. Isoseismal maps are used to distinguish the effects of intrabasinal normal faulting from those of regional orogenic thrusting. Thus, this study demonstrates the utility of mapping seismites to separate the importance of regional vs. local tectonic activity influencing foreland basin sedimentation by identifying patterns that delineate palaeoepicentres associated with specific local intrabasinal normal faults vs. regional trends in soft‐sediment deformation related to Sevier belt earthquakes.     

Conventional and Unconventional Hydrocarbon Resource Potential Evaluation of Source Rocks and Reservoirs: A Case Study of the Upper Xiaganchaigou Formation,Western Qaidam Basin,Northwest China

The Paleogene upper Xiaganchaigou Formation (E₃²) is the most important source rock and reservoir in the Qaidam Basin. However, there are few studies on the processes of hydrocarbon accumulation in this formation; therefore, its hydrocarbon resource potential has not been estimated reasonably. This paper evaluates the hydrocarbon generation properties in light of an improved hydrocarbon generation and expulsion potential model. According to the geochemical characteristics of source rocks and the petrological features of reservoirs, the potentials of different resource types, including conventional oil, tight oil and shale oil, are quantified by combining the buoyancy-driven hydrocarbon accumulation depth (BHAD) and the lower limit for movable resource abundance. The results show that the source rocks are characterized by a large thickness (more than 1000 m), moderate organic matter content, high marginal maturity and a high conversion rate (50% hydrocarbons have been discharged before R_o?=?1%), which provide sufficient oil sources for reservoir formation. Moreover, the reservoirs in the Qaidam Basin consist mainly of low-porosity and low-permeability tight carbonates (porosity of 4.7% and permeability less than 1 mD). The maximum hydrocarbon generation, expulsion, retention and movable retention intensities at present are 350?×?10⁴ t/km², 250?×?10⁴ t/km², 130?×?10⁴ t/km² and 125?×?10⁴ t/km², respectively. The thresholds of hydrocarbon generation, expulsion and BHAD were 0.46% R_o, 0.67% R_o and 0.7% R_o, respectively. Moreover, the dynamic evolution process of hydrocarbon accumulation was divided into three evolution stages, namely, (a) initial hydrocarbon accumulation, (b) conventional hydrocarbon reservoir and shale oil accumulation and (c) unconventional tight oil accumulation. The conventional oil, tight oil and movable shale oil resource potentials were 10.44?×?10⁸ t, 51.9?×?10⁸ t and 390?×?10⁸ t, respectively. This study demonstrates the good resource prospects of E₃² in the Qaidam Basin. A comprehensive workflow for unconventional petroleum resource potential evaluation is provided, and it has certain reference significance for other petroliferous basins, especially those in the early unconventional hydrocarbon exploration stage.

     

基于三维激光扫描仪的建筑物建模应用研究

为分析三维激光扫描仪在建筑物建模方面的精度,针对传统实测的建模方式,采用基于三维激光扫描理论技术对某建筑进行扫描,从其数据获取、数据分析处理,到获得该建筑物的表面三维模型的过程入手,对比、分析与传统测量的建模方法所获得模型的精度及可靠性。结果表明,三维激光扫描仪所获得数据的精度完全达到了预期的要求,且可以大大节省数据建模的时间,突显了三维激光扫描技术的优势,也为三维激光扫描技术在其他领域的应用提供了科学参考。     

Structural evolution of a gravitationally detached normal fault array: analysis of 3D seismic data from the Ceduna Sub‐Basin,Great Australian Bight

