scholarly journals Petroleum geochemical aspects of the Mandawa Basin, coastal Tanzania: the origin of migrated oil occurring today as partly biodegraded bitumen

2019 ◽  
Vol 27 (1) ◽  
pp. petgeo2019-050
Author(s):  
Tesfamariam Berhane Abay ◽  
Katrine Fossum ◽  
Dag Arild Karlsen ◽  
Henning Dypvik ◽  
Lars Jonas Jørgensen Narvhus ◽  
...  
Keyword(s):  
Source Rock ◽  
Vitrinite Reflectance ◽  
Upper Jurassic ◽  
Petroleum System ◽  
Geochemical Data ◽  
Petroleum Systems ◽  
Wet Gas ◽  
Depositional System ◽  
Marine Algal ◽  
Gas Fields

The shallow-marine Upper Jurassic–Lower Cretaceous sedimentary successions of the Mandawa Basin, coastal Tanzania, are located about 80 km away from the offshore gas discoveries of Block 2, Tanzania. In this paper we present petroleum geochemical data, including bitumen extracted from outcrop samples which are relevant to the understanding of the onshore ‘Petroleum System’ and possibly also to the offshore basin. Despite some biodegradation and weathering, common to all outcrop samples, most bitumen samples analysed contain mature migrated oil. The maturity span of geomarkers (C13–C15 range) covers the entire oil and condensate/wet gas window (Rc = 0.7–2% Rc, where Rc is the calculated vitrinite reflectance), with the biomarkers generally indicating the oil window (Rc = 0.7–1.3% Rc). This suggests that the bitumen extracts represent several phases of migrated oil and condensate, which shows that the samples are part of an active or recently active migration regime or ‘Petroleum System’. The source-rock facies inferred for the bitumen is Type II/III kerogen of siliciclastic to carbonate facies. This is oil-prone kerogen, typical for a marine depositional system with an influx of proximal-derived terrigenous material blended in with in situ marine algal organic matter (OM). Application of age-specific biomarkers such as the C28/C29-steranes, extended tricyclic terpane ratio (ETR), nordiacholestanes and the aromatic steroids suggest that more than one source rock have contributed to the bitumen. Possible ages are limited to the Mesozoic (i.e. excluding the Late Paleozoic), with the most likely source rock belonging to the Early Jurassic. More geochemical and geological studies should be undertaken to further develop the general understanding of the petroleum system of the Mandawa Basin and its implications to the ‘Petroleum Systems’ both offshore and onshore. This paper also presents a reinterpretation of published gas composition and isotope data on the Pande, Temane and Inhassoro gas fields (Mozambique) with implications for possible oil discoveries in the gas-dominated region.

scholarly journals Geochemical Characterization and Thermal Maturation of Cerrejón Formation: Implications for the Petroleum System in the Ranchería Sub-Basin, Colombia

Geosciences ◽  
2020 ◽  
Vol 10 (7) ◽  
pp. 258
Author(s):  
Luis Felipe Cruz-Ceballos ◽  
Mario García-González ◽  
Luis Enrique Cruz-Guevara ◽  
Gladys Marcela Avendaño-Sánchez
Keyword(s):  
Source Rock ◽  
Vitrinite Reflectance ◽  
Central Area ◽  
Petroleum System ◽  
Geochemical Data ◽  
Burial History ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Rock Eval ◽  
Upper Paleocene

The Upper Paleocene Cerrejón Formation is a great source of coal in Colombia. The northeastern part of the Ranchería Sub-Basin sees the most intense mining activity. As a consequence, all geological studies have been concentrated on this region. Consequently, neither the distribution of the Cerrejón Formation, nor the quality and quantity of organic matter in the rest of the sub-basin is clear. In this study, we analyzed new geochemical data from Rock–Eval pyrolysis analyses and vitrinite reflectance using core samples from the ANH-CAÑABOBA-1 and ANH-CARRETALITO-1 wells. Based on this information, it was possible to classify the geochemical characteristics of the Cerrejón Formation as a source rock, particularly in the central area of the sub-basin, which had not been extensively studied before. Additionally, based on the interpretation of seismic reflection data, the numerical burial history models were reconstructed using PetroMod software, in order to understand the evolution of the petroleum system in the sub-basin. The models were calibrated with the data of maximum pyrolysis temperature (Tmax), vitrinite reflectance (%Ro), and bottom hole temperature (BHT). We infer the potential times of the generation and expulsion of hydrocarbon from the source rock.

