Hydrocarbon Generation in Gippsland Basin, Australia--Comparison with Cooper Basin, Australia

Although it was for many years believed that coals could not act as source rocks for commercial oil accumulations, it is today generally accepted that coals can indeed generate and expel commercial quantities of oil. While hydrocarbon generation from coals is less well understood than for marine and lacustrine source rocks, liquid hydrocarbon generation from coals and coaly source rocks is now known from many parts of the world, especially in the Australasian region (MacGregor 1994; Todd et al. 1997). Most of the known large oil accumulations derived from coaly source rocks have been generated from Cenozoic coals, such as in the Gippsland Basin (Australia), the Taranaki Basin (New Zealand), and the Kutei Basin (Indonesia). Permian and Jurassic coal-sourced oils are known from, respectively, the Cooper Basin (Australia) and the Danish North Sea, but in general only minor quantities of oil appear to be related to coals of Permian and Jurassic age. In contrast, Carboniferous coals are only associated with gas, as demonstrated for example by the large gas deposits in the southern North Sea and The Netherlands. Overall, the oil generation capacity of coals seems to increase from the Carboniferous to the Cenozoic. This suggests a relationship to the evolution of more complex higher land plants through time, such that the highly diversified Cenozoic plant communities in particular have the potential to produce oil-prone coals. In addition to this overall vegetational factor, the depositional conditions of the precursor mires influenced the generation potential. The various aspects of oil generation from coals have been the focus of research at the Geological Survey of Denmark and Greenland (GEUS) for several years, and recently a worldwide database consisting of more than 500 coals has been the subject of a detailed study that aims to describe the oil window and the generation potential of coals as a function of coal composition and age.

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Petroleum potential and kinetic models for hydrocarbon generation from the Upper Cretaceous to Paleogene Latrobe Group coals and shales in the Gippsland Basin, Australia

Organic Geochemistry ◽

10.1016/j.orggeochem.2015.11.001 ◽

2016 ◽

Vol 91 ◽

pp. 54-67 ◽

Cited By ~ 24

Author(s):

Soumaya Abbassi ◽

Dianne S. Edwards ◽

Simon C. George ◽

Herbert Volk ◽

Nicolaj Mahlstedt ◽

...

Keyword(s):

Kinetic Models ◽

Upper Cretaceous ◽

Hydrocarbon Generation ◽

Petroleum Potential ◽

Gippsland Basin

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Unconventional hydrocarbons in shales: source rock or waste zones?

The APPEA Journal ◽

10.1071/aj14109 ◽

2015 ◽

Vol 55 (2) ◽

pp. 474

Author(s):

Nachiketa Mishra ◽

John Kaldi ◽

Ulrike Schacht

Keyword(s):

Organic Compounds ◽

Hydrocarbon Generation ◽

Bakken Formation ◽

Unconventional Resources ◽

Hydrocarbon Content ◽

Basin Scale ◽

Unconventional Hydrocarbons ◽

Mercury Injection Capillary Pressure ◽

Continuous Source ◽

Cooper Basin

This extended abstract summarises the objectives of a research project that will provide insight into hydrocarbon generation and accumulation in continuous-source reservoirs and how to best exploit such unconventional resources in Australia, specifically in the Cooper Basin. It compares and contrasts a productive shale from the US—the Bakken Formation—with shales from the Cooper Basin. Unconventional resources, such as the Devonian-Mississippian Bakken Formation, have been assumed to be continuous source-reservoirs where the oil is generated from organic-rich shales with minimal migration. It is possible, however, that the shale intervals are a waste zone (a leaked seal). These waste zones form when the buoyancy pressure of the hydrocarbon exceeds the capillary forces in the seal, resulting in tertiary migration. Oil saturation values strongly correlate with the hydrocarbon content parameter (S1/TOC) from Rock-Eval. Values of 120 mgHC/gC are typically indicative of non-indigenous or migrated hydrocarbons (reservoirs or leaked seals). Mercury injection capillary pressure (MICP) analysis of core samples can also diagnose whether a shale is a source or a seal. Organic shales with high capillary entry pressures generally have low hydrocarbon content, in line with in-situ generation; shales with low entry pressures have comparatively higher hydrocarbon content and indicate migration from an underlying accumulation. Once these waste zones are identified on a basin-scale, specific samples from the Bakken Formation will be analysed using micro-scale sealed vessel pyrolysis, combined with monitoring of the biomarkers and other organic compounds using mass spectrometry. As the composition of organic compounds is altered during migration, this will confirm whether they are generated locally or migrated.