The growth, interaction and controls on normal fault systems developed within stacked delta systems at extensional delta‐top settings have not been extensively examined. We aim to analyse the kinematic, spatial and temporal growth of a Cretaceous aged, thin‐skinned, listric fault system in order to further the understanding of how gravity‐driven fault segments and fault systems develop and interact at an extensional delta‐top setting. Furthermore, we aim to explore the influence of a pre‐existing structural framework on the development of gravity‐driven normal faults through the examination of two overlapping, spatially and temporally distinct delta systems. To do this, we use three‐dimensional (3D) seismic reflection data from the central Ceduna Sub‐basin, offshore southern Australia. The seismic reflection data images a Cenomanian‐Santonian fault system, and a post‐Santonian fault system, which are dip‐linked through an intervening Turonian‐early Campanian section. Both of these fault systems contain four hard‐linked strike assemblages oriented NW–SE (127–307), each composed of 13 major fault segments. The Cenomanian‐Santonian fault system detaches at the base of a shale interval of late Albian age, and is characterised by kilometre‐scale growth faults in the Cenomanian‐Sanontian interval. The post‐Santonian fault system nucleated in vertical isolation from the Cenomanian‐Santonian fault system. This is evident through displacement minima observed at Turonian‐early Campanian levels, which is indicative of vertical segmentation and eventual hard dip‐linkage. Our analysis constrains fault growth into four major evolutionary stages: (1) early Cenomanian nucleation and growth of fault segments, resulting from gravitational instability, and with faults detaching on the lower Albian interval; (2) Santonian cessation of growth for the majority of faults; (3) erosional truncation of fault upper tips coincident with the continental breakup of Australia and Antarctica (ca. 83 Ma); (4) Campanian‐Maastrichtian reactivation of the underlying Cenomanian‐Santonian fault system, inducing the nucleation, growth and consequential dip‐linkage of the post‐Santonian fault system with the underlying fault system. Our results highlight the along‐strike linkage of fault segments and the interaction through dip‐linkage and fault reactivation, between two overlapping, spatially and temporally independent delta systems of Cenomanian and late Santonian‐Maastrichtian age in the frontier Ceduna Sub‐Basin. This study has implications regarding the growth of normal fault assemblages, through vertical and lateral segment linkage, for other stacked delta systems (such as the Gulf of Mexico) where upper delta systems develop over a pre‐existing structural framework.     

Palaeomagnetism and K—Ar age of the Upper Ordovician Alcaparrosa Formation, Argentina

Summary. Palaeomagnetic data from 71 hand samples of igneous rocks of Late Ordovician age exposed in western Argentina (31.3°S, 69.4°W, Alcaparrosa Formation) are given. Stable remanent magnetization was isolated in the majority of samples; they yield a palaeomagnetic pole at 56°S 33°E ( N = 8, α₉₅= 16°). Whole rock K-Ar age determinations yield an age of 416 ± 10 Myr for a pillow lava of the Alcaparrosa Formation.
Palaeomagnetic data for South America, Africa, Australia, Antarctica and India suggest that Gondwana was a unit at least as far back as 1000 Myr. The palaeomagnetic data define a rapid polar migration for Gondwana in Ordovician time which is consistent with the widespread occurrences of Late Ordovician glacial deposits across this supercontinent.     

GIS和GOCAD支持下的矿山3D地质建模

在综合分析3D地质数据模型的基础上.提出将源数据模型分为GIS可描述和GIS不可描述数据模型的分类方法,在ArcGIS和G0(:AD平台下构建了基于GIS的多元、多方法集成的矿山3D地质模型.ArcGIS平台下描述GIS可描述数据模型,并进行数据管理和空间数据分析;GIS不可描述数据模型一方面在GOCAD下描述复杂的地质构造,另一方面采用面向对象的聚合派生法描述矿山工程模型中的空间实体,并利用Geodatabase建立两者的关联.实例应用表明,该方法保持了数据在空间和时间上的一致性,为矿山安全生产管理提供了有效和可靠的空间数据及可视化支持.     

Machine Learning-Based 3D Modeling of Mineral Prospectivity Mapping in the Anqing Orefield,Eastern China

Natural Resources Research - Successful delineation of high potential targets for exploration in maturely-explored orefields is still a tough challenge. A reliable prediction model achieved by...     

A Novel Method to Obtain Permeability in a Dual-Pore System Using Geophysical Logs: A Case Study of an Upper Triassic Formation,Southwest Ordos Basin,China

Fractured tight sandstone reservoirs are dual-pore systems including matrix pores and natural fractures, which both contribute to the system permeability. However, most previous studies either calculated the matrix permeability or obtained the fracture permeability to represent the system permeability in the logging evaluation of fractured tight sandstones because existing logging methods cannot distinguish the two types. In this study, a novel method is proposed to estimate the system permeability in fractured tight sandstones using geophysical logs. First, the fracture characteristics in the Upper Triassic Chang 8 member of the Yanchang Formation, southwest Ordos Basin, China, were analyzed. Based on the hydraulic flow unit approach, the formation classification criteria and the corresponding permeability–porosity models were established; then, the pure matrix permeability in the dual-pore system was calculated using geophysical logs. Based on the fracture characteristics, the relative pure fracture permeability was obtained using the Sibbit and Faivre method. By applying the Parsons’ model in boreholes, the system permeability was then calculated by coupling the relationship between the two permeabilities. Finally, two field applications in the study area demonstrate the feasibility of the proposed method, and the logging responses, application effects and applicable conditions of this method are discussed in detail. These applications indicate that the proposed method is suitable for tight reservoirs with fracture widths less than 200 μm, and considered to be dual-pore systems.