Cooper-Eromanga Basins Research Articles

Geoscience Poster G1: Origins of hydrogen sulfide (H

Poster G1 The distribution and origin of hydrogen sulfide (H2S) within gas reservoirs is an important issue due to its toxicity and ability to corrode metal infrastructure, even at low concentrations (i.e. 50 ppm). H2S gas is regarded as a high priority for health and safety at drilling sites. The distribution of H2S, in some basins, can be inexplicable with a mix of sweet (no H2S) and sour (contains H2S) wells within one multi-well pad. Sour gas is a concern in some gas and coal fields in Australia which include Gippsland, Bowen and Cooper-Eromanga basins as well as in the North West Shelf with typical concentrations below 10 000 ppm. For example, the German Creek Formation (Bowen Basin) contains up to 77 ppm of H2S gas and coal seam gas producers will need to perform a risk assessment while exploring and developing this resource. There are multiple sources of H2S gas sulfur and this includes sulfate minerals, pyrite, organic sulfur or from frack water. This research utilises the isotopic variation in the sulfur and oxygen of potential sources, coupled with petrological analyses to determine H2S gas generation. Data is used to predict the gas distribution within the reservoirs to reduce exploration risks. One initial study on the Triassic Montney Formation in western Canada produces H2S gas at concentrations up to 220 000 ppm. Isotopic analyses suggest that the H2S is generated from either Triassic sulfates or a mixture of Triassic and Devonian sources and not solely from Devonian rocks as first expected. To access the poster click the link on the right. To read the full paper click here

Origins of hydrogen sulfide (H

The distribution and origin of hydrogen sulfide (H2S) within gas reservoirs is an important issue due to its toxicity and ability to corrode metal infrastructure, even at low concentrations (i.e. 50 ppm). H2S gas is regarded as a high priority for health and safety at drilling sites. The distribution of H2S, in some basins, can be inexplicable with a mix of sweet (no H2S) and sour (contains H2S) wells within one multi-well pad. Sour gas is a concern in some gas and coal fields in Australia which include Gippsland, Bowen and Cooper-Eromanga basins as well as in the North West Shelf with typical concentrations below 10 000 ppm. For example, the German Creek Formation (Bowen Basin) contains up to 77 ppm of H2S gas and coal seam gas producers will need to perform a risk assessment while exploring and developing this resource. There are multiple sources of H2S gas sulfur and this includes sulfate minerals, pyrite, organic sulfur or from frack water. This research utilises the isotopic variation in the sulfur and oxygen of potential sources, coupled with petrological analyses to determine H2S gas generation. Data is used to predict the gas distribution within the reservoirs to reduce exploration risks. One initial study on the Triassic Montney Formation in western Canada produces H2S gas at concentrations up to 220 000 ppm. Isotopic analyses suggest that the H2S is generated from either Triassic sulfates or a mixture of Triassic and Devonian sources and not solely from Devonian rocks as first expected.

CO2-EOR+ in Australia: achieving low-emissions oil and unlocking residual oil resources

The petroleum industry, through the production and consumption of oil and gas, contributes to global greenhouse gas emissions. However, the industry’s leadership and experience in underground injection and storage of CO2, especially through CO2 enhanced oil recovery (CO2-EOR), which has been proposed as a possible solution to reducing atmospheric CO2 levels, has not been well acknowledged. Unlike traditional CO2-EOR, which tends to be a net carbon emitter due to the use of predominantly natural CO2, rather than anthropogenic, CO2-EOR+ focuses on storing a larger volume of CO2. Thus CO2-EOR+ not only provides a potential solution to dispose of anthropogenic emissions but at the same time reduces reliance on imported oil through increased domestic production. Increased industry interest and energy policy strategies directed at reducing and/or removing emissions from industry processes reflect the growing social and economic impetus to improve operation practices and the petroleum industry’s reputation. Residual oil zones (ROZs) below identified oil–water contacts provide an excellent target for the application of CO2-EOR+. They offer a producible residual oil resource accessible through CO2-EOR, as well as a large pore volume for CO2 storage, with efforts focused on converting ROZs into resources and reserves. Existing fields in the Surat and Cooper-Eromanga Basins are already well placed to utilise anthropogenic CO2 sources to achieve conventional CO2-EOR metrics. The ROZs in these basins will hopefully allow potential EOR projects to increase the CO2 volumes stored, per incremental barrel of oil, well past traditional levels (0.2–0.3 tCO2/bbl), and in doing so, potentially achieve net negative-emission oil.