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Unconventional gas prospectivity of the Cooper Basin

The APPEA Journal ◽

10.1071/aj14063 ◽

2015 ◽

Vol 55 (2) ◽

pp. 428 ◽

Cited By ~ 1

Author(s):

Lisa Hall ◽

Tony Hill ◽

Liuqi Wang ◽

Dianne Edwards ◽

Tehani Kuske ◽

...

Keyword(s):

Source Rocks ◽

System Modelling ◽

Hydrocarbon Generation ◽

Tight Gas ◽

Unconventional Gas ◽

Upper Carboniferous ◽

Gas Market ◽

Intracratonic Basin ◽

Exploration Activity ◽

Cooper Basin

The Cooper Basin is an Upper Carboniferous–Middle Triassic intracratonic basin in northeast SA and southwest Queensland. The basin is Australia's premier onshore hydrocarbon-producing province and is nationally significant due to its provision of domestic gas for the east coast gas market. Exploration activity in the region has recently expanded with numerous explorers pursuing newly identified unconventional hydrocarbon plays. While conventional gas and oil prospects can usually be identified by 3D seismic, the definition and extent of the undiscovered unconventional gas resources in the basin remain poorly understood. This extended abstract reviews the hydrocarbon prospectivity of the Cooper Basin with a focus on unconventional gas resources. Regional basin architecture, characterised through source rock distribution and quality, demonstrates the abundance of viable source rocks across the basin. Petroleum system modelling, incorporating new compositional kinetics, source quality and total organic carbon (TOC) map, highlight the variability in burial, thermal and hydrocarbon generation histories between depocentres. The study documents the extent of a number of unconventional gas play types, including the extensive basin-centred and tight gas accumulations in the Gidgealpa Group, deep-dry coal gas associated with the Patchawarra and Toolachee formations, as well as the less extensive shale gas plays in the Murteree and Roseneath shales.

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Constraining the distribution and relationship between overpressure, natural fracture density and temperature in the Cooper Basin, Australia

The APPEA Journal ◽

10.1071/aj15002 ◽

2016 ◽

Vol 56 (1) ◽

pp. 11 ◽

Cited By ~ 7

Author(s):

David Kulikowski ◽

Dennis Cooke ◽

Khalid Amrouch

Keyword(s):

Uranium Content ◽

Natural Fracture ◽

Hydrocarbon Generation ◽

Fracture Density ◽

Fracture Detection ◽

Field Scale ◽

Seismic Attribute ◽

Fracture Development ◽

Generation Mechanisms ◽

Cooper Basin

To effectively and safely extract hydrocarbon from low permeability and overpressured reservoirs in the Cooper Basin, a thorough understanding of the regional and field scale distribution of overpressure, temperature and fracture density is essential. Previous research omitted the effect of fluid expansion and hydrocarbon generation mechanisms for overpressure generation in the basin, albeit reservoir temperatures have sharply increased in the past five million years. The authors collate pressure (>8,000 samples) and temperature (>6,000 samples) data from 1,095 wells across the SA portion of the Cooper Basin and incorporate natural fracture densities from 28 interpreted borehole image logs to investigate the spatial variation, and potential relationship, between pressure, temperature and natural fracture density. Results show significantly lower geothermal gradients within the Patchawarra Trough, likely attributed to a lack of shallow volcanics, blanketing coals or low uranium content. Shallow volcanics are common in high-temperature areas such as the Moomba/Big Lake and Gidgealpa fields and deeper portions of the Nappamerri Trough, with overpressured wells (>0.45 psi/ft) appearing to cluster in these areas, particularly south of the Gidgealpa-Merrimelia-Innamincka Ridge. Fracture density shows no obvious relationship to pressure, inferring a dominant structural origin for natural fracture development. Although the authors cannot exclusively attribute fluid expansion and hydrocarbon expansion mechanisms to overpressure, they likely have a profound effect. Future work should investigate the feasibility of integrating pressure, vertical stress and sonic velocity to constrain the overpressure generation mechanism within the basin while incorporating field scale seismic attribute analysis for natural fracture detection and overpressure analysis.

