HYDROCARBON PROSPECTIVITY OF THE DEEPWATER GIPPSLAND BASIN, VICTORIA, AUSTRALIA

2001 ◽  
Vol 41 (1) ◽  
pp. 91 ◽  
Author(s):  
T. Bernecker ◽  
M.A. Woollands ◽  
D. Wong ◽  
D.H. Moore ◽  
M.A. Smith
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Data Sets ◽  
Hydrocarbon Generation ◽  
The North ◽  
Potential Source Rock ◽  
Exploration And Production ◽  
Modelling Studies ◽  
History Of ◽  
Gippsland Basin

After 35 years of successful exploration and development, the Gippsland Basin is perceived as a mature basin. Several world class fields have produced 3.6 billion (109) BBL (569 GL) oil and 5.2 TCF (148 Gm3) gas. Without additional discoveries, it is predicted that further significant decline in production will occur in the next decade.However, the Gippsland Basin is still relatively underexplored when compared to other prolific hydrocarbon provinces. Large areas are undrilled, particularly in the eastern deepwater part of the basin. Here, an interpretation of new regional aeromagnetic and deep-water seismic data sets, acquired through State and Federal government initiatives, together with stratigraphic, sedimentological and source rock maturation modelling studies have been used to delineate potential petroleum systems.In the currently gazetted deepwater blocks, eight structural trapping trends are present, each with a range of play types and considerable potential for both oil and gas. These include major channel incision plays, uplifted anticlinal and collapsed structures that contain sequences of marine sandstones and shales (deepwater analogues of the Marlin and Turrum fields), as well as large marine shale-draped basement horsts.The study has delineated an extensive near-shore marine, lower coastal plain and deltaic facies association in the Golden Beach Subgroup. These Late Cretaceous strata are comparable to similar facies of the Tertiary Latrobe Siliciclastics and extend potential source rock distribution beyond that of previous assessments. In the western portion of the blocks, overburden is thick enough to drive hydrocarbon generation and expulsion. The strata above large areas of the source kitchen generally dip to the north and west, promoting migration further into the gazetted areas.Much of the basin’s deepwater area, thus, shares the deeper stratigraphy and favourable subsidence history of the shallow water producing areas. Future exploration and production efforts will, however, be challenged by the 200–2500 m water-depths and local steep bathymetric gradients, which affect prospect depth conversion and the feasibility of development projects in the case of successful exploration.

scholarly journals Evaluation of hydrocarbons generated from the Permo-Carboniferous source rocks in Huanghua Depression of the Bohai Bay Basin, China

2018 ◽  
Vol 36 (5) ◽  
pp. 1229-1244
Author(s):  
Xiao-Rong Qu ◽  
Yan-Ming Zhu ◽  
Wu Li ◽  
Xin Tang ◽  
Han Zhang
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Bohai Bay Basin ◽  
Important Conclusion ◽  
The North ◽  
Huanghua Depression ◽  
History Of

The Huanghua Depression is located in the north-centre of Bohai Bay Basin, which is a rift basin developed in the Mesozoic over the basement of the Huabei Platform, China. Permo-Carboniferous source rocks were formed in the Huanghua Depression, which has experienced multiple complicated tectonic alterations with inhomogeneous uplift, deformation, buried depth and magma effect. As a result, the hydrocarbon generation evolution of Permo-Carboniferous source rocks was characterized by discontinuity and grading. On the basis of a detailed study on tectonic-burial history, the paper worked on the burial history, heating history and hydrocarbon generation history of Permo-Carboniferous source rocks in the Huanghua Depression combined with apatite fission track testing and fluid inclusion analyses using the EASY% Ro numerical simulation. The results revealed that their maturity evolved in stages with multiple hydrocarbon generations. In this paper, we clarified the tectonic episode, the strength of hydrocarbon generation and the time–spatial distribution of hydrocarbon regeneration. Finally, an important conclusion was made that the hydrocarbon regeneration of Permo-Carboniferous source rocks occurred in the Late Cenozoic and the subordinate depressions were brought forward as advantage zones for the depth exploration of Permo-Carboniferous oil and gas in the middle-northern part of the Huanghua Depression, Bohai Bay Basin, China.

