The Occurrence of Bedding-Parallel Fibrous Calcite Veins in Permian Siliciclastic and Carbonate Rocks in Central Thailand

Bedding-parallel fibrous calcite veins crop out at two Permian carbonate localities in the Phetchabun area, central Thailand, within the Nam Duk and Khao Khwang Formations. Samples are studied to determine their petrographic, geochemical and isotopic character, depositional and diagenetic associations and controls on the formation of fibrous calcite across the region. Biomarker and non-biomarker parameters are used to interpret organic matter sources in the vein-hosting units, the depositional environment and levels of source rock maturation in order to evaluate source rock potential in the two Formations. Carbon and oxygen isotope values of the veins and the host are determined to discuss the source of carbonates and diagenetic conditions. The petroleum assessment from the Khao Khwang and Nam Duk Formations suggests that both Formations are a petroleum potential source rock with type II/III kerogen deposited in an estuarine environment or a shallow marine environment and a slope-to-basin marine environment or an open marine environment, respectively. The bedding-parallel fibrous calcite veins from the Khao Khwang and Nam Duk Formations are divided into two types: 1) beef and, 2) cone-in-cone veins. The carbon and oxygen isotope compositions from the fibrous calcite veins suggest that the calcite veins could be precipitated from a carbon source generated in the microbial methanogenic zone. The results in this study provide a better understanding of the interrelationship between the bedding-parallel fibrous calcite veins and petroleum source rock potential.

Depositional sequence interpretation using seismic and well data of offshore Central Sumatra Basin

Offshore Central Sumatra Basin is an integral part of Central Sumatra Basin known for producing hydrocarbon basins. The derivation of stratigraphic study of seismic and well data is intended to improve accuracy of geological interpretation. Sequence stratigraphy studies have a significant role in exploratory studies to determine which depositional sequence can be inferred as hydrocarbon reservoir and its correlation in petroleum system. This study aims to identify biogenic gas sequential interpretation using seismic and well data of offshore Central Sumatra Basin. The procedure to analyze sequence stratigraphy is to identify stratigraphy surface markers using GR log, then map these markers to the seismic section that has been tied with good data to determine the distribution of each stratigraphy sequence. This study area has five depositional sequences, which are predominantly formed in marine depositional environments. Potential source rock in this area is at DS-1 which has a lacustrine depositional environment with euxinic conditions. The euxinic shale at the upper TST-1 deposit could be a source rock with hydrocarbon migration through faults. Biogenic gas reservoir potential is in Petani Formation (DS-5). Shale in MFS-5 and HST-5 could be a hydrocarbon trap, whereas LST-5 and TST-5 sandstone deposits can be a reservoir.

Last Cretaceous Geology of Taranaki Basin, New Zealand

<p>Taranaki Basin is a large sedimentary basin located along the western side of New Zealand, which contains all of this countries present petroleum production. The basin first formed as the late-Cretaceous Taranaki Rift, and the first widespread sediments are syn-rift deposits associated with this continental rifting. The Taranaki Rift was an obliquely extensional zone which transferred the movement associated with the opening of the New Caledonia Basin southward to the synchronous Tasman Sea oceanic spreading. Along the rift a series of small, en-echelon basins opened, controlled by high-angle normal and strike-slip faults. These small basins presently underlie the much larger Taranaki Basin. Since the initial rift phase, Taranaki Basin has undergone a complex Cenozoic history of subsidence, compression, additional rifting, and minor strike-slip faulting, all usually involving reactivation of the late-Cretaceous rift-controlling faults. One of the late-Cretaceous rift basins is the Pakawau Basin. Rocks deposited in this basin outcrop in Northwest Nelson as the Pakawau Group. Data from the outcrop and from wells drilled in the basin allow the Pakawau Group to be divided into two formations, the Rakopi Formation and the North Cape Formation, each with recognizable members. The Rakopi Formation (new name) is a sequence of terrestrial strata deposited by fans and meandering streams in an enclosed basin. The North Cape Formation is a transgressive sequence of marine, paralic and coastal-plain strata deposited in response to regional flooding of the rift. The coal-measure strata of the Rakopi Formation are organic rich, and are potential petroleum source rocks where buried deeply enough. In contrast, the marine portions of the North Cape Formation contain almost no organic matter and cannot be considered a potential source rock. Sandy facies within both formations have petroleum reservoir potential. The Rakopi and North Cape formations can be correlated with strata intersected by petroleum exploration wells throughout Taranaki Basin, and all syn-rift sediments can be assigned to them. The Taranaki Rift was initiated about 80 Ma, as recorded by the oldest sediments in the Rakopi Formation. The transgression recorded in the North Cape Formation propagated southwards from about 72 to 70 Ma, and the Taranaki Rift remained a large marine embayment until the end of the Cretaceous about 66.5 Ma. Shortly thereafter, a Paleocene regression caused the southern portions of Taranaki Basin to revert to terrestrial (Kapuni Group) sedimentation. The two distinct late Cretaceous sedimentary sequences of the Rakopi and North Cape formations can be identified on seismic reflection data, and the basal trangressive surface that separates them has been mapped throughout the basin. This horizon essentially marks the end of sedimentation in confined, terrestrial subbasins, and the beginning of Taranaki Basin as a single, continental-margin-related basin. Isopach maps show the Rakopi Formation to be up to 3000m thick and confined to fault- controlled basins. The North Cape Formation is up to 1500m thick and was deposited in a large north-south embayment, open to the New Caledonia basin to the northwest. This embayment was predominantly a shallow-marine feature, with shoreline and lower coastal plain facies deposited around its perimeter</p>