Petroleum system of Miocene troughs of the Pannonian Basin in southern Hungary, based on 3D basin modeling

2018 ◽  
Vol 6 (1) ◽  
pp. SB37-SB50 ◽  
Author(s):  
Viktor Lemberkovics ◽  
Edina Kissné Pável ◽  
Balázs Badics ◽  
Katalin Lőrincz ◽  
Alexander Rodionov ◽  
...  
Keyword(s):  
Source Rock ◽  
Pannonian Basin ◽  
System Modeling ◽  
Petroleum System ◽  
Source Rocks ◽  
Small Scale ◽  
Basin Modeling ◽  
Petroleum Systems ◽  
Wet Gas ◽  
Late Neogene

The role of the Middle-Upper Miocene source rocks in the Late Neogene petroleum system of the Pannonian Basin is undoubtedly significant, but it is not entirely understood. Only a few general publications exist that describe these sediments and their importance. We have focused on understanding the Neogene tectono-stratigraphic development and petroleum systems of these relatively small syn-rift grabens in southern Hungary. We have developed a workflow for organic geochemical, seismic, and facies interpretation; basin subsidence; and 3D basin modeling to better understand the Miocene-Pliocene-age petroleum system in a [Formula: see text] study area. This area fully covers two small-scale (less than [Formula: see text] size each) troughs filled by syn-rift and postrift deposits in large thickness with significantly different structural histories. During our investigation, six source rock beds were identified and built into the model. Thousands of meters of Lower Miocene, (Karpatian age) sediment accumulated in a “pull-apart,” but later structurally inverted Kiskunhalas Trough in the south, where four moderate- to good-quality (2 wt% estimated original total organic carbon [TOC], 200 HI), dominantly gas-prone, immature to wet gas mature source rock beds were identified. In the overlying Middle Miocene (Badenian age) sediments, generally good quality (2 wt% estimated original [TOC], 300–500 HI, type II and II-S), oil-prone, dominantly oil mature source bed was identified. This layer, as the regional Miocene source rock, is mainly responsible for the known hydrocarbon (HC) accumulations. The 3D basin and petroleum system modeling helped us understand the HC migration into the already-discovered fields as well as identify possible future exploration objects.

Petroleum systems and results of exploration on the Atlantic margins of the UK, Faroes & Ireland: what have we learnt?

2016 ◽  
Vol 8 (1) ◽  
pp. 187-197 ◽  
Author(s):  
Iain C. Scotchman ◽  
Anthony G. Doré ◽  
Anthony M. Spencer
Keyword(s):  
Upper Jurassic ◽  
Petroleum System ◽  
Source Rocks ◽  
Gas Field ◽  
Petroleum Systems ◽  
Unknown Source ◽  
Porcupine Basin ◽  
Break Up ◽  
Northern North Sea ◽  
The Uk

AbstractThe exploratory drilling of 200 wildcat wells along the NE Atlantic margin has yielded 30 finds with total discovered resources of c. 4.1×109 barrels of oil equivalent (BOE). Exploration has been highly concentrated in specific regions. Only 32 of 144 quadrants have been drilled, with only one prolific province discovered – the Faroe–Shetland Basin, where 23 finds have resources totalling c. 3.7×109 BOE. Along the margin, the pattern of discoveries can best be assessed in terms of petroleum systems. The Faroe–Shetland finds belong to an Upper Jurassic petroleum system. On the east flank of the Rockall Basin, the Benbecula gas and the Dooish condensate/gas discoveries have proven the existence of a petroleum system of unknown source – probably Upper Jurassic. The Corrib gas field in the Slyne Basin is evidence of a Carboniferous petroleum system. The three finds in the northern Porcupine Basin are from Upper Jurassic source rocks; in the south, the Dunquin well (44/23-1) suggests the presence of a petroleum system there, but of unknown source. This pattern of petroleum systems can be explained by considering the distribution of Jurassic source rocks related to the break-up of Pangaea and marine inundations of the resulting basins. The prolific synrift marine Upper Jurassic source rock (of the Northern North Sea) was not developed throughout the pre-Atlantic Ocean break-up basin system west of Britain and Ireland. Instead, lacustrine–fluvio-deltaic–marginal marine shales of predominantly Late Jurassic age are the main source rocks and have generated oils throughout the region. The structural position, in particular relating to the subsequent Early Cretaceous hyperextension adjacent to the continental margin, is critical in determining where this Upper Jurassic petroleum system will be most effective.

scholarly journals Geochemical characteristics and depositional environments of the Narimba Formation source rock, Bass Basin, Australia

2020 ◽  
Vol 10 (8) ◽  
pp. 3207-3225
Author(s):  
Mohamed Ragab Shalaby ◽  
Muhammad Izzat Izzuddin bin Haji Irwan ◽  
Liyana Nadiah Osli ◽  
Md Aminul Islam
Keyword(s):  
Source Rock ◽  
Vitrinite Reflectance ◽  
Depositional Environments ◽  
Geochemical Characteristics ◽  
Type Ii ◽  
Wet Gas ◽  
Kerogen Type ◽  
Rock Characterization ◽  
Rock Eval ◽  
Oil Gas

