Active Petroleum System Research Articles

Timing of hydrocarbon charge in the Axial Zone of the Eastern Cordillera, Colombia

The petroleum potential of onshore basins in Colombia has been partly controlled by the Andean Orogeny since the end of the Cretaceous. Its Axial Zone has at least one understudied active petroleum system with a rather low petroleum potential and few commercial medium to heavy oil accumulations, raising questions about how the Andean deformation influenced the petroleum system and the possible undiscovered accumulations. We examine the timing of this petroleum system in the Axial Zone through oil–source correlations and two 2D petroleum system models across the Boyacá and Soápaga faults based on cross-sections. Modelling reveals the direct control of deformation on generation–accumulation in the Axial Zone, where the Lower Cretaceous source rocks, due to high heat flows during the synrift phase, started generation so early (100 to 60 Ma) that no reservoirs or traps were yet available to allow hydrocarbon entrapment and accumulation. Equally, for the younger Upper Cretaceous source rocks, the tectonic inversion of the basin between 33 and 23 Ma along the Boyacá and Soápaga faults interrupted burial and the maturation in most parts of the basin, leaving only local pods of active source rocks where maturation continues today due to the tectonic overburden along the footwall of the Soápaga Fault. The latter is thus the major kitchen, contributing more than 50% of the liquid hydrocarbons trapped mainly in Upper Cretaceous and Paleocene sandstones. Hydrocarbons migrate upwards where biodegradation and water washing occurred in the near-surface, giving rise to the many tar sand occurrences in the Eocene sandstones.

3D seismic analysis of Cenozoic slope deposits and fluid-flow phenomena along the Nigerian Transform Margin

Abstract 3D seismic data provide new insights on c. 2 km thick Cenozoic post-transform slope sediments and fluid-flow phenomena along the Nigerian Transform Margin. The study documents large-scale mass-transport deposits (MTDs), deep-water channels, sediment waves, and a range of fluid-flow phenomena such as pockmarks, pipes, seabed mound and gas hydrates. They are observed from Pliocene-aged sediments and distributed above structural highs, regional faults, and active and relict deep-water channels in the eastern part of the area, closest to the Niger Delta cone. The fluid-flow features are interpreted to be indicative of an active petroleum system in the deeper subsurface and from fluid migration along planes of deep-seated faults. MTDs are mapped at multiple levels and the volume of failed sediments increased through time within the western part of the study area. The repeated and increased volume of MTDs in the area is attributed to an increased rate of sedimentation through time and slope gradient during the late Cenozoic. The presence of repeated MTDs and fluid-flow phenomena on the Nigerian Transform Margin has implications for installations of offshore facilities as they constitute potential geohazards. The study also documents, for the first time, polygonal fault systems offshore Nigeria.

Hydrocarbon generation potential of Campano-Maastrichtian to Paleogene shales in the Benin Flank of the Anambra Basin, SW Nigeria

The hydrocarbon generation potential of the Campano-Maastrichtian to Paleogene shales from the Benin Flank (located in SW Nigeria) of the Anambra Basin, has been previously investigated mostly by studying outcrops and by relatively few subsurface data-based studies. Thus, it is expedient undertaking an assessment of the hydrocarbon generation potential of this frontier area from subsurface samples. Campano-Maastrichtian to Paleogene shale samples obtained from Egoli-1 borehole in the Benin Flank of the Anambra Basin are studied by means of HAWK programmed pyrolysis, organic petrography, and mineralogy (XRD), with the aim to explore the petroleum-generating potential and the thermal maturity. The obtained results display a significant variation of the TOC content ranging from very low (<0.5%) to significant (>5%), indicating poor to excellent oil potential based on S2 values under the condition, of course, the studied formations reached the oil window. The shales of the Nsukka and Imo Formations display lower petroleum-generating potential than these of the Mamu Formation. All the studied samples are dominated by gas-prone (type III) and inert (type IV) kerogens, with few displaying mixed II/III (oil- and gas-prone). The organic-petrography observations support partly the results of the HAWK programmed pyrolysis, as they reveal an organic-richer Mamu Formation in comparison to the Nsukka and Imo Formations; huminite/vitrinite particles (both indigenous and recycled) along with variable contents of liptinite (mostly alginite and bituminite) and inertinite macerals (mostly inertodetrinite) are hosted in the shales. The latter display a typical composition for fine-grained clastic sediments; mostly kaolinite, illite/montmorillonite, quartz, and subordinately, anatase. In terms of thermal maturity, huminite/vitrinite reflectance data points to immature stage; however, the occurrence of solid bitumens, displaying equivalent vitrinite reflectance values within the oil window, points to an active petroleum system in sequences deeper than the examined ones.