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HYDROCARBON PROSPECTIVITY OF THE TORQUAY SUB-BASIN, OFFSHORE VICTORIA

The APPEA Journal ◽

10.1071/aj93039 ◽

1994 ◽

Vol 34 (1) ◽

pp. 479 ◽

Cited By ~ 4

Author(s):

Mark A. Trupp ◽

Keith W. Spence ◽

Michael J. Gidding

Keyword(s):

Lower Cretaceous ◽

Hydrocarbon Exploration ◽

Source Rocks ◽

Structural Deformation ◽

Hydrocarbon Generation ◽

Fault Block ◽

Complex Fault ◽

Wild Dog ◽

Reservoir Potential ◽

Gippsland Basin

The Torquay Sub-basin lies to the south of Port Phillip Bay in Victoria. It has two main tectonic elements; a Basin Deep area which is flanked to the southeast by the shallower Snail Terrace. It is bounded by the Otway Ranges to the northwest and shallow basement elsewhere. The stratigraphy of the area reflects the influence of two overlapping basins. The Lower Cretaceous section is equivalent to the Otway Group of the Otway Basin, whilst the Upper Cretaceous and Tertiary section is comparable with the Bass Basin stratigraphy.The Torquay Sub-basin apparently has all of the essential ingredients needed for successful hydrocarbon exploration. It has good reservoir-seal pairs, moderate structural deformation and probable source rocks in a deep kitchen. Four play types are recognised:Large Miocene age anticlines, similar to those in the Gippsland Basin, with an Eocene sandstone reservoir objective;The same reservoir in localised Oligocene anticlines associated with fault inversion;Possible Lower Cretaceous Eumeralla Formation sandstones in tilted fault blocks and faulted anticlines; andLower Cretaceous Crayfish Sub-group sandstones also in tilted fault block traps.Maturity modelling suggests that the Miocene anticlines post-date hydrocarbon generation. Poor reservoir potential and complex fault trap geometries downgrade the two Lower Cretaceous plays.The Oligocene play was tested by Wild Dog-1 which penetrated excellent Eocene age reservoir sands beneath a plastic shale seal, however, the well failed to encounter any hydrocarbons. Post-mortem analysis indicates the well tested a valid trap. The failure of the well is attributed to a lack of charge. Remaining exploration potential is limited to the deeper plays which have much greater risks associated with each play element.

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SOURCE, MATURITY AND GAS COMPOSITION RELATIONSHIPS IN THE SOUTHERN COOPER BASIN

The APPEA Journal ◽

10.1071/aj79016 ◽

1980 ◽

Vol 20 (1) ◽

pp. 191

Author(s):

D.A. Schwebel ◽

S.B. Devine ◽

M. Riley

Keyword(s):

Vitrinite Reflectance ◽

Sedimentary Basins ◽

Geothermal Gradient ◽

Temperature Gradients ◽

Land Plants ◽

Hydrocarbon Generation ◽

Gas Composition ◽

Wet Gas ◽

Structural Zones ◽

Cooper Basin

In the Permian sedimentary sequence of the Cooper Basin, land plants contributed the bulk of the organic matter to the sediments. Inertinite, vitrinite and exinite are common kerogen types present in the organic-rich shales. Coal thickness varies areally.The geothermal gradient, though varying (from area to area), is everywhere higher than normal for sedimentary basins. The whole of the Permian sequence is mature for hydrocarbon generation. The highest temperature gradients of up to 3.19°F/100’ are measured in the Nappamerrie Trough and are associated with areas of granitic basement. Vitrinite reflectance profiles confirm that the sediments are thermally mature.Trends of gas composition indicate three distinct regions with gases trapped in:the Patchawarra Trough tend to be high in CO2 and wet gas;the Nappamerri Trough tend to be high in CO2 and low in wet gas; andthe Tennapera Trough tend to be low in CO2 and moderately high in wet gas.These differences in gas composition are accounted for by differences in thermal history within structural zones.