Last Cretaceous Geology of Taranaki Basin, New Zealand

<p>Taranaki Basin is a large sedimentary basin located along the western side of New Zealand, which contains all of this countries present petroleum production. The basin first formed as the late-Cretaceous Taranaki Rift, and the first widespread sediments are syn-rift deposits associated with this continental rifting. The Taranaki Rift was an obliquely extensional zone which transferred the movement associated with the opening of the New Caledonia Basin southward to the synchronous Tasman Sea oceanic spreading. Along the rift a series of small, en-echelon basins opened, controlled by high-angle normal and strike-slip faults. These small basins presently underlie the much larger Taranaki Basin. Since the initial rift phase, Taranaki Basin has undergone a complex Cenozoic history of subsidence, compression, additional rifting, and minor strike-slip faulting, all usually involving reactivation of the late-Cretaceous rift-controlling faults. One of the late-Cretaceous rift basins is the Pakawau Basin. Rocks deposited in this basin outcrop in Northwest Nelson as the Pakawau Group. Data from the outcrop and from wells drilled in the basin allow the Pakawau Group to be divided into two formations, the Rakopi Formation and the North Cape Formation, each with recognizable members. The Rakopi Formation (new name) is a sequence of terrestrial strata deposited by fans and meandering streams in an enclosed basin. The North Cape Formation is a transgressive sequence of marine, paralic and coastal-plain strata deposited in response to regional flooding of the rift. The coal-measure strata of the Rakopi Formation are organic rich, and are potential petroleum source rocks where buried deeply enough. In contrast, the marine portions of the North Cape Formation contain almost no organic matter and cannot be considered a potential source rock. Sandy facies within both formations have petroleum reservoir potential. The Rakopi and North Cape formations can be correlated with strata intersected by petroleum exploration wells throughout Taranaki Basin, and all syn-rift sediments can be assigned to them. The Taranaki Rift was initiated about 80 Ma, as recorded by the oldest sediments in the Rakopi Formation. The transgression recorded in the North Cape Formation propagated southwards from about 72 to 70 Ma, and the Taranaki Rift remained a large marine embayment until the end of the Cretaceous about 66.5 Ma. Shortly thereafter, a Paleocene regression caused the southern portions of Taranaki Basin to revert to terrestrial (Kapuni Group) sedimentation. The two distinct late Cretaceous sedimentary sequences of the Rakopi and North Cape formations can be identified on seismic reflection data, and the basal trangressive surface that separates them has been mapped throughout the basin. This horizon essentially marks the end of sedimentation in confined, terrestrial subbasins, and the beginning of Taranaki Basin as a single, continental-margin-related basin. Isopach maps show the Rakopi Formation to be up to 3000m thick and confined to fault- controlled basins. The North Cape Formation is up to 1500m thick and was deposited in a large north-south embayment, open to the New Caledonia basin to the northwest. This embayment was predominantly a shallow-marine feature, with shoreline and lower coastal plain facies deposited around its perimeter</p>

Bio-electrosequence interpretation of late cretaceous sediments of the Southern Bornu Basin, Nigeria

