Latrobe Group Research Articles

Reservoir quality of the Late Cretaceous Volador Formation of the Latrobe group, Gippsland Basin, Australia: Implications from integrated analytical techniques

Increasing demand for energy due to the populous Eastern Australia has driven oil and gas industries to find new sources of hydrocarbons as they are the primary energy suppliers. Intensive study has been done on the Volador Formation in the Gippsland Basin by means of core-based petrophysical, sedimentological, and petrographic analyses as well as well log-based interpretation and capillary pressure test. Five wells from Kipper, Basker and Tuna fields with available dataset were investigated in this study: Kipper-1, Basker-1, Basker-2, Basker-5 and Tuna-4. Overall, the formation has good reservoir quality based on the high porosity and permeability values obtained through core and well log petrophysical analyses. The formation made up of mostly moderate to coarse quartz grains that has experienced strong anti-compaction and is poorly cemented. Montmorillonite and illite clays are seen dispersed in the rock formation, with the minority being mixed clays. These clays and diagenetic features including kaolinite cement and quartz overgrowth that can lead to porosity reduction only have insignificant impact on the overall reservoir quality. In addition, capillary pressure data shows that most samples are found in the transition to good reservoir zones (<50% saturation). The results obtained from this study have shown that the Volador Formation in the Gippsland Basin is worth for hydrocarbon exploration.

Maximising gas production from late-life assets: a case study from the Snapper Field, Gippsland Basin

Discovered in 1968 and developed in 1981, the Snapper Field has supplied oil and gas to Australia’s eastern seaboard for over 40 years. The field consists of a broad northeast–southwest trending faulted anticline within the Eocene and Paleocene sands of the Latrobe Group. Reserves in 2023 are within the shallowest reservoir interval – the N-1 – which had an original gas in place of approximately 3.8 Tcf. Pressure and wireline log data acquired during exploration and development suggested that the Snapper Field was horizontally and vertically well connected, and it was expected that individual intervals within the N-1 reservoir would water-out sequentially from the bottom to the top of the reservoir during production. As a result, the risk of water over-running gas, and bypassed gas was considered to be low. Production and logging results in 2017 proved otherwise, prompting a period of renewed study from 2019 to 2022. This paper focusses on the culmination of this work effort: construction of a new static geological model and dynamic simulation model, which was built upon and expanded previous models completed prior to 2019. The insights from this study have demonstrated the importance of ongoing and regular reservoir surveillance and the significant value that the construction of new static and dynamic models can add to late-life oil and gas fields. This study showed a later end of field life than previous estimates and an increase in reserves by up to ~20% through the optimisation of future work-over programs. The Snapper Field is owned by ExxonMobil (50%) and Woodside Energy (50%) and is operated by ExxonMobil.

Source rock characteristics and 1D basin modeling of the lower Cretaceous Latrobe Group, Gippsland Basin, Australia

