A NEW MODEL FOR THE HUTTON/BIRKHEAD RESERVOIR/SEAL COUPLET AND THE ASSOCIATED BIRKHEAD-HUTTON(!) PETROLEUM SYSTEM

1998 ◽  
Vol 38 (1) ◽  
pp. 724 ◽  
Author(s):  
P.J. Boult ◽  
E. Lanzilli ◽  
B.H. Michaelsen ◽  
D.M. McKirdy ◽  
M.J. Ryan
Keyword(s):  
Weak Link ◽  
Petroleum System ◽  
Source Rocks ◽  
Age Dating ◽  
New Model ◽  
Biomarker Analysis ◽  
Seismic Sequence Stratigraphy ◽  
Migration Pathways ◽  
Live Oil ◽  
Eromanga Basin

Biomarker analysis of source rocks and oils from the Permian and Jurassic of the central Patchawarra Trough and the Gidgealpa area, reveal that much of the oil in the Eromanga Basin may have a significant lateral migrational component and be of Jurassic (i.e. intra-Eromanga) origin. Differences in hopane signatures can be used to discriminate between palaeo-oil and presently migrating live oil, and to constrain migration pathways. Thus, in some locations the identification of new source kitchens has been made possible by a combination of seal and biomarker analysis taking into account stratigraphic inheritance on conventional structural drainage maps. 3D seismic, sequence stratigraphy, dipmeter interpretation and neodymium model age dating together with conventional correlation techniques, have provided a new model for the deposition of the Hutton Sandstone to Birkhead Formation transition in the Eromanga Basin. Analysis of seal and carrier bed properties through time, in combination with hydrocarbon geochemistry and thermal modelling, indicates that the Birkhead-Hutton (!)' petroleum system has produced significant quantities of oil in the Cooper Basin sector of the Eromanga Basin.A disconf ormity near the base of the Hutton/Birkhead transition has controlled the location of oil-prone source rocks within the Birkhead Formation and stratigraphically focussed migration along palaeo-topographic ridges. A diachronous influx of volcanic-arc-derived (VAD) sediment within the Birkhead Formation has been traced right across the productive part of the Eromanga Basin. This influx of VAD sediment is associated with the main seal to underlying accumulations within both the lower Birkhead Formation and Hutton Sandstone. Sands comprising VAD sediment, which are juxtaposed, form the weak link within the main seal. The sediments between the VAD influx and the underlying unconformity in many locations constitute a waste zone.Palaeo-oil columns are common beneath extant, live oil accumulations. This indicates that a possible decrease in seal potential of the VAD sediment has occurred over time. The main seals to underlying accumulations were originally static, water-wet capillary seals which, mostly through an alteration of wettability, changed to simple permeability seals for currently migrating oil. Seal analysis, biomarker studies and geothermal modelling indicate that a double migration pulse has occurred in some areas of the Eromanga Basin. Palaeo-oil columns are related to a Late Cretaceous charge, and live oil accumulations to presently migrating oil.

scholarly journals Analysis of Petroleum System for Exploration and Risk Reduction in Abu Madi/Elqar'a Gas Field, Nile Delta, Egypt

2012 ◽  
Vol 2012 ◽  
pp. 1-10 ◽  
Author(s):  
Said Keshta ◽  
Farouk J. Metwalli ◽  
H. S. Al Arabi
Keyword(s):  
Nile Delta ◽  
Organic Matter Content ◽  
Petroleum System ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Basin Modeling ◽  
Burial History ◽  
Gas Field ◽  
Upper Miocene ◽  
Migration Pathways

Abu Madi/El Qar'a is a giant field located in the north eastern part of Nile Delta and is an important hydrocarbon province in Egypt, but the origin of hydrocarbons and their migration are not fully understood. In this paper, organic matter content, type, and maturity of source rocks have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. Modeling of the empirical data of source rock suggests that the Abu Madi formation entered the oil in the middle to upper Miocene, while the Sidi Salem formation entered the oil window in the lower Miocene. Charge risks increase in the deeper basin megasequences in which migration hydrocarbons must traverse the basin updip. The migration pathways were principally lateral ramps and faults which enabled migration into the shallower middle to upper Miocene reservoirs. Basin modeling that incorporated an analysis of the petroleum system in the Abu Madi/El Qar'a field can help guide the next exploration phase, while oil exploration is now focused along post-late Miocene migration paths. These results suggest that deeper sections may have reservoirs charged with significant unrealized gas potential.