Source rock potential and spatial distribution of the stratigraphic formations in the central Mediterranean Ridge: Evidence from mud volcanic deposits and 2D seismic data

Due to the lack of deep wells in the broader region, the mud volcanic deposits (mud breccia) are the only source of direct information for the deep stratigraphic units of the Mediterranean Ridge (MR), in the eastern Mediterranean. The study of this material, combined with the available seismic data, can improve the geological understanding of this frontier exploration area.In this paper, biostratigraphic and geochemical studies are performed on mud breccia deposits from five Mud Volcanoes (MVs) in the central MR, aiming to define the sediments’ stratigraphic origin and assess the source rock potential of the individual formations. In addition, regional seismic data is used to reveal the spatial distribution of the major lithostratigraphic formations in the subsurface.Results indicate an Eocene-Miocene origin for the mud breccia of Gelendzhik, Nice, Moscow and Dublin MVs, whereas a Paleocene (?) and Cretaceous origin is suggested for the Toronto MV deposits. Most clasts represent hemipelagic mudstones/marlstones. Regarding the source rock potential of the area, it is considered that: (a) nine clasts of Miocene, Eocene and undetermined age, reflect the presence of immature and early mature, gas-prone source rocks of poor to moderate potential; (b) a small clast discovered in the matrix of Dublin MV originates from an excellent quality oil-prone source rock; and (c) the discovered solid hydrocarbons and oil droplets point to an active petroleum system in the region.Seismic interpretation defines the spatial distribution of the Post-Evaporite, Evaporite and Pre-Evaporite formations. The burial depth of the Pre-Evaporite formation (source layers of MV deposits) significantly varies from 20 to 4970 m inside the study area and is largely dependent on Evaporite thickness.

Controls on hydrocarbon accumulation in the pre-rift paleozoic and late syn-rift cretaceous sandstones in PTAH oil field, north Western Desert, Egypt: Insights from seismic stratigraphy, petrophysical rock-typing and organic geochemistry

North Western Desert (NWD) of Egypt is one of the most petroliferous provinces in North Africa. Mesozoic rift basins in the NWD host several active petroleum systems in their syn- and post-rift sedimentary successions. Also, numerous oil reserves were recently discovered in the pre-rift Paleozoic reservoirs. However, the genetic link between the pre-rift hydrocarbon plays and the syn- and post-rift accumulations is still ambiguous. Additionally, controls on distribution of the optimum rock types in the pre-rift reservoirs need further investigation. Therefore, this study integrates geochemical, seismic-stratigraphic, and petrophysical approaches to better understand these issues based on oil, seismic, and well data retrieved from the Paleozoic pre-rift “Shiffah” and the Cretaceous late syn-rift “Alam El Bueib (AEB)” sandstones in PTAH oil Field in the NWD.Oil retrieved from Shiffah and AEB pay zones displays a similar n-alkane composition dominated by cycloalkanes and nC20+ alkanes. The oil samples retain biomarker signatures of pre-Cretaceous terrestrial organofacies where oleanane is absent, isoprenoid ratio (prestane/phystane) is high (>5) and C29/C27 steranes is greater than 1.5. Shiffah and AEB oils have a common source rock and display compositional characteristics similar to NWD oils derived from the Middle Jurassic Khatatba Formation fluvio-deltaic organofacies. Deep-seated rift-faults cross-cutting the entire syn- and pre-rift successions provide the paths for the upward and downward hydrocarbon migration from Khatatba organofacies to AEB and Shiffah sandstones, respectively. Distribution of the reservoir rock types (RRTs) controlled the thickness of the hydrocarbon column. Reservoir quality decreases from RRTI to RRTIII. RRTI rocks occur in the Shiffah fluvial basin-fill facies, whereas the best RRTs in AEB are classified as RRTII and are exclusively associated with the prograding deltaic facies. Correlation between seismic facies and RRT allows the prediction of their lateral and vertical distribution. Our results highlight existence of excellent reservoir rock types in the pre-rift succession connected with the Jurassic kitchen which charged the entire syn- and post-rift reservoirs.