The aim of this study is to perform source rock characterization of the Lower Cretaceous Latrobe Group's formations in the Gippsland Basin. A total of 138 source rock samples with coal and shale lithologies were selected from three formations represented by Chimaera, Curlip and Kipper Shale formations. The geochemical analyses consisting Rock-Eval pyrolysis, total organic carbon (TOC), vitrinite reflectance (% VR), maceral composition, and biomarkers were used for source rock characterization of the studied formations. It can be interpreted that the formations have poor to very good TOC (average of 2.32 wt %) indicating good organic abundance, while the coal samples from Chimaera Formation have higher organic abundance with excellent TOC (average of 45.25 wt %). These indicate good hydrocarbon generative potential. The formations mostly generate type II/III (mixed) to type III (gas prone) kerogens. Maturity parameters including production index (PI), temperature of maximum pyrolysis (Tmax), % VR and carbon preference index (CPI) indicated that the source rocks are immature to late mature (oil to oil/gas windows). Paleodepositional environment of source rocks is evaluated with biomarker data – normal alkane distribution, pristane/phytane (Pr/Ph) and isoprenoid/normal-alkane ratios. The results show that the source rocks are dominantly terrestrial, deposited in oxic setting. The rock samples did not show any sign of hydrocarbon migration, but experienced biodegradation. However, biomarker analyses were only done on the Chimaera Formation and the results do not represent the whole source rocks in this study. 1D basin modeling was done for Kipper wells. The results show that in Kipper-1, the oil and gas generations started in Kipper Shale at depths 1900 m about 24 Ma, and 2510 m about 15.4 Ma, respectively. In Kipper-2, oil and gas generations started in Chimaera Formation at depths 2540 m about 8 Ma, and 2580 m about 2.5 Ma, respectively. Transformation ratio (TR) plots show that the oil and gas generations have not reached the peak. Petroleum system event (PSE) chart suggested that the main hydrocarbon generation of the Latrobe Group started 26 Ma and is simultaneously being preserved in the Gippsland Basin. This study hopes to give insight of the burial history concept, hydrocarbon generation, and give support in the development of the hydrocarbon fields in the Gippsland Basin.

3D seismic geomorphology of Early Cenozoic incised channels, Gippsland Basin, SE Australia: Evidence for submarine origin

The Latrobe Group in the Gippsland Basin consists of well-developed, stacked shoreface and coastal plain deposits, cut by large, incised channel systems up to 500 m deep. These large channels are conspicuous on seismic intersections and have previously been interpreted as the result of fluvial incision associated with basin inversion/compressional tectonics. Here we have used 3D seismic, well log, and core to re-evaluate the origin of these channel systems. We interpret three major phases of channel incision-infilling; Tuna Channel 1, Tuna Channel 2 and the Marlin Channel. Biostratigraphic data shows that the channels range in age from the Palaeocene-Eocene transition to the Late Eocene. These ages indicate channel formation occurred prior to the onset of compressional tectonics in the Gippsland Basin, which began at the Eocene-Oligocene transition.Correlation of these channels with coeval palaeoshoreface systems reveals that the channels are located seaward of, and in close proximity to these shorelines. Well data indicates that the channel fill sediments are of marine origin, consisting of glauconite, dinoflagellates, foraminifera, and marine macro fossils. We do not observe evidence for a regional unconformity which would correlate with over 500 m of subaerial channel incision. These channels are therefore interpreted as submarine canyons, rather than channels of fluvial origin. They are interpreted as shelf-incising, with canyon heads located close to coeval palaeoshorelines where they received sediment via longshore/littoral processes. The erroneous identification of submarine canyons as incised valleys in sedimentary basins has significant implications for tectonic and eustatic histories globally.

The CarbonNet Pelican 3D seismic survey – A first for Australia’s offshore greenhouse gas storage

The CarbonNet Pelican 3D seismic survey – A first for Australia’s offshore greenhouse gas storage

Geochemical evaluation of aliphatic and aromatic hydrocarbons in Palaeogene source rocks from the Latrobe Group, Gippsland Basin, Australia