Play-based exploration in the southern Cooper Basin: a systematic approach to exploration in a mature basin

Exploration within a mature basin poses many challenges, not least how to best utilise resources and time to maximise success and reduce cost. Play-based exploration (PBE) provides a team-based approach to combine key aspects of the petroleum system into an integrated and wholistic view of basin prospectivity. While the PBE methodology is well established, it is not often applied to its full extent on a basin scale. After a period of declining exploration success in parts of the South Australia Cooper-Eromanga Basin, this study was undertaken by a dedicated regional geoscience team with the aim of rebuilding an understanding of the basin, based on first principles and stripping away exploration paradigms. The study area comprises an acreage position in the South Australian and Queensland Cooper-Eromanga Basins covering 70 000 km2 in which Senex Energy has 14 oil fields, has drilled more than 80 exploration wells and has acquired 2D and 3D seismic material. A plethora of proven and emerging plays exist within the acreage ranging from high productivity light sweet oil (Birkhead and Namur Reservoirs) to tight oil (Murta Formation), conventional gas (Toolachee/Epsilon and Patchawarra Formation), tight gas (Patchawarra Formation) and the emerging deep coal play (Toolachee and Patchawarra Coals). Play-based exploration methodologies incorporating the integration of seismic data, log and palynological data, structural analysis, geochemistry, 3D basin modelling, consistent well failure analysis and gross depositional environment maps have allowed the systematic creation of common risk segment maps at all play levels. This information is now actively utilised for permit management, business development, work program creation and portfolio management. This paper will present an example of the work focussing on the southern section of the South Australian Cooper-Eromanga Basin.

Innovative high trace density design with broadband seismic data acquisition in the Cooper–Eromanga Basins, Australia

Through a combination of innovative survey design, new technology and the introduction of novel operational techniques, the trace density of a 3D seismic survey in the Cooper Basin was increased from a baseline of 140 000 to 1 600 000 traces km–2, the bandwidth of the data was extended from four to six octaves, and the dataset was acquired in substantially the same time-frame and for the same cost as the baseline survey.

Source rock characterisation of under-explored regions of Queensland

Historically, petroleum exploration in Queensland has focused on the Bowen-Surat and Cooper-Eromanga basins, with only cursory examination of other basins across the state. As part of the Queensland Industry Priorities Initiative, two projects (Round 1 and 2) were submitted to the Geological Survey of Queensland (GSQ) to examine the geochemical characteristics of potential petroleum source rocks throughout Queensland. The analysis conducted provides a better understanding of generative potential for petroleum, and predicts the timing, volume, composition, and physical state of hydrocarbons retained in and expelled from source rocks. It is an integral component to petroleum systems analysis used to identify the potential for undiscovered accumulations of petroleum from conventional and unconventional reservoirs. Of particular interest were the Georgina, Drummond, Eromanga, and Maryborough basins. Of these, the Georgina and Maryborough basins have known hydrocarbon shows identified through exploration drilling, though no commercial discoveries have yet been made. The Drummond Basin was targeted to identify a potential source for oil and gas shows encountered in drilling within the Galilee Basin. The Toolebuc Formation in the Eromanga Basin has been noted as having the potential for a shale oil play and this study is supporting further assessment to identify optimal areas for future exploration through predictive modelling. This report details the results from Round 1 of the study for samples taken from the Georgina Limestone and Scartwater, Ducabrook, Mount Hall, Toolebuc, and Maryborough formations, where limited analysis of source rock characteristics has historically been undertaken. Ninety-seven samples were chosen from nine wells and sent to Geos4 in Potsdam, Germany, for source rock analysis. All samples were screened for suitability of further analysis using Rock-Eval and TOC by LECO, with immature and organic-rich samples being preferentially selected for further testing. Screened samples were analysed using pyrolysis gas chromatography (n=27), thermovaporisation (n=23), bulk kinetics (n=5), compositional kinetics (n=4), late gas analysis (n=14), and biomarker and bulk isotope analysis (n=15). These results have been integrated with existing analyses to better understand the prospectivity of the under-explored basins of Queensland.