Cenozoic Clastic Deposits in the Thermaikos Basin in Northern Greece and Their Reservoir Potential

The Epanomi gas field discovery during the 1980s at the eastern fringe of the Thermaikos Basin in Northern Greece proved the existence of an active petroleum system in the area. Seismic and drilling exploration programs in the area provide data to study the Cenozoic clastic sequence in the Thermaikos Basin. This study aims to recognize, through core and well-log data, the wide range of facies associations from different depositional environments, which contribute to the basin fill. Additional wells from the Kassandra and Epanomi onshore areas support the conclusions of this study. A detailed core description, a cuttings evaluation, and a log analysis of selected wells were the main tools for the facies association analysis. Seismic data from the area were used to identify the lateral extension of the depositional environments in the areas between and around the wells. The Eocene–Oligocene part of the stratigraphic succession corresponds to deep-water turbidites in the middle of the basin, passing laterally to a shallow marine and locally to fluvial, alluvial, and deltaic settings. The dominant (in terms of thickness) Miocene interval consists of fluvial and shallow marine sediments, while deltaic deposits are also present. The Quaternary deposits are mostly shallow marine, with local lagoonal sediments. The reservoir properties were integrated at the last stages of the study in order to identify the most interesting facies. The outcome of this study can be useful for hydrocarbon exploration or for potential future CO2 storage.

Underexplored but not forgotten: assessing the energy resources potential of the greater Pedirka Basin region through play-based mapping

The Pedirka, Simpson and western Eromanga basins in central Australia have had a chequered exploration history which has seen only 42 wells drilled across a study area of ~210 000 km2. Exploration initially focused on conventional hydrocarbons from the 1950s–1980s, before shifting towards coal seam gas (CSG) opportunities in the mid-2000s. Active petroleum systems have been proven in the region by a non-commercial oil discovery at Poolowanna 1 in 1977, and by several wells that showed evidence of residual oil columns. CSG exploration programs have confirmed the presence of thick, marginally mature coal intervals on the flanks of the basins, but are yet to evaluate the CSG potential of the deeper troughs. Geoscience Australia, the Northern Territory Geological Survey and the South Australian Department for Energy and Mining have been collaborating on the Australia’s Future Energy Resources project to undertake an assessment of the resource potential for conventional and unconventional hydrocarbons, and the geological storage of CO2 (GSC) potential of the greater Pedirka region. The project has applied a play-based exploration approach to qualitatively assess the resource potential of the region. The Carboniferous to Cretaceous stratigraphic interval was divided into 14 plays which were evaluated for the presence of sediment-hosted energy resources through post-drill analysis, gross depositional environment mapping and common risk segment mapping. The analysis identified energy resources and GSC potential across multiple plays and locations within the study area. These results demonstrate, that while the region is underexplored, it should not be overlooked by future exploration activities.