Twenty-seven hydrocarbon source rocks from the Proteacidites asperopolus, Malvacipollis diversus and Lygistepollenites balmei biozones, Palaeogene Latrobe Group in the Gippsland Basin were analysed using gas chromatography-mass spectrometry. Based on the molecular geochemistry of the aliphatic and aromatic fractions, together with bulk geochemical data (including Rock-Eval pyrolysis and total organic carbon contents), the thermal maturity, palaeoenvironments, and organic matter source of these Palaeogene samples were systematically evaluated. The results provide a useful comparison with those from Upper Cretaceous source rocks in the Gippsland Basin (Jiang and George, 2018, 2019). Similar to the Upper Cretaceous rocks, the aliphatic hydrocarbons in the Paleogene samples are mainly comprised of n-alkanes, isoprenoids, terpanes, hopanes and steranes. The aromatic hydrocarbons are dominated by naphthalene, phenanthrene, anthracene, fluorene, dibenzofuran, dibenzothiophene and their alkyl homologues. Other aromatic hydrocarbons detected include land plant-derived compounds (e.g. retene, methylretenes, cadalene, simonellite, etc), and combustion-derived compounds (e.g. chrysene, pyrene, picene, benzo[b]fluoranthene, benzo[a]anthracene, etc). These 4- to 6-ring polycyclic aromatic hydrocarbons are more abundant in the Paleogene samples compared to the Upper Cretaceous rocks. Biomarker and aromatic hydrocarbon distributions indicate that the Proteacidites asperopolus and Malvacipollis diversus samples are immature or are in the early stage of the oil generation window, while the Lygistepollenites balmei samples correspond to the low maturity to mature stage. The samples were all deposited under sub-oxic to oxic conditions in fresh water with low salinity, possibly in a lacustrine depositional environment. The organic matter inputs are from plankton/algae and higher land plants, but are dominated by organic matter with a terrigenous origin.

A probability model to detect carbonate cementation in sandstones and other enigmatic wireline facies

Zones of carbonate cementation identified within lower Paaratte Formation sandstones of the eastern Otway Basin, Victoria, southeastern Australia, can be quantitatively detected by a wireline log-based probability model. Though trained on these zones, the same model appears to accurately predict carbonate cementation within Late Cretaceous-to-Eocene reservoir sandstones of the Latrobe Group supersequence of the Gippsland Basin, 100s of km to the east. Predicted carbonate cementation matches published evidence (a regional petrographic study) and provides a plausible interpretation for corresponding sections of Formation Micro-Imager data acquired more recently. These Latrobe Group sandstones are thought to have once been pervasively cemented prior to development of the secondary porosity responsible for providing reservoirs to the main petroleum system of the basin. However, model predictions imply that discrete, heavily cemented zones remain, which must have acted, and must still act, as local obstructions to reservoir fluid migration. These zones would also likely react with carbonic acid formed at plume fronts generated by dedicated CO2 storage operations of the future. The cemented zones that have been predicted are sparse, spatially sporadic and cannot be resolved by 3D seismic reflection survey data at present-day reservoir depths. These predictions therefore emphasise the difficulty in mapping the distribution of carbonate cemented zones. However, they provide calibration data for future mapping systems.Two different tests of the probability log model were undertaken. One benchmarks its predictions against those of a neural network trained using the original model development dataset from the Otway Basin. Predictive performance of the neural network model is significantly worse than that of the probability log model when making predictions using wireline data acquired at a well in the Gippsland Basin. The second test demonstrates that the general probability log modelling approach is amenable to classifying other cryptic ‘electro-facies’, for example those representing enigmatic or ambiguous rock types not easily interpreted from common wireline log data using standard theory. This test presents a case study by which the probability log modelling approach predicts the presence of both basic and evolved, felsic igneous sill intrusions within the stratigraphic succession of the Faroe-Shetland Basin of NW Europe.

Cenozoic structural history of the Gippsland Basin: Early Oligocene onset for compressional tectonics in SE Australia