Chemical and mineralogical characterisation of illite–smectite: Implications for episodic tectonism and associated fluid flow, central Australia

The Warburton–Cooper–Eromanga basins of central–eastern Australia contain a number of reactivated fracture–fault networks that relate to a complex and poorly understood thermal and tectonic evolution. Authigenic illite was sampled from two prominent features of the Warburton–Cooper basins: the Gidgealpa–Merrimelia–Innamincka Ridge, composed of anticlinal imbricate thrust fault blocks, and the synclinal Nappamerri Trough. These sample sets were investigated using a combination of clay mineralogical, trace element and stable isotope analyses to deduce the palaeofluid chemistry associated with past tectonothermal perturbations. The Nappamerri Trough hosts the highly radiogenic Big Lake Suite granite and part of one of Australia’s larger on-shore oil and gas reserves. Calculated fluid stable isotope values from the trough, in conjunction with calculated palaeotemperatures, indicate an influx of evolved high-latitudinal meteoric waters under an extremely high geothermal gradient (∼100°Ckm−1) and high water/rock ratios consistent with an extensional environment. Such high water/rock ratios resulted in intense alteration of the granite during which it underwent substantial enrichment in the heat-producing elements (HPE), particularly Th. This hydrothermal system is interpreted to result from continent-wide transmission of tensional stress originating from episodic rifting of the eastern Australian margin in the mid Cretaceous, as dated by Sm–Nd, Rb–Sr and Ar–Ar. The Gidgealpa–Merrimelia–Innamincka Ridge, by contrast, is marked by a lower, but still elevated, palaeogeothermal gradient (∼42°Ckm−1) and calculated fluid isotopic values compatible with evolved basinal fluids of meteoric origin under low water/rock ratio conditions. Distinct trace element compositions of residue and leachate aliquots further indicate two periods of fluid flow with unique chemical compositions. In light of previous geochronology, these events are interpreted as westward extensions of widespread crustal tensional stress that affected much of central and eastern Queensland in the Carboniferous and Late Triassic.Integrated analyses of authigenic illite provide evidence for three periods of fluid flow and elevated thermal regime associated with regional tectonism during the Carboniferous, Late Triassic and Cretaceous. Our data further show that due to the extremely high geothermal gradient and water/rock ratios, Cretaceous fluid flow had profound effects on the surrounding geology, which may have formed/enhanced two of Australia’s most significant energy resources.