scholarly journals Analysis of Geologic CO2 Migration Pathways in Farnsworth Field, NW Anadarko Basin

Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7818
Author(s):  
Jolante van Wijk ◽  
Noah Hobbs ◽  
Peter Rose ◽  
Michael Mella ◽  
Gary Axen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Petroleum System ◽  
Oil Field ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Tracer Study ◽  
Deep Basin ◽  
Anadarko Basin ◽  
System Models ◽  
Migration Pathways

This study reports on analyses of natural, geologic CO2 migration paths in Farnsworth Oil Field, northern Texas, where CO2 was injected into the Pennsylvanian Morrow B reservoir as part of enhanced oil recovery and carbon sequestration efforts. We interpret 2D and 3D seismic reflection datasets of the study site, which is located on the western flank of the Anadarko basin, and compare our seismic interpretations with results from a tracer study. Petroleum system models are developed to understand the petroleum system and petroleum- and CO2-migration pathways. We find no evidence of seismically resolvable faults in Farnsworth Field, but interpret a karst structure, erosional structures, and incised valleys. These interpretations are compared with results of a Morrow B well-to-well tracer study that suggests that inter-well flow is up-dip or lateral. Southeastward fluid flow is inhibited by dip direction, thinning, and draping of the Morrow B reservoir over a deeper, eroded formation. Petroleum system models predict a deep basin-ward increase in temperature and maturation of the source rocks. In the northwestern Anadarko Basin, petroleum migration was generally up-dip with local exceptions; the Morrow B sandstone was likely charged by formations both below and overlying the reservoir rock. Based on this analysis, we conclude that CO2 escape in Farnsworth Field via geologic pathways such as tectonic faults is unlikely. Abandoned or aged wellbores remain a risk for CO2 escape from the reservoir formation and deserve further monitoring and research.

THE EROMANGA BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 379
Author(s):  
H.R.B. Wecker
Keyword(s):  
Middle Triassic ◽  
Significant Proportion ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Structural Deformation ◽  
Tectonic Activity ◽  
Hydrocarbon Generation ◽  
Basin Region ◽  
Migration Pathways ◽  
Eromanga Basin

The Eromanga Basin, encompassing an area of approximately 1 million km2 in Central Australia, is a broad intracratonic downwarp containing up to 3000 m of Middle Triassic to Late Cretaceous sediments.Syndepositional tectonic activity within the basin was minimal and the main depocentres largely coincide with those of the preceding Permo- Triassic basins. Several Tertiary structuring phases, particularly in the Early Tertiary, have resulted in uplift and erosion of the Eromanga Basin section along its eastern margin, and the development of broad, northwesterly- to northeasterly- trending anticlines within the basin. In some instances, high angle faults are associated with these features. This structural deformation occurred in an extensional regime and was strongly influenced by the underlying Palaeozoic structural grain.The Eromanga Basin section is composed of a basal, dominantly non- marine, fluvial and lacustrine sequence overlain by shallow marine deposits which are in turn overlain by another fluvial, lacustrine and coal- swamp sequence. The basal sequence is the principal zone of interest to petroleum exploration. It contains the main reservoirs and potential source rocks and hosts all commercial hydrocarbon accumulations found to date. While the bulk of discovered reserves are in structural traps, a significant stratigraphic influence has been noted in a number of commercially significant hydrocarbon accumulations.All major discoveries have been in the central Eromanga Basin region overlying and adjacent to the hydrocarbon- productive, Permo- Triassic Cooper Basin. The mature Permian section is believed to have contributed a significant proportion of the Eromanga- reservoired hydrocarbons. Accordingly, structural timing and migration pathways within the Permian and Middle Triassic- Jurassic sections are important factors for exploration in the central Eromanga Basin region. Elsewhere, in less thermally- mature areas, hydrocarbon generation post- dates Tertiary structuring and thus exploration success will relate primarily to source- rock quality, maturity and drainage factors.Although exploration in the basin has proceeded spasmodically for over 50 years, it has only been in the last decade that significant exploration activity has occurred. Over this recent period, some 450 exploration wells and 140 000 km of seismic acquisition have been completed in the pursuit of Eromanga Basin oil accumulations. This has resulted in the discovery of 227 oil and gas pools totalling an original in- place proved and probable (OOIP) resource of 360 MMSTB oil and 140 BCF gas.Though pool sizes are generally small, up to 5 MMSTB OOIP, the attractiveness of Eromanga exploration lies in the propensity for stacked pools at relatively shallow depths, moderate to high reservoir productivity, and established infrastructure with pipelines to coastal centres. Coupled with improved exploration techniques and increasing knowledge of the basinal geology, these attributes will undoubtedly ensure the Eromanga Basin continues to be a prime onshore area for future petroleum exploration in Australia.