Abstract The Gippsland Basin contains some of the largest hydrocarbon accumulations in Australia, and has been in production since the 1920's. These hydrocarbons are trapped by large growth anticlines offshore, in reservoirs of the Cretaceous to Eocene-aged Latrobe Group. Despite the obvious importance of these growth anticlines, the timing of their formation, and the overall Cenozoic tectonic history of the basin is not well understood. Here, we present a detailed growth strata analysis of the faults and anticlines within the Cenozoic sediments of the Gippsland Basin. This indicates two major phases of tectonism in the basin: 1. Late Cretaceous to Eocene extension, and 2. Oligocene to Holocene compression. Detailed analysis of the extensional phase indicates the development of numerous normal growth faults, which display an overall reduction in the magnitude of extension from the Late Cretaceous to the Eocene, commonly terminating at the top of the Latrobe Group. The shift to compressional tectonism occurred at approximately the Eocene-Oligocene boundary (~34 Ma). A major and widespread episode of compression then occurred, with evidence of growth on anticlines and reverse faults beginning in the early Oligocene. This previously unrecognized early Oligocene event produced significant growth (20–50% total growth) of the major anticlines which host hydrocarbon accumulations. The early Oligocene event represents the first phase of the compressional tectonic regime that continues to the present day in SE Australia. It appears likely that this Oligocene event affected other basins in SE Australia and probably contributed to uplift of the Eastern Highlands. The underlying tectonic cause for this Oligocene compressional regime is enigmatic and may be related to far field tectonic processes. A second pulse of compressional tectonism and anticline growth occurred during the mid-Miocene and is generally more significant in the onshore regions of the basin. The youngest phase of compressional tectonism beginning in the Late Miocene (~10 Ma) is also more intense in onshore regions and is marked by an unconformity that is widespread in SE Australia.

THE ORIGIN OF FLORAL LAGERSTÄTTEN IN COALS

ABSTRACT Floral Lagerstätten deposits (i.e., fossil sites with exceptional preservation and diversity) are preserved within the Miocene brown coals of the Latrobe Group, Gippsland Basin, Australia. Three independent mechanisms are conducive to their accumulation. Throughout the coal seams the conversion of plant material into charcoal (fusain) and its accumulation in a subaqueous setting provides one means of near-perfect preservation. A second and more uncommon example occurs in the form of a 20 cm thick leaf-litter horizon that extends for over two kilometers. In this case, flooding of freshwater tributaries and lakes during the early stages of low-gradient peat development resulted in an extensive, shallow, acidic and water-filled depression that subsequently accumulated and preserved the surrounding plant material. The third and most common form results from the deposition of plant material into small, isolated pools that formed as depressions on the ombrogenous (i.e., rain-fed) and domed surface of the peatlands. In all of these settings an essential component allowing detailed floral preservation is the delivery of plant material directly to the anaerobic catotelm (i.e., below the water table), hence avoiding the physical and chemical processes of degradation that typically occur in the surficial aerobic acrotelm (i.e., above the water table). Leaf litter that falls into low-energy acidic and anoxic water-filled depressions that lie below the acrotelm will likely be well-preserved.

CarbonNet progress towards a declaration of identified storage formation at the Pelican site with a new high-resolution 3D seismic dataset

The CarbonNet project is making the first ever application for a ‘declaration of an identified greenhouse gas storage formation’ (similar to a petroleum location) under the Offshore Petroleum and Greenhouse Gas Storage Act. Unlike a petroleum location, however, there is no ‘discovery’ involved in the application. Instead, a detailed technical assessment is required of the geological suitability for successful long-term storage of CO2. The key challenges to achieving a successful application relate to addressing ‘fundamental suitability determinants’ under the act and regulations. At Pelican (Gippsland Basin), a new high-resolution 3D seismic survey and over 10 nearby petroleum wells (and over 1500 basinal wells) supplement a crestal well drilled in 1967 that proved the seal and reservoir stratigraphy. The GCN18A 3D marine seismic survey has the highest spatial and frequency resolution to date in the Gippsland Basin. The survey was acquired in water depths from 15 to 35 m with a conventional eight-streamer seismic vessel, aided by LiDAR bathymetry. The 12.5 m bin size and pre-stack depth migration with multiple tomographic velocity iterations have produced an unprecedented high-quality image of the Latrobe Group reservoirs and sealing units. The 3D seismic data provides excellent structural definition of the Pelican Anticline, and the overlying Golden Beach-1A gas pool is excellent. Depositional detail of reservoir-seal pairs within the Latrobe Group has been resolved, allowing a confident assessment of petroleum gas in place and CO2 storage opportunities. The CarbonNet project is progressing with a low-risk storage concept at intra-formational level, as proven by trapped pools at nearby oil and gas fields. Laterally extensive intra-formational shales provide seals across the entire structure, providing pressure and fluid separation between the overlying shallow hydrocarbon gas pool and the deeper CO2 storage opportunity. CarbonNet is assessing this storage opportunity and progressing towards a ‘declaration of an identified greenhouse gas storage formation’.