The changing face of Queensland's petroleum industry

The cycles and related changes in exploration targets identified in this study show the evolution of the Queensland petroleum industry from conventional petroleum to coal seam gas dominance. Delineation of these cycles was undertaken using petroleum exploration well data, and production and reserves statistics. Although the cycles are defined on the basis of exploration activity, there is a very different history in the types of targets and commodities explored for in the Bowen-Surat and Cooper-Eromanga basins. Trends in exploration success have been influenced by technology improvements, better understanding of target reservoirs, proximity to infrastructure, government policy and world oil prices. Four distinct exploration cycles have been identified from the data. During the first cycle (1959–74) exploration focused predominantly on the shallower Jurassic-aged reservoirs in the Bowen-Surat basins resulting in the discovery of most of the major conventional oil and gas fields. The second cycle (1979–89) saw exploration begin in earnest in the Cooper-Eromanga basins and a switch to predominantly Triassic-aged reservoirs in the Bowen-Surat basins. The first coal seam gas exploration wells were drilled during this cycle. The third cycle (1990–99) shows a decrease in the number of conventional petroleum wells across both regions and the beginning of the switch to the present dominance of coal seam gas. The fourth cycle (2000–present) shows a significant decrease in the number of conventional exploration wells drilled across both regions, but an increase in the success rates. All conventional discoveries in the Bowen-Surat basins during cycle four have been in Permian-aged reservoirs, reflecting a change in the exploration focus to deeper parts of the Bowen Basin. Coal seam gas exploration has expanded significantly, with the Walloon Coal Measures being targeted, resulting in nearly four coal seam gas wells drilled for each conventional petroleum exploration well state-wide since 2000. Examination of coal seam gas exploration highlights the many false starts since the first well was drilled in 1980. Exploration has shifted from area to area as companies tested different exploration concepts and completion techniques. The most obvious shift has been from Permian-aged targets of the Bowen Basin into the Jurassic-aged Walloon Coal Measures in the Surat and Clarence-Moreton basins, as its prospectivity was realised.

Review of Exhumation and Implications for Hydrocarbon Exploration in Australia

The subsidence history of sedimentary basins is recorded and can be relatively easily reconstructed from the preserved stratigraphic sequence. Uplift events, above sedimentary base level are expressed only by hiatuses or uncon- formities. Hence, quantifying the exhumation associated with uplift is intrinsically more problematic than quantifying the burial associated with the subsidence. Detailed study of the exhumation in basins is of particular significance since can provide crucial information about the petroleum exploration and for investigating the dynamic driving forces of basin up- lift events. The aim of this article is to evaluate the magnitudes of exhumation in two well known petroliferous basins, the Cooper-Eromanga Basins of South Australia and Queensland, based on different techniques and to consider the implica- tions for petroleum exploration.

Two layer model of lithospheric compression and uplift/exhumation in an intracratonic setting: an example from the Cooper–Eromanga Basins, Australia

Seismic reflection profiles indicate the compressive nature of the structural style associated with the major uplift events in the Cooper–Eromanga Basins. Inversion geometries and reactivated features attest to a period of compression during Late Triassic–Early Jurassic times. In the Eromanga Basin, compressional structural styles associated with Late Cretaceous–Tertiary are apparent. Many of the Late Cretaceous–Tertiary structures coincide with exhumation highs in Late Cretaceous–Tertiary times. The two-layer lithospheric compression model is considered as the most complete explanation of both the uplift of areas subject to compression and crustal thickening, and of the regional uplift of areas not subject to any apparent Late Cretaceous–Tertiary compression. In the model, compression and thickening in the lower lithosphere is decoupled and laterally displaced from that in the upper crust. Thickening of the mantle lithosphere without thickening of the overlying crust can account for the initial subsidence then uplift of not inverted platform areas. The opening of the Tasman Sea and the Coral Seas can lead to stress transmission in the interior of the continent. These stresses are likely to generate uplift but cannot explain the distribution of uplift in areas not subject to compression.

Exhumation Studies in Hydrocarbon Exploration

The Cooper-Eromanga Basins of South Australia and Queensland are not at their maximum burial-depth due to Late Cretaceous–Tertiary and Late Triassic–Early Jurassic exhumation. This study reviews evidence of exhumation and palaeo-thermal history in the Cooper-Eromanga Basins based on previous apatite fission track analysis and fluid inclusion homogenization temperatures. Previous works using these techniques have tended to focus their research in the palaeo-thermal history, rather than exhumation magnitudes, indeed thermal annealing witnessed by apatite fission track analysis and associated with the recent/present high geothermal gradients precludes estimation of exhumation at the Cooper-Eromanga Basins unconformity. The relative importance of hot fluids, burial/exhumation and/or other heating processes is unclear. Nonetheless, where reported, exhumation results from apatite fission track analysis and fluid inclusion homogenization temperatures are in a broad agreement with those from compaction analysis.

