Source Rocks of the Cooper Basin

Analytical pyrolysis and sealed tube pyrolysis at low temperatures have been used to study the timing and petroleum generating capacity of selected Permian through Tertiary coals and carbonaceous shales in relation to their petrographic and elemental composition. The results show that judicious application of flash pyrolysis techniques in conjunction with more conventional procedures are essential for effective source rock assessment in terrigenous source rocks, particularly in those of lower quality. Although the petroleum potential of the samples follows the broad trends in petrographic composition established for Australian coals, that is, relative proportions of vitrinite, inertinite and liptinite, there is much variation which cannot be explained petrographically at the maceral group level. Furthermore, there is no simple relationship between pyrolytic hydrocarbon yield from terrigenous kerogens and overall elemental composition. The yield and composition of pyrolysable normal hydrocarbons varies widely depending on the nature and amount of liptinite macerals, particularly for samples with Hydrogen Indices below 300. Liptinite-poor (<10 per cent) samples may yield significant amounts of hydrocarbons, but typically they have a low wax content. Suberinite is associated with high yields of waxy hydrocarbons, but sporinite and liptodetrinite have a lower hydrocarbon potential and do not yield the waxy compounds. These geochemical results are explicable in terms of the relatively abstract concepts of labile, refractory and inert kerogens rather than standard petrographic descriptions. Mass balance calculations based on Rock-Eval analyses of samples from the Jurassic Walloon Coal Measures show that the maximum oil formation occurs over a very narrow maturation window from 0.8 to 1.0 per cent Ro, although small amounts of oil may be generated at lower maturation levels. The gas to oil ratio of the generated hydrocarbons is constant up to a reflectance level of 1.0 per cent Ro, where upon the proportion of gas increases rapidly. The low quality Permian source rocks from the Cooper Basin have a lower ratio of labile to refractory kerogen than the Jurassic and Tertiary examples. As a result, the gas to oil ratio of hydrocarbons formed in the oil window is higher and the oil potential appears to be exhausted at an earlier stage of maturation. Efficient migration of hydrocarbons from Permian sediments in the Cooper Basin also appears to occur at a relatively early stage of maturation compared with the Jurassic Walloon Coal Measures.

Geochemical analysis, petrographic examination and wireline log interpretation have identified intervals within the lower Eumeralla Formation of the Otway Group (Early Cretaceous) with good source potential. The sequence has a maximum penetrated thickness of 260 m and consists of thinly interbedded coal and siltstone deposited in peat swamp and lacustrine environments. Vitrinite is the dominant maceral present in the coal although the proportion of more oil-prone liptinite commonly exceeds 10 per cent. This is consistent with the intermediate Type II/ III kerogen composition indicated by Rock-Eval and is comparable with data from proven terrestrial oil-productive source rocks in the Gippsland and Cooper Basins. The siltstone is organically-lean but has some algal input. Algal-rich lacustrine source rocks could be developed nearer the basin centre. Regional stratigraphic, structural and thermal modelling studies highlight the exploration potential of the Chama Terrace in the northwest Otway Basin. Structures on the terrace are ideally situated to receive a hydrocarbon charge from mature Eumeralla Formation source rocks in fault blocks on the downthrown side of the Tartwaup Hingeline. Seismic mapping of offshore permit EPP 24, and adjacent onshore permit PEL 40, has delineated several large fault blocks where Crayfish Subgroup (Otway Group) reservoir is juxtaposed against, and sealed by, the lower Eumeralla Formation sequence. Drilling scheduled for late 1992 will determine the credibility of the Eumeralla-sourced play and provide a key test of the ultimate hydrocarbon potential of the Otway Basin.

The thick, regionally extensive lacustrine shales of the Cooper Basin were discovered more than half a century ago, but it was not until recently that the source rock and reservoir potential of the shales were recognised, particularly within the Nappamerri Trough, which is the deepest and largest of the structural troughs in the Cooper Basin, South Australia. In 2010, at the commencement of an extensive exploration and evaluation program, there were no pre-existing analogues for the Nappamerri Trough shale play, as all commercially produced shale plays in North America involve marine rather than lacustrine shales. Data from existing wells in the area provided a preliminary indication of shale potential, in particular, the organic content, maturity, mineralogy and extent of overpressure. A thorough wireline logging and core-analysis program was designed for the initial exploration wells to expand the understanding of key shale characteristics. The high geothermal gradient proved to be challenging for evaluation with some logging runs having to be curtailed. As a starting point, published methods for evaluating shales were applied to the Nappamerri Trough shales with limited success. Using a deterministic interpretation method and core calibration, petrophysical evaluations were completed which are not only suitable for initial shale assessment, but they also identified where the key petrophysical uncertainties were and how they could be addressed in the future.

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.