Biomarker signatures of Upper Cretaceous Latrobe Group petroleum source rocks, Gippsland Basin, Australia: Distribution and geological significance of aromatic hydrocarbons

Aromatic hydrocarbons extracted from Upper Cretaceous (Maastrichtian and Campanian) Latrobe Group coaly shales and shales from the Gippsland Basin were investigated by gas chromatography–mass spectrometry. A variety of 2-ring to 6-ring aromatic hydrocarbons were identified, including both higher-plant-derived and combustion-derived polycyclic aromatic hydrocarbons (PAHs). These aromatic compounds indicate that the Upper Cretaceous coaly shales and shales were deposited in a fluvial/deltaic environment with significant higher plant input and are at a relatively low thermal maturity stage. Higher plant parameters and angiosperm/gymnosperm indices based on aromatic components suggest that higher land plants, including both angiosperms and gymnosperms, were an important part of the palaeovegetation in the Upper Cretaceous. The aromatic angiosperm/gymnosperm index that includes chrysene- and picene-type PAHs is not as reliable for evaluation of relative angiosperm and gymnosperm contributions as the aliphatic indices due to input of combustion-derived PAHs and the complexity of burning conditions altering the relative contributions. However, combustion-derived PAHs and aromatic angiosperm/gymnosperm indices supplement the information from aliphatic hydrocarbons and provide further evidence to support the hypothesis that palaeoclimate cooled from the Campanian to the Maastrichtian.

Depositional setting for Eocene seat earths and related facies of the Gippsland Basin, Australia

The origin of seat earths (i.e. underclays, seat rocks, fire clays) has been investigated using sedimentological, palynological and mineralogical analysis of clastic-coal successions from the Eocene Traralgon Formation of the Gippsland Basin, Australia. The seat earths of the Latrobe Group are massive, a light grey to white colour, contain abundant slickensided fracture surfaces and isolated organic matter, and mineralogically consist of abundant kaolinite and lesser amounts of 2 M illite. From palynological evidence, the seat earths have paleoenvironments that grade from a fire-prone heath-fern meadow marsh (i.e. Gleicheniaceae and Epacridaceae dominant), to fire-tolerant shrubs and small trees (i.e. Cyatheaceae, Schizaeaceae and Proteaceae dominant) that fringe raised peatland rainforests. The palynological data also indicate a non-marine origin for the kaolinitic mudstones. The non-marine seat earths were deposited over a foundation of intertidal sediments (containing lenticular, wavy and flaser bedding, tidal rhythmites, extensive burrowing and a diverse assemblage of marine-influenced dinoflagellates). The upward increase in kaolinite, slickensides and rootlets within the seat earth indicates this clay was kaolinitized by pedogenic processes (i.e. weathering by organically derived humic/fulvic acids) prior to and throughout peat formation. The presence of well-preserved and abundant spore-pollen in the kaolinitic mudstones also suggests that the seat earths were deposited in an acidic and relatively reducing setting. The stratigraphic transition from tidal siltstone, to mudstone (seat earth) to coal in ascending order is interpreted as a shallowing-upwards succession. The seat earths of the Gippsland Basin were therefore deposited as a precursor non-marine facies (mostly meadow-marsh) grading into an ombrogenous coal facies, thereby explaining the intimate association between coals and seat earths globally.

