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

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

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

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

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

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

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.

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

Depositional setting for Eocene seat earths and related facies of the 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

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.

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.

Evidence of fire in Australian Cenozoic rainforests

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

Shale alteration after exposure to supercritical CO2

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