Outcrop analogy with the subsurface geology and hydrocarbon prospectivity of Jaintiapur and adjacent areas in North-East Bangladesh

The availability of hydrocarbons in the eastern part of Bangladesh indicates the presence of active petroleum systems in the Bengal basin. Although extensive research has been conducted in the Surma basin, the correlation between structural configuration, tectonostratigraphic framework, and hydrocarbon potentiality in the basin including Jaintiapur area has not yet been established. In this study, the hydrocarbon prospectivity of Jaintiapur and the adjoining Dupigaon area has been characterized through outcrop analogy with the subsurface interpretation of seismic data along L13-01, PK-SY-5, and L13-03 lines. The main three megasequences have been recognized based on sequence stratigraphy in the Sylhet region utilizing outcrop, seismic, and well-log data. The exposed Tertiary and Quaternary formations of Jaintiapur and adjoining areas can be classified into eleven litho-stratigraphic units. Detailed facies analyses indicate that these rock units were deposited in fluvial, deltaic, and shallow marine environments. The subsurface lithology of the study area has been inferred from the petrophysical data obtained from Sylhet-7, Kailashtila-4, and Jalalabad-1 wells. Jaintiapur area lies in a tectonically complex province and is controlled by the Dauki Fault System. Folding and faulting represent intense tectonic deformation in the area. Detailed analyses of surface and subsurface geology indicate that faults pass along the rivers and transverse faults segment the reservoirs. A total of seven horizons have been interpreted using Petrel software. The seismic attribute analysis identifies leads and prospects based on transverse faults and amplitude anomalies with distinct bright spots at the PK-SY-5 line. From seismic interpretation, attribute analysis, and lithofacies distribution of Sylhet-7 well and its surround area in the Dupigaon, it seems that same gas bearing sand. Gas sands of the Sylhet-7 well indicate the possibility of gas/oil in the equivalent sedimentary sequence in the Dupigaon structure as this area is located close to and more down-dip towards the kitchen area.

PETROLEUM SYSTEMS ANALYSIS OF THE EASTERN ARABIAN PLATE: CHEMOMETRICS BASED ON A REVIEW OF THE GEOCHEMICAL CHARACTERISTICS OF OILS IN JURASSIC – CENOZOIC RESERVOIRS

This paper presents the results of an integrated geochemical study of oils in Jurassic – Cenozoic reservoirs in the eastern region of the Arabian Plate. The main objective was to analyze the active petroleum systems at a regional scale across the study area which extends from NE Iraq to SE Oman and includes the entire Persian Gulf. The dataset for the study consisted of more than 500 crude oil samples from 112 oil fields and 11 different reservoir units. This dataset was compiled from both the literature and re‐evaluated geochemical and stable isotope analyses, augmented by new analytical studies.The study documents regional variations and trends in the bulk and molecular properties and stable isotope ratios of the oil samples. Two overall clans and twelve genetic oil families and sub‐families were distinguished using multivariate statistical analysis (chemometrics) based on biomarker parameters. The age, lithology, depositional setting and organic matter type of the respective source rocks for each family/sub‐family was inferred from oil geochemical fingerprints.The results provide insights into the key geological factors that control the number, size and geochemical character of oil fields in the eastern Arabian Plate. The geographical extent of the various oil families was assessed and used to evaluate charge access and to predict migration directions and migration pathways in the study area.The results indicate the value of implementing multivariate statistical analysis on “big data” along with state‐of‐the‐art geological petroleum systems analysis and interpretation of biomarker and oil composition data to investigate complex and extended petroleum systems.

