Understanding the plumbing of the Gippsland Basin: new results on fluid migration and reservoir quality

2011 ◽  
Vol 51 (2) ◽  
pp. 693
Author(s):  
Peter Tingate ◽  
Monica Campi ◽  
Geoffrey O'Brien ◽  
John Miranda ◽  
Louise Goldie Divko ◽  
...  
Keyword(s):  
Co2 Storage ◽  
Fluid Migration ◽  
Gas Field ◽  
Reservoir Characteristics ◽  
Petroleum Systems ◽  
Migration History ◽  
History Of ◽  
Hydrocarbon Charge ◽  
Gippsland Basin ◽  
Migration Pathways

Understanding the CO2 storage potential and petroleum prospectivity of the Gippsland Basin are critical to managing the resources of this region. Key controls on determining the prospectivity for CO2 storage and petroleum include understanding the fluid migration history and reservoir characteristics in the basin. Gippsland Basin hydrology, reservoir characteristics and petroleum systems are being studied to better understand how CO2 can be safely stored in the subsurface. Hydrocarbon migration pathways have been delineated using petroleum systems modelling. The latest hydrocarbon charge history data has been acquired to test the containment potential of individual structures along these migration pathways. The charge history results indicate the Golden Beach gas field has had a complex hydrocarbon fill history, and that early charge has migrated through the regional seal. The results also indicate that early oil charge was very common in the basin, including large structures that are now filled with gas (e.g. Barracouta). The results allow the regions with good CO2 containment potential to be delineated for further storage investigations. A new evaluation of the reservoir characteristics of the Latrobe Group—through porosity/permeability analysis and automated mineral analysis (AMA)—has provided insights into CO2 injectivity and capacity. The AMA results constrain the mineralogy and diagenetic history of the reservoirs and seals. In addition, the data highlights the presence of carbonates, glauconite and K-feldspar that are potentially reactive with injected CO2.

APPROACHES TO PALAEOGEOGRAPHIC RECONSTRUCTIONS OF THE LATROBE GROUP, GIPPSLAND BASIN, SOUTHEASTERN AUSTRALIA

2005 ◽  
Vol 45 (1) ◽  
pp. 581 ◽  
Author(s):  
T. Bernecker ◽  
A.D. Partridge
Keyword(s):  
Co2 Storage ◽  
Depositional Environments ◽  
Petroleum Systems ◽  
Fine Grained ◽  
Southeastern Australia ◽  
Depositional System ◽  
Facies Associations ◽  
Marine Fossils ◽  
Coal Accumulation ◽  
Gippsland Basin

In the Gippsland Basin, the seaward extent of paralic coal occurrences can be mapped in successive time slices through the Paleocene and Eocene to provide a series of straight to gently arcuate surrogate palaeoshorelines within the petroliferous Latrobe Group. Palaeogeographic reconstructions that incorporate this information provide a unique perspective on the changes affecting a siliciclastic depositional system on a passive continental margin where basin development has been primarily controlled by thermal sag. In contrast, the absence of calcareous marine fossils and lack of extensive, widespread and thick fine-grained sediments on the marine shelf and continental slope, beyond the seaward limits of coal accumulation, have contributed to the false impression that the Latrobe Group accumulated in a largely non-marine basin. Based on the proposed model for palaeoshoreline delineation, seismic data, sequence analysis, petrography and palynology can be integrated to subdivide the main depositional environments into distinct facies associations that can be used to predict the distribution of petroleum systems elements in the basin. The application of such palaeogeographic models to the older section of the Latrobe Group can improve the identification of these petroleum systems elements in as yet unexplored parts of the Gippsland Basin. Given the recent attention paid to the basin as a CO2 storage province, palaeogeographic interpretations may be able to assist with the selection of appropriate injection sites.

Hydrocarbon charge history of the Gippsland Basin

2010 ◽  
Vol 50 (2) ◽  
pp. 729
Author(s):  
Keyu Liu ◽  
Peter Eadington ◽  
David Mills ◽  
Richard Kempton ◽  
Herbert Volk ◽  
...  
Keyword(s):  
System Analysis ◽  
Evaluation Research ◽  
Petroleum System ◽  
Additional Information ◽  
Oil Generation ◽  
History Of ◽  
And Migration ◽  
Hydrocarbon Charge ◽  
Gas Fields ◽  
Gippsland Basin