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PATTERNS OF DIAGENESIS IN SOME AUSTRALIAN SEDIMENTARY BASINS

The APPEA Journal ◽

10.1071/aj76006 ◽

1977 ◽

Vol 17 (1) ◽

pp. 58 ◽

Cited By ~ 1

Author(s):

M. Shibaoka ◽

A. J. R. Bennett

Keyword(s):

Sedimentary Basins ◽

Hydrocarbon Generation ◽

Liquid Hydrocarbons ◽

Geological Time ◽

Oil Generation ◽

History Of ◽

And Migration ◽

Gippsland Basin ◽

Reflectance Data ◽

Generation Activity

Three characteristic types of Australian sedimentary basins can be recognized on the basis of depth-reflectance curves. These may be designated as the Cooper, Sydney, and Gippsland Basin types. Characteristic depth-reflectance curves allow an assessment of the depositional and tectonic histories of sedimentary basins to be made. If the geological history and especially the stratigraphy of a basin is well known, it is possible to estimate the maturity which coal or kerogen would have attained at any past or present time. This maturity would be expressed by particular reflectance values of vitrinite. By making actual measurements of vitrinite and kerogen reflectance, the model of maturation can be tested. In this way it has been possible, for a number of basins, to estimate the geological period in which liquid hydrocarbons were generated and the rate at which the maturation process proceeded. The formation of an accumulation of oil is a matter of balance between the supply and loss of oil to and from traps, as well as persistence of traps and migration paths through geological time. The lapse of time after oil generation and the rate of generation are thus most important. The above-mentioned three types of sedimentary basins differ in these respects. Reflectance data can therefore be used not only to estimate the present state of organic maturity, but also in conjunction with the history of sedimentation in the basin, to interpret hydrocarbon generation activity in geological time.

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HYDROCARBON PROSPECTIVITY OF THE DEEPWATER GIPPSLAND BASIN, VICTORIA, AUSTRALIA

The APPEA Journal ◽

10.1071/aj00005 ◽

2001 ◽

Vol 41 (1) ◽

pp. 91 ◽

Cited By ~ 5

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.

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HYDROCARBON GENERATION IN THE FLY LAKE—BROLGA AREA OF THE COOPER BASIN

The APPEA Journal ◽

10.1071/aj78012 ◽

1979 ◽

Vol 19 (1) ◽

pp. 108

Author(s):

Michelle Smyth

Keyword(s):

Organic Matter ◽

Sedimentary Basins ◽

Depositional Environments ◽

Fluorescent Light ◽

Hydrocarbon Generation ◽

Coal Seams ◽

Clastic Sediments ◽

Permian Coal ◽

Coal Measures ◽

Cooper Basin

The Cooper Basin is a major gas producing basin in Australia. Organic material in sediments from its Permian coal measures has been studied using transmitted, reflected and fluorescent light microscope techniques of analysis. In the Fly Lake—Brolga area, of the Patchawarra Trough, Cooper Basin, the interseam sediments of the Patchawarra Formation contain three types of kerogen or dispersed organic matter (d.o.m.): exinitic, vitrinitic and inertinitic. Exinitic d.o.m. is most abundant near the top of the Formation, vitrinitic d.o.m. is more abundant in the middle and lower parts of it, and inertinitic d.o.m. occurs throughout.A correlation between the type of d.o.m. in the sediments and the petrography of associated coals is emerging. Exinitic d.o.m. appears to be associated with coals that have high vitrite-plus-clarite contents, whereas vitrinitic d.o.m. is associated with high "intermediates" coals. Further examples are needed to establish these relationships more firmly.On the basis of results of coal petrographic studies in other Australian Permian sedimentary basins, depositional environments have been proposed for the coal seams in the Fly Lake—Brolga area. These environments are compared with those proposed by Thornton (1978) using the clastic sediments of the Patchawarra Formation.

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