Changes in Formation Water and Mineral Composition Under Co2 Storage Conditions for a Range of Rock Types of the Latrobe Group Reservoir, Gippsland Basin (Australia)

Changes in Formation Water and Mineral Composition Under Co2 Storage Conditions for a Range of Rock Types of the Latrobe Group Reservoir, Gippsland Basin (Australia)

Terrestrial cooling record through the Eocene-Oligocene transition of Australia

Abstract A new mid-latitude terrestrial climate proxy record is presented for southeastern Australia. The Middle Eocene to Middle Miocene palynofloral and δ13C record of the Latrobe Group, Gippsland Basin, details that the climate of southeastern Australia, paleolatitude 60–50°S, supported the growth of highly diverse subtropical to cool-temperate rainforests. These forests are characterized by mesothermal to microthermal floral elements that are here interpreted as subtropical (Malvacipollis subtilis and Cupanieidites orthoteichus dominated palynofloras), warm-temperate (Beaupreadites elegansiformis and Phyllocladus mawsonii dominated palynofloras) and cool-temperate (Nothofagus spp. and Dacrycarpidites australiensis dominated palynofloras) rainforests. The palynofloral record of the Latrobe Group indicates that mean annual temperatures were between 20 and 24 °C during the Middle Eocene resulting in subtropical rainforests, between 14 and 20 °C for the late Middle Eocene to earliest (i.e. pre-Oi1) Oligocene resulting in warm-temperate rainforests, between 10 and 14 °C for the late Early Oligocene to Early Miocene resulting in cool-temperate rainforests and between 14 and 20 °C in the Middle Miocene, facilitating the resurgence of warm-temperate rainforest floras. Rainfall was also likely in excess of 1500 mm throughout the Middle Eocene to the Middle Miocene in southeastern Australia. The climatic trends preserved within this mid-latitude terrestrial record relate to global Cenozoic cooling, the exception being the Middle Miocene records, which instead relate to the Middle Miocene Climatic Optimum. In the mid-latitude Gippsland Basin, cooling appears to have begun in the Middle Eocene. Correlation of our palynoflora with records from Antarctica and New Zealand, in addition to benthic δ18O records, reaffirms that the Latrobe Group coals provide a long-term, largely authochthonous mid-latitude floral record that directly relates to global climatic evolution through the Cenozoic. Our new mid-latitude terrestrial record provides critical insight into the validation of Eocene-Oligocene climate models and improves our understanding of mid-latitude terrestrial ecosystem responses to increased carbon dioxide forcing. The correlation between the δ13C values of the Yallourn and Morwell coal seams to benthic δ13C records also highlights that a relationship exists between the terrestrial and marine benthic δ13C record.

Biomarker signatures of Upper Cretaceous hydrocarbon source rocks from the Latrobe Group, Gippsland Basin

Gas chromatography-mass spectrometry analyses have been carried out to investigate the geochemical characteristics of the Latrobe Group shales and coaly shales from the Gippsland Basin, Australia. The depositional environment, source of organic matter and thermal maturity of hydrocarbon source rocks in the study area were evaluated using molecular biomarker analyses. The distribution of isoprenoid alkanes and pentacyclic triterpanes reveals an oxic environment with fresh water (pristane/phytane > 3.0, gammacerane index < 0.3). The carbon preference indices (CPI) and odd-to-even predominance ratios of the n-alkanes are higher than 1.0, suggesting terrigenous higher plant-derived organic matter in the sediments. The high predominance of C29 sterane over C27 sterane, as well as the occurrence of conifer and angiosperm biomarkers (e.g., labdane, isopimarane, phyllocladane, rimuane, oleanane, retene, anthracene, and cadalene), corroborates input from higher vascular land plants. Biomarker and aromatic thermal maturity indices, such as the methylphenanthrene index, the methylnaphthalene ratio, C31 22S/(22S+22R) hopanes, C30 αβ/(αβ+βα) hopanes and C29 ααα 20S/(20S+20R) steranes, indicate rather thermally immature hydrocarbon source rocks, in agreement with the above CPI data. This maturity trend is also supported by the triaromatic sterane index [TA(I)/TA(I+II)], which is generally lower than 0.2.