NEW INSIGHTS INTO THE ACTIVE PETROLEUM SYSTEMS IN THE COOPER AND EROMANGA BASINS, AUSTRALIA

1999 ◽  
Vol 39 (1) ◽  
pp. 263 ◽  
Author(s):  
C.J. Boreham ◽  
R.E. Summons
Keyword(s):  
Carbon Number ◽  
Carbon Isotopic Composition ◽  
Petroleum System ◽  
Source Rocks ◽  
Upper Permian ◽  
Geochemical Data ◽  
Indirect Measure ◽  
Petroleum Systems ◽  
Eromanga Basin ◽  
Cooper Basin

This paper presents geochemical data—gas chromatography, saturated and aromatic biomarkers, carbon isotopes of bulk fractions and individual n-alkanes—for oils and potential source rocks in the Cooper and Eromanga basins, which show clear evidence for different source-reservoir couplets. The main couplets involve Cooper Basin source and reservoir and Cooper Basin source and Eromanga Basin reservoir. A subordinate couplet involving Eromanga Basin source and Eromanga Basin reservoir is also identified, together with minor inputs from pre-Permian source rocks to reservoirs of the Cooper and Eromanga basins.The source–reservoir relationships are well expressed in the carbon isotopic composition of individual n-alkanes. These data reflect primary controls of source and maturity and are relatively insensitive to secondary alteration through migration fractionation and water washing, processes that have affected the molecular geochemistry of the majority of oils. Accordingly, the principal Gondwanan Petroleum Supersystem originating from a Permian source of the Cooper Basin has been further subdivided into two petroleum systems associated with Lower Permian Patchawarra Formation and Upper Permian Toolachee Formation sources respectively. Both sources are characterised by n-alkane isotope profiles that become progressively lighter with increasing carbon number—negative n-alkane isotope gradient. The Patchawarra source is isotopically lighter than the Toolachee source. Reservoir placement of oil in either the Toolachee or Patchawarra formations is, in general, a good guide to its source and perhaps an indirect measure of seal effectiveness. The subordinate Murta Petroleum Supersystem of the Eromanga Basin is subdivided into the Birkhead Petroleum System and Murta Petroleum System to reflect individual contributions from Birkhead Formation and Murta Formation sources respectively. Both systems are characterised by n-alkane carbon isotope profiles with low to no gradient. The minor Larapintine Petroleum Supersystem has been tentatively identified as involving pre-Permian source rocks in the far eastern YVarburton Basin and western margin of the Warrabin Trough in Queensland.Eromanga source inputs to oil accumulations in the Eromanga Basin can be readily recognised from saturated and aromatic biomarker assemblages. However, biomarkers appear to over-emphasise local Eromanga sources. Hence, we have preferred the semi-quantitative assessment of relative Cooper and Eromanga inputs that can be made using n-alkane isotope data and this appears to be robust provided that Eromanga source input is greater than 25% in oils of mixed origin. Enhanced contributions from Birkhead sources are concentrated in areas of thick and mature Birkhead source rocks in the northeastern Patchawarra Trough. Pre-Permian inputs are readily recognised by n-alkanes more depleted in I3C compared with late Palaeozoic and Mesozoic sources.Long range migration (>50 km) from Permian sources has been established for oil accumulations in the Eromanga Basin. This, together with contributions from local Eromanga sources, highlights petroleum pro- spectivity beyond the Permian edge of the Cooper Basin. Deeper, pre-Permian sources must also be considered in any petroleum system evaluation of the Cooper and Eromanga basins.

scholarly journals Petroleum system analysis of the Mishrif reservoir in the Ratawi, Zubair, North and South Rumaila oil fields, southern Iraq