Abstract This research aims to conduct source rock characterization on the Narimba Formation in the Bass Basin, Australia, which is made of mostly sandstone, shale and coal. The geochemical characteristics and depositional environments have been investigated through a variety of data such as rock–eval pyrolysis, TOC, organic petrography and biomarkers. Total organic carbon (TOC) values indicated good to excellent organic richness with values ranging from 1.1 to 79.2%. Kerogen typing of the examined samples from the Narimba Formation indicates that the formation contains organic matter capable of generating kerogen Type-III, Type-II-III and Type-II which is gas prone, oil–gas prone and oil prone, respectively. Pyrolysis maturity parameters (Tmax, PI), in combination with vitrinite reflectance and some biomarkers, all confirm that all samples are at early mature to mature and are in the oil and wet gas windows. The biomarkers data (the isoprenoids (Pr/Ph), CPI, isoprenoids/n-alkanes distribution (Pr/nC17 and Ph/nC18), in addition to the regular sterane biomarkers (C27, C28 and C29) are mainly used to evaluate the paleodepositional environment, maturity and biodegradation. It has been interpreted that the Narimba Formation was found to be deposited in non-marine (oxygen-rich) depositional environment with a dominance of terrestrial plant sources. All the analyzed samples show clear indication to be considered at the early mature to mature oil window with some indication of biodegradation.

scholarly journals Biomarkers and C and S Isotopes of the Permian to Triassic Solid Bitumen and Its Potential Source Rocks in NE Sichuan Basin

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-14 ◽  
Author(s):  
Chunfang Cai ◽  
Chenlu Xu ◽  
Wenxiang He ◽  
Chunming Zhang ◽  
Hongxia Li
Keyword(s):  
Source Rock ◽  
Vitrinite Reflectance ◽  
Lower Triassic ◽  
Source Rocks ◽  
Upper Permian ◽  
Solid Bitumen ◽  
Lower Silurian ◽  
High Maturity ◽  
Gas Fields ◽  
Extractable Organic Matter

The potential parent source rocks except from Upper Permian Dalong Formation (P3d) for Upper Permian and Lower Triassic solid bitumen show high maturity to overmaturity with equivalent vitrinite reflectance (ERo) from 1.7% to 3.1% but have extractable organic matter likely not contaminated by younger source rocks. P3d source rocks were deposited under euxinic environments as indicated by the pyrite δ34S values as light as -34.5‰ and distribution of aryl isoprenoids, which were also detected from the Lower Silurian (S1l) source rock and the solid bitumen in the gas fields in the west not in the east. All the solid bitumen not altered by thermochemical sulfate reduction (TSR) has δ13C and δ34S values similar to part of the P3l kerogens and within the S1l kerogens. Thus, the eastern solid bitumen may have been derived from the P3l kerogens, and the western solid bitumen was likely to have precracking oils from P3l kerogens mixed with the S1l or P3d kerogens. This case-study tentatively shows that δ13C and δ34S values along with biomarkers have the potential to be used for the purpose of solid bitumen and source rock correlation in a rapidly buried basin, although further work should be done to confirm it.

Geochemical modelling of diagenetic reactions in a sub-arkosic sandstone

Clay Minerals ◽  
2000 ◽  
Vol 35 (1) ◽  
pp. 57-67 ◽  
Author(s):  
S. A. Barclay ◽  
R. H. Worden
Keyword(s):  
Source Rock ◽  
Upper Jurassic ◽  
Path Model ◽  
Geochemical Data ◽  
Oil Generation ◽  
Northern North Sea ◽  
Corroborative Evidence ◽  
Mineral Cements ◽  
Diagenetic Reactions ◽  
Arkosic Sandstone

AbstractA reaction path model was constructed in a bid to simulate diagenesis in the Magnus Sandstone, an Upper Jurassic turbidite reservoir in the Northern North Sea, UKCS. The model, involving a flux of source rock-derived CO2 into an arkosic sandstone, successfully reproduced simultaneous dissolution of detrital K-feldspar and growth of authigenic quartz, ankerite and illite. Generation of CO2 occurred before and during the main phase of oil generation linking source rock maturation with patterns of diagenesis in arkosic sandstones and limiting this type of diagenesis to the earlier stages of oil charging. Independent corroborative evidence for the model is provided by formation water geochemical data, carbon isotope data from ankerite and produced gas phase CO2 and the presence of petroleum inclusions within the mineral cements. The model involves a closed system with respect to relatively insoluble species such as SiO2 and Al2O3 but is an open system with respect to CO2. There are up to seven possible rate-controlling steps including: influx of CO2, dissolution of K-feldspar, precipitation of quartz, ankerite and illite, diffusive transport of SiO2 and Al2O3 from the site of dissolution to the site of precipitation and possibly the rate of influx of Mg2+ and Ca2+. Given the large number of possible controls, and contrary to modern popular belief, the rate of quartz precipitation is thus not always rate limiting.