Integrated analysis that involves physical sedimentological, standard palynological and electrofacies analyses on ditch cuttings and suite of wireline logs from Gaibu–1 Well, southern Bornu were examined to identify critical sequence elements and construct a bio-sequence stratigraphical framework. Four (4) palynozones consisting of Triorites africaensis, Cretacaeiporites scabratus - Odontochitina costata, Droseridites senonicus and Syncolporites/Milfordia spp Assemblage Zones construed to be Late Cretaceous – younger successions. Nine (9) depositional sequences each with candidate maximum flooding surfaces (375, 900, 1875, 2250, 2600, 3050, 3400, 3800, 4300 m) marked by marker shales with high abundance and diversity of palynomorphs. Thus, equate with the local lithostratigraphy and global large-scale depositional cycles with candidate sequence boundaries (50, 725, 1625, 2175, 2490, 2850, 3300, 3610, 3960, 4470 m) ranging about 96.28 to 70.07 Ma. The delineated transgressive surfaces along the built sequences mark the subjected onset of marine flooding characterised with interchange of progradational to retrogradational facies. Delineated sequence elements generally show up-hole from progradational to retrogradational and aggradational that represents Lowstand Systems Tracts (LSTs), Transgressive Systems Tracts (TSTs) and Highstand Systems Tracts (HSTs) respectively. The LSTs are seen in form of prograding complex and slope fans, suggestive of good reservoirs. The TSTs consist of channel sand units and shales that depict retrogradational marine units, which could serve as both seals and source rocks for the sand units. The HSTs are made up of interplay of aggradational to progradational sediment packages that could serve as a potential source rock. The palaeoenvironmental indices depict the successions are deposited within continental to open marine settings.

TOC Prediction Using Delta Log Resistivity, and Its Distribution in Cyclostratigraphy-INPEFA Trend in “S-Field”, Kutai Basin”

S field has unique geological conditions, with a depth of maturity around 800 meters based on geochemical analysis and classified as the shallowest in the Kutai Basin compared to other fields of around 4000 meters. This is caused by this field's geological conditions, which are influenced by the tectonic gravitational force from the north and the lifting of the middle Miocene formation from below. The study aims to have better understanding on the petroleum system using the ∆ Log R to analyse the source rock, to be integrated with the Cyclostratigraphy-INPEFA log to discover which cyclic deposition trend has the higher TOC (total organic carbon) accumulation. Determining the potential source rock with the rich TOC would help the finding of a new prospect reservoir for conventional or unconventional development. ∆ Log R is a practical method for predicting TOC and depth, applied in many fields with success stories. The research focuses on TOC prediction on a delta plain environment with abundant coal source rock using sonic, density, and neutron logs as porosity logs. Because most of the Organic Content is found in Non-Reservoir Rocks, Reservoir Rocks needs to eliminate Log-Gamma Ray as a lithological interpretation. Mature Organic Rocks with a high TOC value and excellent porosity will show high resistivity; this is because Kerogen, which is dominant in shale, validates this TOC prediction for geochemical analysis. Cyclostratigraphy-INPEFA log is generated from a particular formula based on cyclic deposition concept that refers to the orbital change that affects earth insolation. The phenomena cause the sea-level change (eustasy). When the sea level drops (cooling phase), the coarse sediment will be deposited., Whereas the finer sediment will be deposited when the sea-level rises (warming phase). This study shows that predicted TOC accumulation is much higher in the warming phase.

Biogenic and Thermogenic Gas Potential of The Underexplored Southern Kutai Basin, Offshore East Kalimantan: A Case Study from South Sesulu Block

The Southern Kutai Basin is currently less explored than the Mahakam area and others in the northern part of this Basin. Therefore, this research focuses on knowing the potential of active source rocks that can produce hydrocarbons, the volume that can be produced and its migration that can encourage exploration activities in this area. The method of this research is to conduct a geochemical evaluation as a screening of source rock which has the potential to generate biogenic and thermogenic hydrocarbons. Rock - Eval Pyrolysis, biomarker analysis in the form of Gas Chromatography - Mass Spectrometry (GC-MS) evaluated from eight exploration wells was used to determine the quantity, quality, maturity and environment of organic material deposition. 1D and 3D basin modelling using geochemical and geological evaluations to determine the presence of thermogenic hydrocarbon shows accumulations around the study area through migration analysis. Isotope analysis, thermal gradient and sedimentation rates are used to determine the environment and activity of anaerobic micro-organisms in generating biogenic gases. Geophysical analysis including interpretation and mapping of subsurface structures using 2D and 3D seismic are used to determine the distribution of potential source rock and its migration history. Geochemical data indicate that biogenic gas have been generated from within the Late Miocene tol recent sedimentary section where the quantity of organic matter is fair to excellent (0.51 – 7.31 %wt TOC) which represents the results of micro-organism activities where sedimentation rates avg 6,2 x 107 ton/year. Thermogenic gas; however, is estimated from the Late Oligocene to Early Miocene series of post rift sediment throughout the Kutai Basin.