Exhumation Study in the Cooper-Eromanga Basins, Australia and the Implications for Hydrocarbon Exploration

The Cooper-Eromanga Basins of South Australia and Queensland are not at their maximum burial-depth due to Late Cretaceous-Tertiary and Late Triassic-Early Jurassic exhumation. The main tool used for estimating the exhumation is the available vitrinite reflectance data. Exhumation studies using compaction analysis have also been compiled in order that exhumation is better constrained. The results suggest that Late Cretaceous-Tertiary exhumation increases eastwards from the South Australia to the Queensland sector of the basins. This study has major implications for hydrocarbon exploration. Predicted maturation of source rocks will be greater for any given geothermal history if exhumation is incorporated in maturation modeling.

Burial/exhumation histories for the Cooper–Eromanga Basins and implications for hydrocarbon exploration, Eastern Australia

ABSTRACTThe Cooper–Eromanga Basins of South Australia and Queensland are not at their maximum burial depth due to Late Cretaceous–Tertiary, and Late Triassic–Early Jurassic exhumation. Apparent exhumation (maximum burial depth–present burial depth) for the Cooper Basin has been quantified using the compaction methodology. The results show that exhumation of the Cooper Basin for the majority of the wells is greater than the exhumation of the Eromanga Basin. Using the compaction methodology, apparent exhumation of Early to Middle Triassic age Arrabury and Tinchoo Formatios has been quantified. Both units yield similar results and do not support that the Arrabury/Tinchoo boundary represents the Cooper–Eromanga boundary. Hence, the Cooper Basin is believed to have reached its maximum burial depth in Late Triassic times. Sonic log data are not available for the units overlying the Late Cretaceous Winton Formation; thus, it is not possible to date exhumation beyond the Late Cretaceous–Tertiary using the compaction methodology. Tertiary sequences as are preserved are relatively thin and separated by marked unconformities and weathered surfaces; hence, exhumation rather than sedimentation dominated the Tertiary, and in exhumed areas, maximum burial depth was attained in Late Cretaceous times. The burial/exhumation history of representative wells was synthesized using sediment decompaction and establishing porosity/depth relations for the Cooper–Eromanga units. Considering the relative significance of the major periods of exhumation in the Cooper/Eromanga Basins, three broad types of burial/exhumation histories can be distinguished. Maximum burial depth of the Cooper Basin sequence was attained before the deposition of the Eromanga Basin sequence, i.e. Late Triassic–Early Jurassic times; maximum burial depth of the Cooper and Eromanga Basin sequences attained in Late Cretaceous times; and Cooper and Eromanga Basin sequences are currently at maximum burial‐depth. Incorporation of exhumation into burial history has major implications for hydrocarbon exploration.

Constraining stress magnitudes using petroleum exploration data in the Cooper–Eromanga Basins, Australia