GeoArabia ◽  
2009 ◽  
Vol 14 (4) ◽  
pp. 91-108 ◽  
Author(s):  
Thamer K. Al-Ameri ◽  
Amer Jassim Al-Khafaji ◽  
John Zumberge
Keyword(s):  
Source Rock ◽  
Lower Cretaceous ◽  
System Analysis ◽  
Isotopic Analysis ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Core Samples ◽  
Biomarker Analysis ◽  
Sulaiy Formation ◽  
Rock Analysis

ABSTRACT Five oil samples reservoired in the Cretaceous Mishrif Formation from the Ratawi, Zubair, Rumaila North and Rumaila South fields have been analysed using Gas Chromatography – Mass Spectroscopy (GC-MS). In addition, fifteen core samples from the Mishrif Formation and 81 core samples from the Lower Cretaceous and Upper Jurassic have been subjected to source rock analysis and palynological and petrographic description. These observations have been integrated with electric wireline log response. The reservoirs of the Mishrif Formation show measured porosities up to 28% and the oils are interpreted as being sourced from: (1) Type II carbonate rocks interbedded with shales and deposited in a reducing marine environment with low salinity based on biomarkers and isotopic analysis; (2) Upper Jurassic to Lower Cretaceous age based on sterane ratios, analysis of isoprenoids and isotopes, and biomarkers, and (3) Thermally mature source rocks, based on the biomarker analysis. The geochemical analysis suggests that the Mishrif oils may have been sourced from the Upper Jurassic Najma or Sargelu formations or the Lower Cretaceous Sulaiy Formation. Visual kerogen assessment and source rock analysis show the Sulaiy Formation to be a good quality source rock with high total organic carbon (up to 8 wt% TOC) and rich in amorphogen. The Lower Cretaceous source rocks were deposited in a suboxic-anoxic basin and show good hydrogen indices. They are buried at depths in excess of 5,000 m and are likely to have charged Mishrif reservoirs during the Miocene. The migration from the source rock is likely to be largely vertical and possibly along faults before reaching the vuggy, highly permeable reservoirs of the Mishrif Formation. Structural traps in the Mishrif Formation reservoir are likely to have formed in the Late Cretaceous.

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.

Simulating the timing of petroleum generation and expulsion from deltaic source rocks: Implications for Late Cretaceous petroleum system in the offshore Jiza-Qamar Basin, Eastern Yemen

2018 ◽  
Vol 170 ◽  
pp. 620-642 ◽  
Author(s):  
Mohammed Hail Hakimi ◽  
Abdulwahab S. Alaug ◽  
Abdulghani F. Ahmed ◽  
Madyan M.A. Yahya ◽  
Mohamed M. El Nady ◽  
...  
Keyword(s):  
Late Cretaceous ◽  
Petroleum System ◽  
Source Rocks ◽  
Petroleum Generation

TECTONOSTRATIGRAPHY AND POTENTIAL SOURCE ROCKS OF THE BASS BASIN

2005 ◽  
Vol 45 (1) ◽  
pp. 601 ◽  
Author(s):  
J.E. Blevin ◽  
K.R. Trigg ◽  
A.D. Partridge ◽  
C.J. Boreham ◽  
S.C. Lang
Keyword(s):  
Seismic Data ◽  
Middle Eocene ◽  
Liquid Hydrocarbon ◽  
Source Rocks ◽  
Rift System ◽  
Complex Nature ◽  
Hydrocarbon Generation ◽  
Crustal Extension ◽  
Principal Source ◽  
Seismic Sequence Stratigraphy

A study of the Bass Basin using a basin-wide integration of seismic data, well logs, biostratigraphy and seismic/sequence stratigraphy has resulted in the identification of six basin phases and related megasequences/ supersequences. These sequences correlate to three periods of extension and three subsidence phases. The complex nature of facies relationships across the basin is attributed to the mostly terrestrial setting of the basin until the Middle Eocene, multiple phases of extension, strong compartmentalisation of the basin due to underlying basement fabric, and differential subsidence during extension and early subsidence phases. The Bass Basin formed through upper crustal extension associated with three main regional events:rifting in the Southern Margin Rift System;rifting associated with the formation of the Tasman Basin; and,prolonged separation, fragmentation and clearance between the Australian and Antarctic plates along the western margin of Tasmania.The final stage of extension was the result of far-field stresses that were likely to be oblique in orientation. The late Early Eocene to Middle Eocene was a time of rifttransition and early subsidence as the effects of intra-plate stresses progressively waned from east to west. Most of the coaly source rocks now typed to liquid hydrocarbon generation were deposited during this rift-transition phase. Biostratigraphic studies have identified three major lacustrine episodes during the Late Cretaceous to Middle Eocene. The lacustrine shales are likely to be more important as seal facies, while coals deposited fringing the lakes are the principal source rocks in the basin.