As part of a larger petroleum system analysis and resource re-evaluation research program in the Gippsland Basin, over 400 samples from 29 selected wells in the Gippsland Basin were investigated using quantitative fluorescence techniques developed by CSIRO Petroleum, including the quantitative grain fluorescence (QGF) and QGF on extracts (QGF-E) and the total scanning fluorescence (TSF) techniques. Preliminary results have provided new insight into the hydrocarbon migration and charge history of the Gippsland Basin. The investigation has revealed: widespread occurrence of palaeo oil columns in some of the major gas fields, indicating that a significant amount of oil was charged into these reservoirs prior to a subsequent gas accumulation; that some of the current oil intervals appear to have received a relatively late oil charge, either through new charge or through palaeo oil re-distribution due to adjustments within the petroleum system; palaeo oil columns appear to be restricted to a certain distance range from the major source kitchens; and, evidence of a sequential oil migration and displacement along structural highs where reservoirs distal to the source kitchens received progressively lighter and more mature palaeo oils. These findings are consistent with the oil generation and migration model proposed by O’Brien et al (2008). Fluid inclusion petrographic investigations and molecular composition of inclusions (MCI) analysis are currently underway that will provide additional information on the hydrocarbon charge history in the Gippsland Basin.

Revisiting petroleum systems in the Gippsland Basin using new geochemical data

2010 ◽  
Vol 50 (2) ◽  
pp. 728 ◽  
Author(s):  
Herbert Volk ◽  
Manzur Ahmed ◽  
Chris Boreham ◽  
Peter Tingate ◽  
Neil Sherwood ◽  
...  
Keyword(s):  
Molecular Weight ◽  
Fluid Inclusions ◽  
Isotope Geochemistry ◽  
Isotopic Analysis ◽  
Oil Field ◽  
Geochemical Data ◽  
Molecular Weight Range ◽  
Petroleum Systems ◽  
History Of ◽  
Gippsland Basin

The Gippsland Basin is one of the most prolific petroleum provinces in Australia, yet the understanding of source, migration and secondary alteration of petroleum is often based on data and concepts that have been developed decades ago. For instance, the Gippsland Basin is commonly cited as an explicit example of a province dominated by oil from coal, yet there is no literature using molecular and isotope geochemistry explicitly demonstrating that generation and expulsion has been from the coal seams and not the intervening carbonaceous mudstones. In this study we will present insights from the evaluation of quantitative analyses of aromatic hydrocarbons, which will be evaluated together with low molecular weight hydrocarbon distributions from whole oil gas chromatography and aliphatic biomarker distributions of the oils. Oils are commonly incrementors of different charge events, and hence extending molecular and isotopic information from a wide molecular weight range offers a more detailed insight into the charge history of an oil field. Oil-bearing fluid inclusions are additional archives that hold keys to the fill history of petroleum reservoirs, and this contribution will also present new data on the distribution and composition of palaeo-oils trapped in fluid inclusions. Lastly, examples will be presented of how modern tools for analysis such as compound specific isotopic analysis (CSIA) of n-alkanes and isoprenoids as well as how understanding relationships between organic facies and source rock kinetics can contribute to refining our understanding of petroleum systems in the Gippsland Basin.

Cannibalization and sealing of deepwater reservoirs by mass-transport complexes — The Jubilee field, Gulf of Mexico

2020 ◽  
Vol 8 (4) ◽  
pp. SV17-SV30
Author(s):  
Sebastian Cardona ◽  
Lesli Wood ◽  
Lorena Moscardelli ◽  
Dallas Dunlap
Keyword(s):  
Gulf Of Mexico ◽  
Mass Transport ◽  
Seismic Data ◽  
Hydrocarbon Exploration ◽  
Fluid Migration ◽  
Gas Field ◽  
Mass Flows ◽  
Gas Chimneys ◽  
Migration Pathways ◽  
Reservoir Deposits