The magnitude of the in situ stresses in the Cooper–Eromanga Basins have been determined using an extensive petroleum exploration database from over 40 years of drilling. The magnitude of the vertical stress ( S v) was calculated based on density and velocity checkshot data in 24 wells. Upper and lower bound values of the vertical stress magnitude are approximated by S v = (14.39 × Z) 1.12 and S v = (11.67 × Z) 1.15 functions respectively (where Z is depth in km and S v is in MPa). Leak-off test data from the two basins constrain the lower bound estimate for the minimum horizontal stress ( S hmin) magnitude to 15.5 MPa/km. Closure pressures from a large number of minifrac tests indicate considerable scatter in the minimum horizontal stress magnitude, with values approaching the magnitude of the vertical stress in some areas. The magnitude of the maximum horizontal stress ( S Hmax) was constrained by the frictional limits to stress beyond which faulting occurs and by the presence of drilling-induced tensile fractures in some wells. The maximum horizontal stress magnitude can only be loosely constrained regionally using frictional limits, due to the variability of both the minimum horizontal stress and vertical stress estimates. However, the maximum horizontal stress and thus the full stress tensor can be better constrained at individual well locations, as demonstrated in Bulyeroo-1 and Dullingari North-8, where the necessary data (i.e. image logs, minifrac tests and density logs) are available. The stress magnitudes determined indicate a predominantly strike-slip fault stress regime ( S Hmax > S v > S hmin) at a depth of between 1 and 3 km in the Cooper–Eromanga Basins. However, some areas of the basin are transitional between strike-slip and reverse fault stress regimes ( S Hmax > S v ≈ S hmin). Large differential stresses in the Cooper–Eromanga Basins indicate a high upper crustal strength for the region, consistent with other intraplate regions. We propose that the in situ stress field in the Cooper–Eromanga Basins is a direct result of the complex interaction of tectonic stresses from the convergent plate boundaries surrounding the Indo-Australian plate that are transmitted into the center of the plate through a high-strength upper crust.

PRODUCTION AND DEVELOPMENT HIGHLIGHTS 2004 — OUR FUTURE IN GAS

The 2004 exploration and appraisal highlights are reviewed and awards given to companies which made significant contributions to increasing Australia’s self sufficiency. While 2004 saw no drilling in Australian frontier basins with most exploratory wells located in the seven producing basins offshore, and within only four onshore basins, overseas, smaller Australian explorers made significant discoveries or appraisals in Turkey, North America and Yemen. Twice as many onshore exploration wells were spudded compared to offshore exploration, a turn around from 2003 mostly due to increased activity in the onshore Cooper-Eromanga and Perth basins.

AUSTRALIA’S HYDROCARBON PROVINCES—WHERE WILL FUTURE PRODUCTION COME FROM?

The cumulative graph of reserves added to a basin through time is a measure of that basins’ exploration maturity. Additions of reserves through new field discovery are limited in the Bowen-Surat, Gippsland, Cooper-Eromanga and Bonaparte Basins whilst significant discoveries continue to be made in the Carnarvon Basin. The recent discoveries in the Perth Basin represent a significant new phase in the addition to reserves for this basin. Reserves growth in existing fields represents a very significant source of new crude oil reserves. All gas bearing basins including those in eastern Australia show potential for additional gas discoveries. Coal Bed Methane also represents a significant gas resource into the future.Australia’s production of crude oil has averaged 11% of the remaining reserves over the last decade. In the late 90s, the rate of production has exceeded the rate of addition to reserves and production must decline in the medium term. Medium- to long-term forecasts of future crude oil production are uncertain because of the difficulty in predicting the rate of crude oil discovery, particularly since many of the established plays in established crude oil basins appear to have little remaining potential and success rates and potential for new plays in established and frontier areas of exploration is unknown.Rates of gas production are not related to existing reserves, but rather to the dynamics of the commercial market which is strongly influenced by regional infrastructure.