Unconventional Shale Play in Oman: Preliminary Assessment of the Shale Oil / Shale Gas Potential of the Silurian Hot Shale of the Southern Rub al-Khali Basin

2015 ◽  
Author(s):  
Jamal A. Madi ◽  
Elhadi M. Belhadj
Keyword(s):  
Source Rock ◽  
Shale Gas ◽  
Oil And Gas ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Generation ◽  
Shale Oil ◽  
Lower Silurian ◽  
History Of ◽  
Oil Gas

Abstract Oman's petroleum systems are related to four known source rocks: the Precambrian-Lower Cambrian Huqf, the Lower Silurian Sahmah, the Late Jurassic Shuaiba-Tuwaiq and the Cretaceous Natih. The Huqf and the Natih have sourced almost all the discovered fields in the country. This study examines the shale-gas and shale-oil potential of the Lower Silurian Sahmah in the Omani side of the Rub al Khali basin along the Saudi border. The prospective area exceeds 12,000 square miles (31,300 km2). The Silurian hot shale at the base of the Sahmah shale is equivalent to the known world-class source rock, widespread throughout North Africa (Tannezouft) and the Arabian Peninsula (Sahmah/Qusaiba). Both thickness and thermal maturities increase northward toward Saudi Arabia, with an apparent depocentre extending southward into Oman Block 36 where the hot shale is up to 55 m thick and reached 1.4% vitrinite reflectance (in Burkanah-1 and ATA-1 wells). The present-day measured TOC and estimated from log signatures range from 0.8 to 9%. 1D thermal modeling and burial history of the Sahmah source rock in some wells indicate that, depending on the used kinetics, hydrocarbon generation/expulsion began from the Early Jurassic (ca 160 M.a.b.p) to Cretaceous. Shale oil/gas resource density estimates, particularly in countries and plays outside North America remain highly uncertain, due to the lack of geochemical data, the lack of history of shale oil/gas production, and the valuation method undertaken. Based on available geological and geochemical data, we applied both Jarvie (2007) and Talukdar (2010) methods for the resource estimation of: (1) the amount of hydrocarbon generated and expelled into conventional reservoirs and (2) the amount of hydrocarbon retained within the Silurian hot shale. Preliminary results show that the hydrocarbon potential is distributed equally between wet natural gas and oil within an area of 11,000 square mile. The Silurian Sahmah shale has generated and expelled (and/or partly lost) about 116.8 billion of oil and 275.6 TCF of gas. Likewise, our estimates indicate that 56 billion of oil and 273.4 TCF of gas are potentially retained within the Sahmah source rock, making this interval a future unconventional resource play. The average calculated retained oil and gas yields are estimated to be 6 MMbbl/mi2 (or 117 bbl oil/ac-ft) and 25.3 bcf/mi2 (or 403 mcf gas/ac-ft) respectively. To better compare our estimates with Advanced Resources International (EIA/ARI) studies on several Silurian shale plays, we also carried out estimates based on the volumetric method. The total oil in-place is 50.2 billion barrels, while the total gas in-place is 107.6 TCF. The average oil and gas yield is respectively 7 MMbbl/mi2 and 15.5 bcf/mi2. Our findings, in term of oil and gas concentration, are in line or often smaller than all the shale oil/gas plays assessed by EIA/ARI and others.

scholarly journals Source rock characteristics and hydrocarbon generation potential in Brunei-Muara district, Brunei Darussalam: a comparative case study from selected Miocene-Quaternary formations

2021 ◽  
Vol 11 (4) ◽  
pp. 1679-1703
Author(s):  
Liyana Nadiah Osli ◽  
Mohamed Ragab Shalaby ◽  
Md. Aminul Islam
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Vegetation Index ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Rock Properties ◽  
Comparative Case Study ◽  
Hydrocarbon Generation ◽  
Brunei Darussalam ◽  
Potential Source Rock

AbstractA comparative analysis on source rock properties has been carried out on the Miocene-Pliocene formations as well as the Quaternary terrace deposits using Rock–Eval pyrolysis results and organic petrography as well as some biomarkers results. Samples were obtained from outcrops of the Quaternary terrace deposits, Pliocene-aged Liang Formation together with the Miocene Miri and Setap Shale formations in Brunei-Muara district, with sample lithologies ranging from coal, coaly shale, shale and lignitic sand. High total organic carbon (TOC) and S2 values ranging from 41.8 to 62.4% and 7.40 mg HC/g rock to 122 mg HC/g rock, respectively, are identified in coals of the terrace deposit, Liang and Miri formations, making these as the best potential source rock due to the “good to excellent” generating potential. Meanwhile, a “fair to poor” potential is exhibited for the coaly shale, shale and lignitic sand samples as a result of their low TOC, HI and S2 values. The organic matter is composed of kerogen type III (gas prone) and type II-III (mixed oil and gas prone). Organic matter in all studied formations originate from a terrestrial-source, as proven by the abundance of huminite. Organic petrographical and biomarkers studies suggest that the coals and lignitic sand samples were deposited in a mangrove-type mire in a lower delta setting, under oxic and limnic to limnotelmatic conditions, except sample DD2-1, which is deposited in a less water-saturated environment. The samples display the presence of bi-modal and normal distribution of n-alkanes. For all of the samples, the dominating plant types in the palaeomire are of soft, herbaceous plants and this is supported by the low vegetation index and moderate Paq values. All the studied samples are thermally immature to early mature, as exhibited by the Tmax values that range from 300 to 437 °C and vitrinite reflectance readings of 0.22% to 0.46%.