Oil to Source Rock Correlation of Besuki Area and its Role in Petroleum System of Banyumas Basin

Banyumas Basin is a basin that has signs of the presence of hydrocarbons, including oil and gasseep on the surface, which indicates active petroleum systems in the subsurface. A lot of oil and gas seeps werefound in Banyumas Basin, including oil seeps in Cipari and Besuki, while gas seeps were found in Mount Wetan,Karanglewas, and also Cipari. Exploration drilling wells have also been carried out, such as the Jati-1 Well, KarangNangka-1, Karang Gedang-1, Tjipari-1, and Mount Wetan-1, but there still has been no significant evidenceof this basin producing hydrocarbons. The TOC value of the outcrop samples taken in Cipari and Besuki have badvalues, while the crude oil has reflected a severe biodegradation process. Both oil seep samples and one extractbitumen contained high bicadinane (R (resin) annotation) and oleanane indicating both oils and extract to have aninput to Tertiary-sourced oils throughout Southeast Asia. Both oil seep samples do not exhibit similarity with theextract source rock. Based on this negative correlation there may be another source rocks in Banyumas Basin, derivedfrom rocks that are not only from Pemali Formation. The existence of this research is expected to be able toadd geological data, especially hydrocarbon geochemical data in Banyumas Basin, so that it can provide evidenceof the prospect and calculation of reserves contained in this basin, and an understanding of the source rock it self.

Several types of triangle zones from the Subandean ranges of Peru: Fish-tails, tectonic wedges and passive-roof duplexes

Surface geology, well data and 2D seismic interpretations reveal the presence of triangle zone structures at the contact of the Subandean Ranges and the Amazonian foreland in Peru. From north to south the Santiago, Marañon, Ucayali and Madre de Dios basins have been studied. Interpretations presented in this study show a great variety of structural styles at this contact area. Simple triangle zones with one back thrust, composite ones with several back thrusts, more complex double vergent ones with pop-up structures, best described as fish-tails, tectonic wedges and passive-roof duplexes are present in the study area. The role of pre-Andean tectonics and paleogeography is key to understanding the Andean evolution, due to the control on the location and geometry of the main detachment levels. The Santiago Basin is characterized by the presence of fish-tail structures with a Permian-Triassic evaporitic basal detachment located at the base of the Pucara Gr. At the Ucayali Basin, several detachment levels interact, the basal ones located within the Ordovician, Devonian, and Carboniferous defining triangle zones or tectonic wedges. At the Madre de Dios Basin, two detachment levels define the base of the triangle zone, Permian shales in the northwest at the Inambari Imbricates area, and Lower Devonian (Cabanillas Gr.) in the southeast at the Candamo area. A roof thrust is located within the Paleogene section at both the Madre de Dios and Ucayali basins, defining passive-roof duplex structures.Several detachment levels are rooted into the Lower Paleozoic; others within the Permian-Triassic section, being locally evaporitic, and finally others are located at the base of the Cretaceous. Paleozoic shales represent the main basal detachment level of the southern Subandean ranges. The role of these detachments and the role of the sedimentation rate are discussed as factors that control the development and geometry of the triangle zones described in the study area.Except for the San Martin-Sagari area of the Ucayali Basin, the triangle zones of the Santiago and Madre de Dios basins remain unexplored even though active petroleum systems are present. Sub-thrust structures at the Azulmayo area of the Madre de Dios Basin remain promising undrilled structures.

Subsurface Fluid Flow Feature as Hydrocarbon Indicator in the Alamein Basin, Onshore Egypt; Seismic Attribute Perspective

The interpretation of subsurface fluid flow features in seismic reflection data is a key part of identifying the presence of hydrocarbon and active petroleum systems. Currently, this kind of study is mainly conducted utilizing offshore seismic reflection data with very limited cases utilizing onshore seismic reflection data. In addition, the Alamein basin is an area of prolific study in onshore Egypt, with most related studies concentrating on basin analysis and reservoir characterization. Therefore, in our study we aimed to make practical and effective use of onshore seismic reflection data with seismic attribute analysis to describe seismic facies, delineating and interpreting subsurface fluid flow features. The relatively vertical V-shaped and pipe or concave-up-shaped features with distorted reflections inside them are revealed through the analysis of variance, sweetness, chaos, instantaneous frequency and the RMS amplitude of seismic attributes. These subsurface fluid flow features are a product of mature source rock that migrates hydrocarbon vertically through faults (especially deep-seated faults) and fracture systems (fault and fracture-related subsurface fluid flow features). The classification scheme presented in our study could be implemented in the onshore case worldwide.