A HYDROCARBON GENERATION MODEL FOR THE COOPER AND EROMANGA BASINS

The aim of the National Geoscience Mapping Accord Cooper-Eromanga Basins Project was to develop a quantitative petroleum generation model for the Cooper and Eromanga Basins by delineating basin fill, thermal history and generation potential of key stratigraphic intervals. Bio- and lithostratigraphic frameworks were developed that were uniform across state boundaries. Similarly cross-border seismic horizon maps were prepared for the C horizon (top Cadna-owie Formation), P horizon (top Patchawarra Formation) and Z horizon (base Eromanga/Cooper Basins). Derivative maps, such as isopach maps, were prepared from the seismic horizon maps.Burial geohistory plots were constructed using standard decompaction techniques, a fluctuating sea level and palaeo-waterdepths. Using terrestrial compaction and a palaeo-elevation for the Winton Formation, tectonic subsidence during the Winton Formation deposition and erosion is the same as the background Eromanga Basin trend—this differs significantly from previous studies which attributed apparently rapid deposition of the Winton Formation to basement subsidence. A dynamic topography model explains many of the features of basin history during the Cretaceous. Palaeo-temperature modelling showed a high heatflow peak from 90–85 Ma. The origin of this peak is unknown. There is also a peak over the last two–five million years.Expulsion maps were prepared for the source rock units studied. In preparing these maps the following assumptions were made:expulsion is proportional to maturity and source rock richness;maturity is proportional to peak temperature; andpeak temperature is proportional to palaeo-heatflow and palaeo-burial.The geohistory modelling involved 111 control points. The major expulsion is in the mid-Cretaceous with minor amounts in the late Tertiary. Maturity maps were prepared by draping seismic structure over maturity values at control points. Draping of maturity maps over expulsion values at the control points was used to produce expulsion maps. Hydrocarbon generation was calculated using a composite kerogen kinetic model. Volumes generated are theoretically large, up to 120 BBL m2 of kitchen area at Tirrawarra North. Maps were prepared for the Patchawarra and Toolachee Formations in the Cooper Basin and the Birkhead and Poolowanna Formations in the Eromanga Basins. In addition, maps were prepared for Tertiary expulsion. The Permian units represent the dominant source as Jurassic source rocks have only generated in the deepest parts of the Eromanga Basin.

The Australian stress map

The Australian stress map project has compiled 357 quality ranked stress orientation analyses for the Australian Continent (including New Guinea). Of these, 206 provide reliable stress orientations, approximately doubling the number from the 1992 world stress map compilation. Most new data are from borehole breakouts. Regionally, maximum horizontal stress (@) is oriented northeast-southwest from New Guinea along most of the North West Shelf, rotating to 100°N in the Carnarvon Basin. An 010°N-020°N @ orientation is observed in the Amadeus and Bowen Basins. However, in the southern half of the continent a broad east-west @H trend is observed in the Yilgarn Block, Cooper-Eromanga Basins, and from a number of isolated indicators. In the Otway and Gippsland Basins @ is oriented 130°N. The rotation of stresses along the North West Shelf and from east-west in the Yilgarn Block to north-south in the Amadeus Basin can be explained in the context of the heterogeneous plate boundary forces acting along the convergent plate boundary to the north of Australia. However, plate boundary forces can not explain the rotation of @ from east-west in the Cooper-Eromanga Basins to approximately north-south in the Amadeus Basin, which may be linked to second order influences on the stress field.The vertical stress (σv) gradient in the Bonaparte and Cooper-Eromanga Basins increases with depth, and is around 20 MPa/km at 1 000 m, attaining 23 MPa/km around 3 000 m. The Amadeus Basin displays an overburden gradient of 25 MPa/km that is little affected by depth. In situ measurements in hard rock terranes suggest a higher average overburden stress gradient of 27 MPa/km. Leak-off pressures suggest that the minimum horizontal stress (σh) is the least principal stress (60-70% of σv) in the Bonaparte and Cooper-Eromanga Basins. Hence in neither basin is the stress regime one associated with reverse faulting (where σH σh σv). Consideration of the frictional limits to faulting suggests that, if in a state of incipient faulting, the stress regime is approximately on the boundary between normal (σv σh σh) and strike-slip (σh σv σh) faulting environments in the Bonaparte Basin and strike-slip in the Cooper-Eromanga Basins. Applications of the stress data include assessing both natural and induced fluid flow directions in the subsurface. For example, hydraulic fractures induced for geothermal exploitation of hot-dry-rock in the Cooper-Eromanga Basins would tend to be vertical, and not, as previously suggested horizontal.