Recent developments in hydrogenation procedures allow the liquid hydrocarbon potential and the total liquid hydrocarbon content of source rocks to be determined directly. In essence, mild controlled hydrogenation. without the cleavage of C-C bonds, converts the recognized hydrocarbon precursors in immature source rocks, i.e. the largely aliphatic acids, alcohols, esters, etc., into the parent alkanes. These alkanes, which have a distinctive composition, are easily collected and determined in toto by routine analytical processes. Thus hydrocarbon potentials are immediately revealed.Since the bulk of Australian crudes are of land plant (humic) origin, initial investigations have been largely concentrated on vitrinites and inertinites separated from Australian coals. These studies have shown that:the formation, on hydrogenation, of alkanes with a distinctive composition is an excellent guide to sediment maturity and to hydrocarbon potential; hydrocarbon generation, although not hydrocarbon maturation, is complete when the reflectance of vitrinite in contributing sediments approximates 0.65 per cent; and no significant difference exists between the hydrocarbon potentials and the hydrocarbon content of associated inertinites and vitrinites when the reflectance of the latter is in the range 0.3 to 1.2 per cent. These findings provide a guide to basin potentials and an explanation for the unexpected prospectivity of inertinite-rich Australian sediments.Results of applying this procedure to sediment samples from exploratory wells in the Gippsland and Cooper Basins have generally followed trends seen with coal samples and confirmed the value of the method in determining hydrocarbon potentials.

The Gippsland basin, with its oil and gas resources, provides an excellent area for organic geochemical and petrologic research on the generation, migration, and alteration of hydrocarbons. The main source rocks for the known oil and gas deposits appear to be at depths greater than those reached by any of the exploration wells. The type of organic material originally present in the rocks now at depths greater than 4,000 m (and now at temperatures greater than 130°C) is unknown but, at least within the Latrobe Group, it appears to have had a high exinite content similar to that observed in the upper part of the group. At such temperatures, thermal cracking of exinite would yield a considerable amount of oil, whereas the products from vitrinite would be mainly gas and solid residue. Migration to reservoirs below the unconformity at the top of the Latrobe Group would follow. Both generation and migration are believed to be occurring at the present time, as immature carbonaceous material is being exposed to higher temperatures by deeper burial. Chromatographic analysis of Gippsland crude oils suggests that the oils originate from solid organic matter derived from algae and land plants, the latter contributing to the high wax content. Gas generation in the Cooper basin provides an interesting comparison with the Gippsland basin in relation to type of organic material and geothermal history.

The Warburton Basin is currently considered economic basement to the gas-oil productive Cooper Basin and the oil productive Eromanga Basin. Only 10 wells have penetrated more than 100 m of the Kalladeina Formation which is identified as the most prospective section within the Warburton Basin. The Kalladeina Formation consists of more than 1600 m of carbonate shelf sediments deposited during the early Cambrian to early Ordovician in a basin consisting of half grabens on the continental side of an active margin. Several intra-Kalladeina Formation seismic events in a 500 km2 region to the west of the Gidgealpa oil and gas field have been tied to wells with palaeontological control. Structure and isopach mapping illustrates large scale thrusts, wrench fault zones and subcrop edges for the Kalladeina Formation. Maps of unconformities and of formations above the Warburton Basin define source, seal and trap relationships. Good carbonate reservoirs have been identified in the Kalladeina Formation but the source potential of this succession appears to be restricted. The overlying Cooper Basin source rocks may have charged the underlying carbonates and this represents one of three play types identified in the area. All Warburton Basin plays are very high risk but potential reserves are also large.

Hydraulic fracture stimulation of low permeability source rock-reservoirs is increasing in the industry and low-permeability, deeply buried coals, "Deep Coals," represent an underdeveloped resource in the Cooper Basin of South Australia. Numerous treatments have been performed with overall technical success but varied productivity. Thus, it was important to understand the potential hydraulic fracture conductivity in the Permian Deep Coal play by evaluating the key treatment variables affecting post-stimulation results. Proppant conductivity tests were conducted on samples from two preserved Deep Coal cores of differing thermal maturity under laboratory conditions, replicating reservoir conditions. Varying concentrations and mesh sizes of lightweight ceramic (LWP) and sand proppants were tested at 250°F. All tests were subject to closure stresses observed in the field, ranging from 2,000 psi to 10,000 psi, using representative hydraulic fracturing fluids. Results revealed a significant conductivity difference between the two coal thermal ranks due to variation in mechanical properties Varying proppant concentration tests revealed that effective conductivity at higher stresses occurs within a narrow window. This window is a balance between insufficiently low concentration resulting in significant conductivity loss, and excessive, non-linear conductivity gains in higher concentrations. Results from these studies are integrated into a hydraulic fracture and reservoir stimulation modelling software to up-scale the observed results versus the laboratory data. Finally, laboratory results helped explain trends for success in stimulation design based on observed post-frac, flow rates.

The Eringa Trough occupies an area of over 8,000 km2 in SA and the NT and contains an estimated 1,500 m of Permo-Carboniferous and over 1,000 m of Mesozoic sediments. Early Permian depositional history of this frontier region is similar to that of the Cooper Basin in northeastern SA. The Eringa Trough has limited seismic coverage and sparse petroleum and mineral exploration drillholes are located on the trough margins. Interpretation of 255 km of new seismic and reprocessed data has delineated a number of undrilled prospects.Excellent quality reservoirs are present. Early mature to mature, Permian and Jurassic source rocks occur, including good to excellent Type-II kerogens within an equivalent of the Jurassic Birkhead Formation. Apatite fission track analysis of Permian and Jurassic sediment shows palaeo-temperatures were approximately 30-40°C higher than at present and that cooling occurred within the last 60 Ma. This suggests that Permian and Jurassic sediments in the deeper parts of the Eringa Trough have experienced temperatures suitable for petroleum generation.An integrated evaluation of the Eringa Trough in SA and the NT has resulted in a greater understanding of this frontier area which has the potential for significant commercial petroleum discoveries.