Predicting and Detecting Carbonate Cemented Zones Within Latrobe Group Reservoirs of the Gippsland Basin

A wireline log model predicts carbonate cemented zones within Late Cretaceous to Paleocene reservoir sandstones of the Latrobe Group, Gippsland Basin. Predictions match published evidence. These sandstones were once heavily cemented prior to development of secondary porosity that produced the world-class petroleum reservoirs we see today. Cemented zones that remain must act as obstructions to reservoir fluid migration. They may also react with the mild carbonic acid that will be introduced by CO2 storage operations of the future. Model predictions show that cemented zones are sparse, spatially sporadic and fall well below seismic resolution at modern-day reservoir depths. Their significance and irregular spatial occurrence mean there is a need to map their distribution.Synthetic seismograms generated for a number of Gippsland Basin wells predict high amplitude seismic reflectors away from major lithostratigraphic boundaries. Many occur where cemented zones are predicted. An investigation of the complex seismic trace demonstrates seismic sensitivity to these zones in the frequency range 100-125 Hz. An elevated moving average of instantaneous frequency correlates with some of them as does a modified instantaneous Q-factor. Others are indicated by a change in the difference of normalised instantaneous amplitude between the original frequency-filtered complex trace and a frequency-filtered complex trace composed of sinusoids with the same magnitude and phase (arithmetic averages of components of the original complex trace passed after frequency filtering). These subtle phase disturbances at high seismic frequencies are hypothesized to be caused by the presence of thin cemented zones. This idea is tested using instantaneous attributes calculated from 3D seismic survey data available across the Gippsland Basin.

Evidence of fire in Australian Cenozoic rainforests

New palynological analysis of the Middle Eocene to Middle Miocene Latrobe Group coals of the Gippsland Basin in Australia sheds new light on fire adaptation in Australia's modern flora. The distribution of charcoal and fire-prone flora within brown coals is entirely controlled by facies and the paleoenvironments within the peatland, and does not result from drier climates as has been previously suggested. There is therefore, no evidence of climatic drying from this Cenozoic peatland record. Charcoal and fire-prone floras are associated with emergent and meadow marsh environments that produce darker coal lithotypes. Counter-intuitively, the low-nutrient and fire-prone environments that fringed the ever-wet rainforests of the Latrobe Group peatlands may have represented an ideal setting for southeastern Australia's modern fire-adapted and sclerophyllous flora (i.e., Eucalyptus and Banksia) to evolve in.

Biomarker signatures of Upper Cretaceous Latrobe Group hydrocarbon source rocks, Gippsland Basin, Australia: Distribution and palaeoenvironment significance of aliphatic hydrocarbons

Upper Cretaceous (Maastrichtian and Campanian) hydrocarbon source rocks from the Latrobe Group, Gippsland Basin (Australia) have been analysed using gas chromatography–mass spectrometry (GC–MS) in order to understand their geochemical characteristics and to reconstruct palaeovegetation and palaeoclimate changes. n-Alkanes ranging from C10 to C37 dominate the aliphatic hydrocarbons in the rock extracts. Both the carbon preference index and the odd-to-even predominance values of n-alkanes are higher than 1.0, suggesting an input from terrigenous higher plants. Low wax indices (mostly < 1.0) and a predominance of C29 over C27 steranes corroborate a major contribution from higher plants. High pristane/phytane (Pr/Ph) ratios (>3.0), a low gammacerane index (<0.3) and the Pr/n-C17 versus Ph/n-C18 cross-plot indicate that the Upper Cretaceous hydrocarbon source rocks were probably deposited in an oxidising environment with fresh water. Thermal maturity parameters such as sterane isomerisation ratios, C31 22S/(22S + 22R) homohopane, C30 αβ/(αβ + βα) hopane and 16(H) β/(α + β) phyllocladane, together with Tmax data and the presence of C27 17β(H)-22,29,30-trisnorhopane (βTm), suggest that most of samples have a relatively low maturity in the early to mid-oil generation window. Angiosperm- and gymnosperm-derived biomarkers, including labdane, pimarane, isopimarane, phyllocladane, abietane, rimuane, ent-beyerane, ent-kaurane, oleanane, 10β(H)-des-A-oleanane, 10β(H)-des-A-lupane, and 10β(H)-des-A-ursane, suggest that palaeovegetation during the Upper Cretaceous was characterised by both gymnosperms (e.g. Araucariaceae and Podocarpaceae) and angiosperms (e.g. Nothofagus), but was dominated by gymnosperms. Compared with samples from the Campanian, there was a relatively lesser contribution from angiosperms during the Maastrichtian. This shows that the palaeoclimate was becoming cooler from the Campanian to the Maastrichtian, which is consistent with previous palynology evidence and sea-surface temperature estimates.