scholarly journals About this title - United Kingdom Oil and Gas Fields: 50th Anniversary Commemorative Volume

10.1144/m52 ◽  
2020 ◽  
Vol 52 (1) ◽  
pp. NP.1-NP
Keyword(s):  
Oil And Gas ◽  
50Th Anniversary ◽  
Reference Source ◽  
Geological Society ◽  
Oil And Gas Fields ◽  
Production History ◽  
Exploration And Production ◽  
History Of ◽  
The Uk ◽  
Gas Fields

Geological Society Memoir 52 records the extraordinary journey of more than 50 years that has led to the development of some 458 oil and gas fields on the UK Continental Shelf (UKCS). It contains papers on almost 150 onshore and offshore fields in all of the UK's main petroliferous basins. These papers range from look-backs on some of the first-developed gas fields in the Southern North Sea, to papers on fields that have only just been brought into production or may still remain undeveloped, and includes two candidate CO2 sequestration projects.These papers are intended to provide a consistent summary of the exploration, appraisal, development and production history of each field, leading to the current subsurface understanding which is described in greater detail. As such, the Memoir will be an enduring reference source for those exploring for, developing, producing hydrocarbons and sequestering CO2 on the UKCS in the coming decades. It encapsulates the petroleum industry's deep subsurface knowledge accrued over more than 50 years of exploration and production.

scholarly journals GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Linear Regression Analysis ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Type Iii ◽  
Limit Value ◽  
The Impact

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

scholarly journals Static Geological Modelling with Knowledge Driven Methodology

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3802
Author(s):  
Jun Li ◽  
Xiaoying Zhang ◽  
Bin Lu ◽  
Raheel Ahmed ◽  
Qian Zhang
Keyword(s):  
Case Studies ◽  
Oil And Gas ◽  
Fracture Network ◽  
Depositional Environments ◽  
Soft Data ◽  
Oil And Gas Exploration ◽  
Hard Data ◽  
The North ◽  
Geological Modelling ◽  
Exploration And Production

Geological modelling is an important topic of oil and gas exploration and production. A new knowledge driven methodology of geological modelling is proposed to address the problem of “hard data” limitation and modelling efficiency of the conventional data driven methodology. Accordingly, a new geological modelling software (DMatlas) (V1.0, Dimue, Wuhan, China) has been developed adopting a grid-free, object-based methodology. Conceptual facies models can be created for various depositional environments (such as fluvial, delta and carbonates). The models can be built largely based on geologists’ understandings with “soft data” such as outcrops analysis and geological maps from public literatures. Basic structures (fault, folds, and discrete fracture network) can be easily constructed according to their main features. In this methodology, models can be shared and re-used by other modelers or projects. Large number of model templates help to improve the modelling work efficiency. To demonstrate the tool, two case studies of geological modelling with knowledge driven methodology are introduced: (1) Suizhong 36-1 field which is a delta depositional environment in Bohai basin, China; (2) a site of the north Oman fracture system. The case studies show the efficiency and reliability within the new methodology.