Mass-transport complexes (MTCs) are important stratigraphic elements in many deepwater basins. In hydrocarbon exploration, MTCs have traditionally been identified as seals although they can also act as migration pathways or cannibalize and compartmentalize adjacent reservoirs. Although the ever-improving resolution of seismic data has enhanced the knowledge about these deposits (e.g., geometry, distribution), at present the potential of MTCs to act as top and/or lateral seals is difficult to predict predrilling and few case studies are publicly available. The key objective here is to present examples of seismically resolvable characteristics of two MTCs in the Jubilee gas field, offshore Gulf of Mexico: one of the MTCs cannibalized part of the reservoir, and the other acted as the top seal. The Jubilee field is an area where the ability of MTCs to act as a top seal has been proven — the field produced approximately 205 billion cubic feet of natural gas until abandonment in 2016. When evaluating the sealing potential of MTCs, seismic interpretation can offer a powerful technique to identify indicators of hydrocarbon leakage. Additionally, mass flows that form MTCs can be highly erosive and cannibalize underlying reservoir deposits, which increase reservoir heterogeneity that can lead to compartmentalization. Our results indicate that the seal MTC in the Jubilee field is a detached MTC and that the translational morphodomain overlies the gas accumulation. Consequently, when predicting the seal potential of MTCs from seismic data, it is important to determine (1) the type of MTC (i.e., attached versus detached), (2) the specific MTC morphodomain overlying the hydrocarbon accumulation/prospect (i.e., the headwall, translational, or toe morphodomains), and (3) the presence of seismic indicators of fluid migration pathways (e.g., gas chimneys, pockmarks, etc.). These results shed some light on the present challenges of predicting the seal potential of MTCs in frontier basins around the world.

GIPPSLAND BASIN GEOSEQUESTRATION: A POTENTIAL SOLUTION FOR THE LATROBE VALLEY BROWN COAL CO2 EMISSIONS

2006 ◽  
Vol 46 (1) ◽  
pp. 413 ◽  
Author(s):  
C.M. Gibson-Poole ◽  
L. Svendsen ◽  
J. Underschultz ◽  
M.N. Watson ◽  
J. Ennis-King ◽  
...  
Keyword(s):  
Co2 Emissions ◽  
Storage Capacity ◽  
Transient Flow ◽  
Co2 Storage ◽  
Oil Field ◽  
Stratigraphic Architecture ◽  
Gas Trapping ◽  
Mineral Trapping ◽  
Gippsland Basin ◽  
Migration Pathways

Geosequestration of CO2 in the offshore Gippsland Basin is being investigated by the CO2CRC as a possible method for storing the very large volumes of CO2 emissions from the Latrobe Valley area. A storage capacity of about 50 million tonnes of CO2 per year for a 40-year injection period is required, which will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets are not compromised. Detailed characterisation focussed on the Kingfish Field area as the first site to be potentially used, in the anticipation that this oil field will be depleted within the period 2015–25. The potential injection targets are the interbedded sandstones, shales and coals of the Paleocene-Eocene upper Latrobe Group, regionally sealed by the Lakes Entrance Formation. The research identified several features to the offshore Gippsland Basin that make it particularly favourable for CO2 storage. These include: a complex stratigraphic architecture that provides baffles which slow vertical migration and increase residual gas trapping; non-reactive reservoir units that have high injectivity; a thin, suitably reactive, low permeability marginal reservoir just below the regional seal providing additional mineral trapping; several depleted oil fields that provide storage capacity coupled with a transient flow regime arising from production that enhances containment; and, long migration pathways beneath a competent regional seal. This study has shown that the Gippsland Basin has sufficient capacity to store very large volumes of CO2. It may provide a solution to the problem of substantially reducing greenhouse gas emissions from the use of new coal developments in the Latrobe Valley.

NEOGENE TECTONICS IN SE AUSTRALIA: IMPLICATIONS FOR PETROLEUM SYSTEMS

2001 ◽  
Vol 41 (1) ◽  
pp. 37 ◽  
Author(s):  
J.A. Dickinson ◽  
M.W. Wallace ◽  
G.R. Holdgate ◽  
J. Daniels ◽  
S.J. Gallagher ◽  
...  
Keyword(s):  
Late Miocene ◽  
Oil And Gas ◽  
Petroleum Exploration ◽  
Petroleum Systems ◽  
Australian Plate ◽  
Late Tertiary ◽  
Petroleum Generation ◽  
History Of ◽  
Petroleum Accumulation ◽  
Gippsland Basin

The influence of Neogene tectonics in the SE Australian basins has generally been underestimated in the petroleum exploration literature. However, onshore stratigraphic and offshore seismic data indicates that significant deformation and exhumation (up to one km or more) has occurred during the late Tertiary-Quaternary. This tectonism coincides with a change in the dynamics of the Australian plate, beginning at around 12 Ma, resulting in a WNW–ESE compressional regime which has continued to the present day.Significant late Miocene tectonism is indicated by a regional angular unconformity at around the Mio-Pliocene boundary in the onshore and nearshore successions of the SE Australian basins.Evidence of on going Pliocene- Quaternary tectonism is widespread in all of the SE Australian basins. Late Tertiary tectonism has produced structures in the offshore SE Australian basins which have been favourable targets for petroleum accumulation (e.g. Nerita structure, Torquay Sub-basin; Cormorant structure, Bass Basin). In the offshore Gippsland Basin, most of the oil- and gas-bearing structures have grown during Oligocene-Recent time. Some Gippsland Basin structures were largely produced prior to the mid- Miocene, while others have a younger structural history. In areas of intense late Tertiary exhumation and uplift (e.g. proximal to the Otway and Strzelecki Ranges), burial/maturation models of petroleum generation may be significantly affected by Neogene uplift.Many structures produced by late Miocene-Pliocene deformation are dry. These relatively young structures may post-date the major maturation episodes, with the post-structure history of the basins dominated by exhumation and cooling.