Regional depth-conversion of mapped seismic two-way-times in the Cooper-Eromanga Basins

Mapped seismic two-way-times to the top of the Cadna-owie and Toolachee Formations in part of Petroleum Exploration Licences 5 and 6 of the Cooper-Eromanga Basins were depth-converted using the interval velocity and velocity anomaly methods. Two types of input velocity data were used for each depth-conversion method: (i) based on mapped seismic isochrons combined with thicknesses at well locations, and (ii) based on drift-corrected checkshot/sonic log data and thicknesses at well locations. The sequence was split into three layers for the depth-conversion: surface to top of the Mackunda Formation (layer 1), top of the Mackunda Formation to top of the Cadna-owie Formation (layer 2) and top of the Cadna-owie Formation to top of the Toolachee Formation (layer 3). The interval velocity method used constant layer interval velocities as predicted by interval velocity maps. In the velocity anomaly method, regional velocity/depth functions were fitted to the input layer velocities. Anomalies with respect to these regional functions were then mapped and used in conjunction with the regional functions in order to undertake the depth-conversion. The accuracy of the depth-conversions was assessed with reference to test wells not used in the determination of the input velocity models. The 95.5% confidence limits of the error in depth-conversion for the velocity anomaly method are 7?16% closer to zero than for the interval velocity method at the top of the Cadna-owie Formation, and 21?41% closer to zero at the top of the Toolachee Formation. Hence velocity anomaly can be more accurately mapped and predicted away from the input wells than 'raw' interval velocity. There is no significant difference between the errors in depth-conversion based on seismic isochron and checkshot/sonic log input velocities. Given that the former are more widely available, and more easily determined than the latter, their use is preferred.

DEPLETION OF GAS RESERVOIRS BY MOLECULAR DIFFUSION — A CASE STUDY

Recent drilling in the southern Cooper-Eromanga basins of eastern central Australia has provided evidence to suggest that Permian gas reservoirs have been depleted by molecular diffusion.Diffusion is the process by which matter is transported along a concentration gradient, as a result of random molecular motion. It is a common and ubiquitous phenomenon in geological environments.In the Toolachee and Nappacoongee-Murteree blocks of PELs 5 and 6, channel sandstones of the Permian Patchawarra Formation are faulted or subcrop against the Murteree Horst basement high. The Lower-Middle Jurassic Hutton Sandstone was deposited directly over the exposed surface of this feature and the surrounding eroded Permo-Triassic topography. As a result, the truncated Patchawarra Formation sandstone reservoirs are in contact with the overlying Hutton Sandstone, a major fresh water aquifer within the Great Artesian Basin. There is an anomalous increase in Patchawarra Formation water resisitivity around the Murteree Horst, suggesting that fluid communication with the Hutton Sandstone has allowed ionic diffusion to reduce the salinity of the Patchawarra reservoirs.Fluid communication has existed between the Patchawarra and Hutton reservoir systems for the duration of hydrocarbon generation and migration. It is proposed that the diffusion of solution gas towards the Murteree Horst has lowered basinward Patchawarra gas concentrations below saturation point, to the extent that gas generated in nearby source areas has gone into solution rather than migrating in the gaseous phase to form accumulations. Hydrocarbon traps immediately basinward of the Patchawarra edge should contain gas only if the rate of supply from source rocks has been greater than the rate of loss by diffusion. Gas accumulations may be shielded from depletion by source areas or other accumulations which are closer to the Patchawarra edge.The diffusion model has a negative impact on the prospectivity of Permian gas targets in marginal source areas of the Cooper Basin where reservoir communication exists between potential gas reservoirs and the Great Artesian Basin aquifers. Nevertheless, the recognition of this process may be used to advantage in identifying areas where further gas exploration should be curtailed. Such action may improve the drilling success rate in the region.