Relationship between cyclic patterns of organic matter concentrations and their paleoenvironmental controls in the Upper Cretaceous rocks in Abu El Gharadig basin, Egypt: Cyclo-sequence stratigraphic framework

Abu El Gharadig Basin includes active petroleum systems that produce petroleum in many fields such as Abu El Gharadig Field. The hydrocarbon source rocks in the Upper Cretaceous of Bahariya and Abu Roash formations play an important role in such petroleum systems. The organic matter concentration is very important parameter to determine the potentiality of source rock occurrences. The understanding of cyclic changes of the organic matter enrichments measured in total organic carbon (TOC) is targeted in the present study together with the paleoenvironmental trends that control their distribution. The paleoenvironmental conditions are determined using the statistical analysis of palynofacies by applications such as cluster and correspondence analyses. These analyses are used to identify the palynofacies types (A, B, C, D and E) with distinctive paleoenvironmental conditions. The correspondence analysis is used to determine the paleoenvironmental trends including proximal-distal trend in axis 2 and oxygenation conditions on axis 1. The palynofacies type D and E are characterized by anoxic to suboxic distal conditions. The measured total organic carbon values are generally low (3.3 wt%) in the studied wells and the higher values have tendency to associate the distal anoxic environment of palynofacies type D. The succession was divided into 15 stratigraphic sequences using the palynofacies analysis which enabled the basinal correlations through the studied wells. Additional trace elements measurements are used to confirm the paleoenvironmental characteristics indicated by the palynofacies analysis. The G-ray log in addition to the proximal-distal trend represented by correspondence axis 2 and organic matter concentrations are subjected to time series analysis by spectral and wavelet transform applications. The analysis revealed similar ratios of the resulted periodicities that indicate existence of a common cyclic pattern. This cyclic pattern is connected to the oscillation orbitallly induced climate changes.

The hidden sedimentary basin underneath the Quaternary volcanic unit in Bogor and Kendeng area

The Java Island is an active volcanic arc that experiences several volcanism episodes, which gradually changes from South to North from the Late Oligocene to Pleistocene, following the subduction of the Australian plates underneath the Eurasian plates. During the Eocene, the southern and northern part of Java was connected as one passive margin system with the sediment supply mainly comes from Sundaland in the north. The compressional tectonics creates a flexural margin and a deep depression in the central axis of Java Island and acts as an ultimate deep-sea depocenter in the Neogene period. In contrast to the neighboring Northwest and Northeast Java Basins in the Northern edges of Java Island, the basin configuration in the East-West trending depression in median ranges of Java (from Bogor to Kendeng Troughs) are visually undetected by seismic due to the immense Quaternary volcanic eruption covers.Five focused window areas are selected for this study. A total of 1,893 Km sections, 584 rock samples, 1569 gravity and magnetic data, and 29 geochemical samples (rocks, oil, and gas samples) were acquired during the study. Geological fieldwork was focused on the stratigraphic unit composition and the observable features of deformation products from the outcrops. Due to the Paleogene deposit exposure scarcity in the Central-East Java area, the rock samples were also collected from the mud volcano ejected materials in the Sangiran Dome.The distinct subsurface configuration differences between Bogor and Kendeng Troughs are mainly in the tectonic basement involvement and the effect of the shortening on the formerly rift basin. Both Bogor and Kendeng Troughs are active petroleum systems that generate type II /III Kerogen typical of reduction zone organic material derived from transition to the shallow marine environment. The result suggests that these basins are secular from the neighboring basins with a native petroleum system specific to the palaeogeographical condition during the Paleogene to Neogene periods where the North Java systems (e.g., Northwest and Northeast Java Basin) was characterized by oxidized terrigenous type III Kerogen.