INITIAL REVIEW OF THE BIOSTRATIGRAPHY AND PETROLEUM SYSTEMS AROUND THE TASMAN SEA HYDROCARBON-PRODUCING BASINS

2006 ◽  
Vol 46 (1) ◽  
pp. 201
Author(s):  
R.A. Cook ◽  
E.M. Crouch ◽  
J.I. Raine ◽  
C.P. Strong ◽  
C.I. Uruski ◽  
...  
Keyword(s):  
New Zealand ◽  
Sequence Stratigraphy ◽  
Sedimentary Basin ◽  
Geological History ◽  
Petroleum Systems ◽  
Tasman Sea ◽  
Internal Structures ◽  
History Of ◽  
Gippsland Basin ◽  
Recent Refinement

Understanding the genesis and habitat of hydrocarbons in a sedimentary basin takes knowledge of that basin at many levels, from basic infill geology to petroleum systems, plays, prospects and detailed sequence stratigraphy. While geophysics can define the basins and their internal structures, biostratigraphy and paleogeography provide greater understanding of basin geology. Micropaleontology and palynology are the chief tools that we need to define both the environment and dimension of time.As an example, the reconstruction of the Tasman Sea region to the mid-Cretaceous (ca 120 Ma) shows that the hydrocarbon-producing Gippsland and Taranaki petroleum basins developed at similar latitudes and in similar geological contexts. Other basins within the region have been lightly explored and need evaluation as to the value of further exploration.As paleontology has developed separately in Australia and New Zealand, comparison of biostratigraphic zones and their chronostratigraphy is critical to understand the similarity or otherwise of the sedimentary record of the two regions. Recent refinement of the NZ timescale and comparative studies on Gippsland Basin wells by NZ paleontologists have provided some key insights that enable us to compare the geological history of both regions more closely, and to recognise similarities in petroleum systems that may enhance petroleum prospects on both sides of the Tasman Sea.

Geochemical underpinnings of Australia's offshore hydrocarbon prospectivity

2014 ◽  
Vol 54 (1) ◽  
pp. 415
Author(s):  
Marita Bradshaw ◽  
Dianne Edwards ◽  
Chris Boreham ◽  
Emmanuelle Grosjean ◽  
Jennifer Totterdell ◽  
...  
Keyword(s):  
Source Rock ◽  
Lower Triassic ◽  
Source Rocks ◽  
Petroleum Systems ◽  
Isotopic Analyses ◽  
Marine Source ◽  
History Of ◽  
Hydrocarbon Sources ◽  
Geochemical Analyses ◽  
Gippsland Basin

Molecular and isotopic analyses of oils and gases can provide information on the depositional environment, maturation and age of their source rocks, and the post expulsion history of the hydrocarbons generated. Source rock analyses can determine their potential to generate hydrocarbons of varying type over specific thermal ranges, as well as demonstrating the strength of oil- or gas-to-source correlations. Together, this geochemical interpretation can provide insights about the extent of petroleum systems and can help delineate the relationships between hydrocarbon occurrences in a basin and across the continent. Oils that do not fit the well-established framework of oil families and Australian petroleum systems point to new source rock fairways. Examples include vagrant oils with lacustrine affinities found at various locations on the western Australian margin. Other examples are oil occurrences in the Gippsland Basin whose geochemical signatures contrast with the dominant non-marine oils, supporting the existence of a viable marine source rock facies. In under-explored and frontier basins, geochemical analyses of potential source rocks can provide key evidence to underpin new exploration efforts. For example, the recent acreage uptake in the Bight Basin was supported by Geoscience Australia’s recovery and analysis of oil-prone marine source rocks, and in the northern Perth Basin by new geochemical analysis extending the distribution of Lower Triassic Hovea marine source rocks offshore. Geoscience Australia has now embarked on a regional petroleum geological program that includes a national source rock study aimed at identifying and characterising Australia’s hydrocarbon sources, families and systems.

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