Miocene Turbidite Sequence as Potential Reservoir and Source Rock Of Mamberamo Basin: An Insight From Fieldwork in Metaweja Area, Central Mamberamo District, Papua

The geology of the Metaweja area is characterized by the turbidite sequence which are deposited in the deep-sea environment during the Miocene and exposed to surface due to the latest deformation. The research was conducted to identify the potential source rock and reservoir rock within the turbidite deposits. In the study area, there are three types of rock units, calcareous shale units formed in the Late Miocene, Sandstone unit and interbedded siltstone-sandstone unit that were deposited in Middle Miocene. Measured section was carried out at the several stations in order to analyze the turbid current deposition mechanism. Measured section of the alternating unit of sandstone - siltstone are observed at several places where the unit has intercalation of shale, coal and iron oxide. Some syn-depositional sedimentary structure also found within this unit. The carbonate shale unit has good total organic content (TOC) ranging from 0.51wt% to 2.56wt%. Pyrolysis analysis has S2 value 1.31 mg/g to 1.34 mg/g, Hydrogen Index (HI) 35 mgHC/g to 49 mgHC/g, Oxygen Index (OI) 35 mgHC/g to 49 mgHC/g, Tmax 430 °C to 434 °C and Vitrinite Reflecteance index (Ro) 0.32% to 0.54%. The carbonate shale characterized as the type III kerogen which prone gas source rock and interpreted as immature to early mature source rock. The petrography analysis of alternating rocks of sandstone - siltstone has characteristics of sandstones with 44% of volcanic lithic fragment composition, 20% matrix 10% clay size fragments, secondary porosity reaches 10% and 13% cement carbonate calcite. Based on the petrography analysis, this unit could be interpreted as reservoir rock, although we need further analysis for the Permeability measurement.

STRUCTURAL SETTING AND HYDROCARBON POTENTIAL OF KHARITE-NUQRA-KOMOMBO RIFT BASINS, SOUTH EGYPT: A PROSPECTIVE APPROACH

— The sedimentary basins of Kharite, Nuqra, and Komombo are outlined with the potential geophysical data where the southern N-S Egyptian Nile course separates Nuqra and Kharit as the East Nile basins. Two commercial discoveries of Al Barka and West El Barka oil fields have been declared in the West Nile basin of Komombo. This work presents our insights on the structural setting and hydrocarbon system of these basins through our integrating results in form of interpreted seismic profiles and structural mapping on the different horizons, 1D basin modeling, geochemistry, and geologic maps based on high-resolution satellite images. Structurally, these rift basins are developed as NWtrending asymmetric fault-bounded half-grabens (oblique to the Red Sea trend) through the reactivation of a major Precambrian Pan African tectonic zone by the Neocomian extensional tectonics. The high potential source rock with up to 7wt. % TOC of kerogen II are proved in the Komombo basin. The seismic and drilling results show Neocomian-Barremian maximum subsidence and the possible occurrence of similar Neocomian source rocks in the eastern Nile basins. Additionally, the convenient clastic reservoir rocks occurred in the entire stratigraphic succession and seal capacity in the upper interval of Senonian-Paleocene. Good opportunities for hydrocarbon structural trapping take place in form of rotated fault blocks by the Early Cretaceous extensional rift and mildly inverted structures by a long span of Late Cretaceous to post-Early Eocene Syrian Arc compression in South Egypt. These elements were verified by Al Baraka discovery and present a promising play concept for hydrocarbon potential in the Kharit and Nuqra basins. The geochemical data indicate different basins exhumation and maturation levels, as the 0.5% calculated vitrinite reflectance "Ro" values occur at the depths of 1200ft and 2100ft in Nuqra and Komombo basins, respectively

Source Rock Evaluation of the Upper Triassic Baluti Formation in Bekhme-1 and Gulak-1 Wells from Akri-Bijeel Block, Kurdistan-Iraq

This study reports on the petroleum potential of the Upper Triassic Baluti Formation in Bekhme-1 and Gulak-1 Wells from Akri¬-Bijeel Block within the Bekhme Anticline area, North of Erbil City. The area is a part of the Zagros Fold and Thrust Belt, and is locally situated within the High Folded Zone. Typically, the Baluti Formation is composed of gray and green shale calcareous dolomite with intercalations of thinly bedded dolomites, dolomitic limestones, and silicified limestones which in places are brecciated. The geochemical indicators obtained from Rock-Eval pyrolysis of Baluti samples gave Total Organic Carbon content (TOC wt. %) average values of 0.15 and 0.18 wt. % and potential hydrocarbon content (S2) average values of 0.78 mg HC/g rock and 0.58 mg HC/g rock for Bekhme-1 and Gulak-1 respectively, suggesting a source rock of poor potential. The type of organic matter is of mixed type II-III and III kerogens with an average Tmax value of 440 °C for both boreholes, exhibiting early to peak stage of thermal maturity. Considering the results of this study, it is concluded that Baluti Formation in the studied area can not be regarded as a potential source rock for hydrocarbon generation.