Peculiarities of Tertiary petroleum systems evolution under prograding shelf environment on the continental margin of the East Siberian Sea

The upper part of the sedimentary cover within the East Siberian Sea shelf comprises Cenozoic clinoform deposits, which accumulated in passive continental margin settings. In the Eastern Arctic, the productivity of clinoform deposits has been proved on the Alaska North Slope and in the Beaufort–Mackenzie Basin. Considering that Cenozoic clinoform deposits are widely represented in the Russian part of the Eastern Arctic, they undoubtedly attract considerable interest from the standpoint of hydrocarbons prospecting. However, despite increasingly closer attention to this interval of the sedimentary section, it is still poorly understood due to its complicated geology. The lack of drilled wells in the region imposes a considerable limitation on an understanding of sedimentary basins development. In this situation, geophysical data become the primary source of information for building geologic models in the Russian sector of the Eastern Arctic. An assessment of hypothetical Cenozoic petroleum systems of the East Siberian Sea is the main objective of this paper. It is to be said research performed under high uncertainty of input data. The results obtained from basin analysis and numerical modeling indicate the possibility that an active petroleum system may exist in the Cenozoic sedimentary wedge of the East Siberian Sea. The outlook for the clinoform complex largely depends on the source rock maturity, i.e., higher prospects should be expected in areas where the prograding wedge has maximum thickness. Considering all factors (reservoir quality prediction, proximity to a hydrocarbon kitchen, timing), the Eocene–Oligocene part of the sedimentary section appears to offer the greatest promise within the study area. Here, predominantly oil accumulations may be expected at a depth of 2.5–3.5 km below sea bottom.

The impact of active petroleum system on light hydrocarbons distribution in marine sediments

Integrated interpretation of regional geochemical data and results of the numerical BM&PSM performed at the east part of the Sea of Azov and northeast part of the Black Sea reveal a correlation between the spatial distribution of light hydrocarbons in seabed sediments and investigated petroleum systems. The obtained results point out that the spatial distribution of gaseous hydrocarbons in marine sediments reflects the geological structure of sedimentary cover, and the maturity of petroleum systems, located within the basins. The origin of background levels and anomalies of light hydrocarbons was explained depending on the present-day petroleum system activity and the structure of overburden rocks.

Modelling of the gas hydrate potential in Svalbard’s fjords

Large amounts of methane are trapped as natural gas hydrate (NGH) in the sediments of the Arctic. Unlike NGH provinces offshore west of Svalbard (Vestnesa Ridge), NGH potential in Svalbard’s fjords and near-shore environment is poorly constrained. In this study we modelled the NGH stability zone (GHSZ) to determine the NGH formation potential within the fjords of Svalbard. We applied a nearest neighbour interpolation method to dynamically derive statistical bottom-water temperature (BWT) trends from available CTD data. The BWT trends along with available geothermal gradient data constrained Svalbard-wide sub-bottom thermobaric models suitable for GHSZ modelling in the near subsurface. Analyses of source rock and fluid seepage data in Isfjorden, including 15 newly identified acoustic gas flares, indicate an active petroleum system with fluid migration reaching the seafloor with significant contributions of higher-order hydrocarbons to the gas feed. A GHSZ is predicted for most fjords at mean BWT conditions and 95:5 methane:ethane gas compositions. Suitable conditions for pure methane NGH formation are only met in the deepest parts of Isfjorden, Hinlopenstretet, Kross- and Kongsfjorden, and Rijpfjorden. Temporal constraints implemented along the well-defined Isfjorden transect indicated a notable negative response to water column warming. The predicted GHSZ across Svalbard’s fjords is likely to disappear over the next few decades.