NEW PETROLEUM MODELS IN THE PEDIRKA BASIN, NORTHERN TERRITORY, AUSTRALIA

2002 ◽  
Vol 42 (1) ◽  
pp. 259 ◽  
Author(s):  
G.J. Ambrose ◽  
K. Liu ◽  
I. Deighton ◽  
P.J. Eadington ◽  
C.J. Boreham
Keyword(s):  
Oil And Gas ◽  
South Australia ◽  
Sedimentary Basins ◽  
Poor Quality ◽  
Northern Territory ◽  
Early Jurassic ◽  
Source Rocks ◽  
Late Triassic ◽  
Hydrocarbon Expulsion ◽  
Migration Pathways

The northern Pedirka Basin in the Northern Territory is sparsely explored compared with its southern counterpart in South Australia. Only seven wells and 2,500 km of seismic data occur over a prospective area of 73,000 km2 which comprises three stacked sedimentary basins of Palaeozoic to Mesozoic age. In this area three petroleum systems have potential related to important source intervals in the Early Jurassic Eromanga Basin (Poolowanna Formation), the Triassic Simpson Basin (Peera Peera Formation) and Early Permian Pedirka Basin (Purni Formation). They are variably developed in three prospective depocentres, the Eringa Trough, the Madigan Trough and the northern Poolowanna Trough. Basin modelling using modern techniques indicate oil and gas expulsion responded to increasing early Late Cretaceous temperatures in part due to sediment loading (Winton Formation). Using a composite kinetic model, oil and gas expulsion from coal rich source rocks were largely coincident at this time, when source rocks entered the wet gas maturation window.The Purni Formation coals provide the richest source rocks and equate to the lower Patchawarra Formation in the Cooper Basin. Widespread well intersections indicate that glacial outwash sandstones at the base of the Purni Formation, herein referred to as the Tirrawarra Sandstone equivalent, have regional extent and are an important exploration target as well as providing a direct correlation with the prolific Patchawarra/Tirrawarra petroleum system found in the Cooper Basin.An integrated investigation into the hydrocarbon charge and migration history of Colson–1 was carried out using CSIRO Petroleum’s OMI (Oil Migration Intervals), QGF (Quantitative Grain Fluorescence) and GOI (Grains with Oil Inclusions) technologies. In the Early Jurassic Poolowanna Formation between 1984 and 2054 mRT, elevated QGF intensities, evidence of oil inclusions and abundant fluorescing material trapped in quartz grains and low displacement pressure measurements collectively indicate the presence of palaeo-oil and gas accumulation over this 70 m interval. This is consistent with the current oil show indications such as staining, cut fluorescence, mud gas and surface solvent extraction within this reservoir interval. Multiple hydrocarbon migration pathways are also indicated in sandstones of the lower Algebuckina Sandstone, basal Poolowanna Formation and Tirrawarra Sandstone equivalent. This is a significant upgrade in hydrocarbon prospectivity, given previous perceptions of relatively poor quality and largely immature source rocks in the Basin.Conventional structural targets are numerous, but the timing of hydrocarbon expulsion dictates that those with an older drape and compaction component will be more prospective than those dominated by Tertiary reactivation which may have resulted in remigration or leakage. Preference should also apply to those structures adjacent to generative source kitchens on relatively short migration pathways. Early formed stratigraphic traps at the level of the Tirrawarra Sandstone equivalent and Poolowanna Formation are also attractive targets. Cyclic sedimentation in the Poolowanna Formation results in two upward fining cycles which compartmentalise the sequence into two reservoir–seal configurations. Basal fluvial sandstone reservoirs grade upwards into topset shale/coal lithologies which form effective semi-regional seals. Onlap of the basal cycle onto the Late Triassic unconformity offers opportunities for stratigraphic entrapment.

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