ACCURATE RECOGNITION OF SOURCE ROCK CHARACTER IN THE JURASSIC OF THE NORTH WEST SHELF, WESTERN AUSTRALIA

1992 ◽  
Vol 32 (1) ◽  
pp. 289 ◽  
Author(s):  
John Scott
Keyword(s):  
Source Rock ◽  
Organic Material ◽  
Source Rocks ◽  
Higher Plant ◽  
Pyrolysis Gas ◽  
Screening Analysis ◽  
North West ◽  
The North ◽  
Potential Source Rock ◽  
Rock Eval

The main potential source rock intervals are generally well defined on the North West Shelf by screening analysis such as Rock-Eval. The type of product from the source rocks is not well defined, owing to inadequacies in current screening analysis techniques. The implications of poor definition of source type in acreage assessment are obvious. The type of product is dependent on the level of organic maturity of the source rock, the ability of products to migrate out of the source rock and on the type of organic material present. The type of kerogen present is frequently determined by Rock-Eval pyrolysis. However, Rock-Eval has severe limitations in defining product type when there is a significant input of terrestrial organic material. This problem has been recognised in Australian terrestrial/continental sequences but also occurs where marine source rock facies contain terrestrially-derived higher plant material. Pyrolysis-gas chromatography as applied to source rock analysis provides, by molecular typing, a better method of estimating the type of products of the kerogen breakdown than bulk chemical analysis such as Rock-Eval pyrolysis.

PESA Australian exploration review 2018

2019 ◽  
Vol 59 (2) ◽  
pp. 493
Author(s):  
D. Lockhart ◽  
D. Spring
Keyword(s):  
Oil And Gas ◽  
Petroleum Exploration ◽  
3D Seismic ◽  
The North ◽  
Second Year ◽  
Gippsland Basin ◽  
2D And 3D ◽  
Conventional Oil ◽  
Exploration Activity ◽  
Offshore Petroleum

Available data for 2018 indicates that exploration activity is on the rise in Australia, compared to 2017, and this represents a second year of growth in exploration activity in Australia. There has been an increase in area under licence by 92 000 km2, reversing the downward trend in area under licence that commenced in 2014. Since 2016, exploratory drilling within Australia has seen a continued upward trend in both the number of wells drilled and the percentage of total worldwide. Onshore, 77 conventional exploration and appraisal wells were spudded during the year. Offshore, exploration and appraisal drilling matched that seen in 2017, with five new wells spudded: two in the Roebuck Basin, two in the Gippsland Basin and one in the North Carnarvon Basin. Almost 1500 km of 2D seismic and over 10 000 km2 of 3D seismic were acquired within Australia during 2018, accounting for 2.4% and 3.9% of global acquisition, respectively. This represents an increase in the amount of both 2D and 3D seismic acquired in Australia compared with 2017. Once the 2017 Offshore Petroleum Acreage Release was finalised, seven new offshore exploration permits were awarded as a result. A total of 12 bids were received for round one of the 2018 Offshore Petroleum Exploration Release, demonstrating an increase in momentum for offshore exploration in Australia. The permits are in Commonwealth waters off Western Australia, Victoria and the Ashmore and Cartier islands. In June 2018, the Queensland Government announced the release of 11 areas for petroleum exploration acreage in onshore Queensland, with tenders closing in February/March 2019; a further 11 areas will be released in early 2019. The acreage is a mix of coal seam gas and conventional oil and gas. Victoria released five areas in the offshore Otway Basin within State waters. In the Northern Territory, the moratorium on fracking was lifted in April, clearing the way for exploration to recommence in the 2019 dry season. With the increase in exploration has come an increase in success, with total reserves discovered within Australia during 2018 at just under 400 million barrels of oil equivalent, representing a significant increase from 2017. In 2018, onshore drilling resulted in 18 new discoveries, while offshore, two new discoveries were made. The most notable exploration success of 2018 was Dorado-1 drilled in March by Quadrant and Carnarvon Petroleum in the underexplored Bedout Sub-basin. Dorado is the largest oil discovery in Australia of 100 million barrels, or over, since 1996 and has the potential to reinvigorate exploration in the region.

The history and future of North Sea oil and gas: an environmental perspective

1987 ◽  
Vol 316 (1181) ◽  
pp. 487-493 ◽  
Keyword(s):  
North Sea ◽  
Management Practices ◽  
Oil And Gas ◽  
Petroleum Industry ◽  
The North ◽  
History Of ◽  
Assessment Techniques ◽  
Northern North Sea ◽  
Construction Operation ◽  
Biological Environment

The history of the development of the hydrocarbon resources of the North Sea is reviewed in an environmental context. The development of impact assessment techniques and practices and the evolution of monitoring of the physical, chemical and biological environment offshore and onshore, with reference to platforms, subsea pipelines, pipeline landfalls and terminal construction and operation is discussed. A brief account of the development of environmental protection management practices and their application to the design, construction, operation and management of major production projects follows. The paper concludes with a look at the environmental conditions likely to be established as the industry moves into the northern North Sea and areas such as the West Shetland Basin, and their significance for the petroleum industry.

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