Shale alteration after exposure to supercritical CO2

Caprock seal efficiency evaluation is a vital part of the assessment of any CO2 storage site. The main goal of this study was to examine the dynamic seal capacity of several intra-formational shale units in the Latrobe Group in the Gippsland Basin, Australia and to characterise their caprock sealing efficiency before and after exposure to supercritical CO2 (scCO2).This laboratory study examined changes to the mineralogical composition of the shale, capillary threshold pressure, and pore size distribution before and after being exposed to scCO2 at reservoir conditions utilizing several analytical methods. Samples selected for this study were taken from cores that have been stored in a sample facility. Since the original mineralogy of the samples is likely to have changed over time at surface storage conditions, thus chemical reactions may be different if fresh samples could have been analysed.X-ray diffraction (XRD) and scanning electron microscopy (SEM) indicate that there are several chemical reactions that occurred between rock-forming minerals and the brine-scCO2 system. Chemical reactions include dissolution and precipitation of several authigenic minerals such as kaolinite, natrojarosite, silica and gypsum.Mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) measurements indicate a reduction in the capillary threshold pressures and an increase in pore volume for most of the samples exposed to scCO2.

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

Pyrolysis experiments (open and closed systems) and kinetic modelling of primary cracking of kerogen have been carried out to investigate hydrocarbon generation characteristics and source rock facies variability within the Upper Cretaceous to Paleogene Latrobe Group in the Gippsland Basin. On the basis of Rock-Eval data, the interbedded coals, coaly shales and carbonaceous shales contain different types of kerogen (Type III, Type II–III, Type II) with variable potential for both gas and liquid hydrocarbon generation. Open system pyrolysis–gas chromatography data indicate that the organically lean marginal marine shales of the Santonian–early Campanian Tricolporites apoxyexinus and Nothofagidites senectus biozones produce gas and condensate. However, coal and coaly to carbonaceous shales sampled from the Paleocene Lygistepollenites balmei, Maastrichtian Forcipites longus, late Campanian Tricolporites lilliei and Turonian Phyllocladidites mawsonii palynological biozones are heterogeneous with the capacity to generate both low and high wax paraffinic–naphthenic–aromatic (P–N–A) oils, and paraffinic oils with a high wax content. The main phase of petroleum formation from these later biozones, assuming a constant geological heating rate of 3.3°C/Ma, is predicted to occur between 150–179°C, indicating different orders of kinetic stability as a result of different types of organic matter and their state of preservation. The thermally immature shales have variable bulk kinetic characteristics, but the measured compositional kinetics and phase behaviour show that they have the potential to generate black oils at early stages of kerogen cracking, and either light oils or wet gases at higher levels of thermal stress. These findings suggest that upon thermal maturation, the interbedded shales of the Latrobe Group may have contributed significant volumes of hydrocarbons to the oil and gas accumulations in the Gippsland Basin. In addition, this study not only supports the premise that over-reliance on Rock-Eval/TOC data alone can be misleading for assessment of petroleum generation, but also represents a strategy for kerogen type and generative potential determination for fluvio-deltaic coals and subordinate lithologies.