scholarly journals Analysis of the Petroleum System of Dima Oil Field by Using PetroMoD 1D

2021 ◽  
pp. 526-531
Author(s):  
Haider A. F. Al-Tarim
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Petroleum System ◽  
Oil Field ◽  
Reservoir Rock ◽  
Geological Time ◽  
Reservoir Rocks ◽  
Petroleum Systems ◽  
Geological Age ◽  
Stratigraphic Succession

The study of petroleum systems by using the PetroMoD 1D software is one of the most prominent ways to reduce risks in the exploration of oil and gas by ensuring the existence of hydrocarbons before drilling.      The petroleum system model was designed for Dima-1 well by inserting several parameters into the software, which included the stratigraphic succession of the formations penetrating the well, the depths of the upper parts of these formations, and the thickness of each formation. In addition, other related parameters were investigated, such as lithology, geological age, periods of sedimentation, periods of erosion or non-deposition, nature of units (source or reservoir rocks), total organic carbon (TOC), hydrogen index (HI) ratio of source rock units, temperature of both surface and formations as they are available, and well-bottom temperature.      Through analyzing the models by the evaluation of the source rock units, the petrophysical properties of reservoir rock units, and thermal gradation with the depth during the geological time, it became possible to clarify the elements and processes of the petroleum system of the field of Dima. It could be stated that Nahr Umr, Zubair, and Sulaiy formations represent the petroleum system elements of Dima-1 well.

PETROLEUM SYSTEMS OF THE PETREL SUB-BASIN-AN INTEGRATED APPROACH TO BASIN ANALYSIS AND IDENTIFICATION OF HYDROCARBON EXPLORATION OPPORTUNITIES

1996 ◽  
Vol 36 (1) ◽  
pp. 248 ◽  
Author(s):  
B.A. McConachie ◽  
M.T. Bradshaw ◽  
J. Bradshaw
Keyword(s):  
Source Rock ◽  
Outer Part ◽  
Integrated Approach ◽  
Petroleum System ◽  
Hydrocarbon Exploration ◽  
Petroleum Potential ◽  
Petroleum Systems ◽  
Marine Source Rock ◽  
Marine Source ◽  
Timor Sea

A petroleum system evaluation of the Petrel Sub-basin in the Bonaparte Gulf, northwest Australia, suggests that the wells drilled in the area have not fully evaluated the petroleum potential. Some of the lowest risk plays in the basin have not been tested adequately or have not been assessed in probable economic fairways.Several important discoveries have highlighted the existence of at least three petroleum systems in the Petrel Sub-basin; Larapintine, Transitional and Gondwanan. Best known are the Gondwanan gas discoveries at Petrel, Tern and most recently Fishburn, where hydrocarbons are reservoired in Late Permian sandstones and are probably sourced from Permian deltaic sequences. Kurt her inshore, oil has been recovered from Carboniferous and Early Permian reservoirs at Turtle and Barnett. The source of the oil is considered to be Carboniferous anoxic marine shales of a distinct petroleum system transitional between the Gondwanan and Larapintine systems (Milligans Formation source rock and Late Carboniferous to Permian reservoirs). Onshore, there is a gas discovery at Gariinala-1 and significant oil shows in Ningbing-1, in Late Devonian Larapintine system rocks. Geochemical analysis of the oil shows it to be sourced from a carbonate marine source rock, different from the clastic derived oils obtained from Turtle and Barnett.Recent discoveries in the Timor Sea have provoked a re-assessment of the very similar, largely untested, Mesozoic, Westralian petroleum system in the outer part of the Petrel Sub-basin. The prospective Mesozoic play fairway occurs in the northern part of the Petrel Sub-basin, extending into Area B of the Zone of Cooperation.

Petroleum Geologic Elements and Petroleum Systems in the Northern Apennines Basin

2012 ◽  
Vol 616-618 ◽  
pp. 935-938
Author(s):  
Hai Yan Hu ◽  
Song Lu ◽  
Hang Zhou Xiao
Keyword(s):  
Source Rock ◽  
Upper Cretaceous ◽  
Petroleum System ◽  
Northern Apennines ◽  
Late Triassic ◽  
Petroleum Systems ◽  
Italian Peninsula

The Northern Apennines lies in the northern Italian Peninsula. The basin has the formation of Mesozoic-Cenozoic depocentries. The source rock is Emma limestone and Late Triassic source rock, which generated at the depth of 5-7 km. The reservoir included the Upper Cretaceous-Eocene Scaglia Formation and Liassic Noriglio Limestone. The seal included Scaglia Cinerea Formation, Cerro Marls Formation and unconformity upper marls. The petroleum systems are The Emma Petroleum System and Marnoso Petroleum System.

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