Geological controls on focused fluid flow in the Song Hong Basin, offshore Vietnam

This study uses 2D seismic lines located in the central Song Hong Basin, covering an area of c. 3900 m2, in the water depth of c. 100 m. Focused fluid flows are developed intensively and can be classified into two types: blow - out pipe and seepage pipe. They have similar seismic characteristics as a vertical zone of disturbed seismic reflections. The significant difference between them is the blow - out pipes associated with seafloor pockmarks and paleo - pockmarks which are absent in the seepage pipe. Besides, the scale of the blow - out pipe is larger, compared with the seepage pipe. The blow - out pipe is c. 500 m wide and 450÷3500 ms TWT; the seepage pipe is smaller scale, c. 200 m wide and 500 ms TWT. Blow - out pipe is rooting from the sequence just above the diapir or deformation unit or deep lacustrine mudstones from the Late Eocene to Oligocene, and marine mudstones from the Early to Middle Miocene. The seepage pipe is rooting from the sequence above the diapir. The focused fluid flow is supposed to be controlled by the overpressured deep source layers and passive diapirism. The occurrence of focused fluid flow is an indicator for the active petroleum system in the study area. Intensive development of focused fluid flow proves a great hydrocarbon potential in the Song Hong basin.

Modeling of the Petroleum System in the Cauvery Basin, Sri Lanka

A part of the southeastern onshore area of India and the northwestern onshore area of Sri Lanka, and the Palk Strait come under the Cauvery Basin. The Indian side of the Cauvery Basin has proven hydrocarbon reserves, while the Sri Lankan sector remains relatively under-explored. Only six exploration wells drilled in the Sri Lankan sector from 1972 to 1981 was dry. Since little further exploration has taken place from 1981 to this date, the existence of an active petroleum system in the Sri Lanka sector of the basin is not known. The objective of this study was to simulate the petroleum system in the Sri Lankan sector of the Cauvery Basin on Petromod 1D software (v.12.2) using data from unpublished reports and data in the public domain. The model was validated using the measured vitrinite reflectance data. Results of the study showed that Albian and Late Cretaceous shale in the Pesalai area have relatively higher hydrocarbon source potential and that hydrocarbon exploration in the Sri Lankan sector of the Cauvery Basin should mainly target Cretaceous and Eocene clastic and carbonate reservoirs associated with faults and anticlinal traps. Hydrocarbon potential in the Pesalai area is relatively higher than that in the Palk-Bay area.

Applications of miospore quantitative stratigraphy and cyclostratigraphy in the Neocomian - Cenomanian sediments in the Western Desert, Egypt: A step in the way to biochronostratigraphy

The Lower Cretaceous section in the Western Desert witnesses regular petroleum exploration activities and contains active petroleum systems. The main tool for biostratigraphic classification of these important strata is the palynology based biozonation. The classical biozonation methods that rely on the ranges between only selected zonal palynomorphs markers or bioevents cause many problems in the correlation of the stratigraphic units. These problems slowed the development of a unified scheme and constructions of a time scale. In this study, another approach is introduced for the first time to overcome these problems. This approach depends on analytical stratigraphy that is based on a number of quantitative methods in the framework of the geo-mathematics. These quantitative methods include statistical constrained single linkage cluster analysis, graphic correlation, constrained optimization, ranking and scaling and unitary associations. These methods take into account all of the identified taxa bioevents or their co-existences. Each of these methods produces a biozonation that predict the real distribution of the palynomorphs in time and space in a different approach. In addition, these methods rank and scale the taxa bioevents in a way that can be calibrated to a time scale. The resulted biozonations are comparable through the methods. The study is based on the miospore records of 15 wells that are closely spaced to become the center for future correlations. This is an important step toward the biochronology that add the time dimension to the biostratigraphic analysis. In addition, the present study introduces for the first time the astronomical time calibration in Bassel-1 well based on the principles of cyclostratigraphy including time series analysis and age model tuning. The G-ray log of this well is tuned to 405 kyr eccentricity cycle to produce an age model that anchored on the OAEs. The age model can be developed by additional calibration and tuned to a higher resolution and used in other applications.