Hutton Sandstone Research Articles

Integrated Geologic and Engineering Reservoir Characterization of the Hutton Sandstone, Jackson Region, Australia: ABSTRACT

An integrated geologic and engineering reservoir characterization study of the Hutton Sandstone was completed for the Jackson region, Eromanga Basin, Australia. Our approach involves four principal steps: (1) determine reservoir architecture within a high-resolution sequence stratigraphic framework, (2) investigate trends in reservoir fluid flow, (3) integrate fluid flow trends with reservoir architecture to identify fundamental reservoir heterogeneities, and (4) identify opportunities for reserve growth. Contrary to the existing perception, the Hutton Sandstone, a continental-scale bed-load fluvial system, does not behave as a large, homogeneous tank in which pistonlike displacement of produced oil occurs unimpeded by vertical migration of the aquifer. The sequence stratigraphic analysis identified numerous thin but widespread shale units, deposited during lacustrine flooding events that periodically interrupted episodes of coarse clastic Hutton deposition. These shales represent chronostratigraphically significant surfaces. More importantly, the trends established in reservoir fluid flow from monitoring aquifer encroachment, production response to water shut-off workovers, and differential depletion in Repeat Formation Tests indicate that these shale units act as efficient barriers to vertical fluid flow. Erosion of the upper part of the Hutton reservoir by the younger Birkhead mixed-load fluvial system caused further stratigraphic complexity and introduced additional barriers to vertical and lateral migration ofmore » mobile oil and aquifer encroachment. This integrated characterization targeted strategic infill and step-out drilling and recompletion candidates.« less

The integrated use of 3D seismic data, well information and seismic forward modelling – Lake Hope field area

The Lake Hope 3D survey was acquired in 1992 and covers five producing oil fields in the Lake Hope Block of the South Australian sector of the Cooper/Eromanga Basins. A total of 38 wells have been drilled within the survey limits, of which 24 are currently producing from eight different reservoir levels. The bulk of the production comes from the Early Cretaceous/Namur Sandstone and Jurassic Birkhead Formation, Hutton Sandstone and Poolowanna Formation. The reservoirs occur between 1.2 and 1.5 seconds two way time (1300?1800 m below MSL). The excellent quality of the Lake Hope 3D seismic data and the large number of wells in the area allowed extensive use of seismic forward modelling. The object was to better understand the quality and distribution of the various reservoirs in the area. Integration of well data, seismic amplitude information and production history made it possible to define the presence and extent of producing Birkhead Formation sands. Two dimensional forward modelling was utilised to interactively alter well-logs and observe the corresponding change in seismic response. By using these procedures and horizon slices from the 3D seismic volume it was possible to prognose additional areas where similar sands are likely to be present. The Hutton Sandstone reservoir contains over one quarter of the oil within the Lake Hope Fields and is also a very productive reservoir elsewhere in the Eromanga Basin. The Birkhead Formation is the top seal to this unit and the Birkhead/Hutton Interface marks the change from the high energy braided stream environment of the Hutton Sandstone to the lacustrine/low energy fluvial environment of the Birkhead Formation. This interface varies from an abrupt change to a transitional change over a 10 metre interval. Reservoir quality and pay thickness are heavily dependent on the nature of this transition. Well information was correlated with observed seismic response to establish the character of the Birkhead/Hutton Interface within the area of the 3D seismic survey. The above studies demonstrate the importance of integrating geological information, well production history and observed variations in seismic response to fully utilise 3D seismic data.

SEDIMENTARY PROVENANCE STUDIES IN AUSTRALIAN BASINS USING NEODYMIUM MODEL AGES

An understanding of the tinting of basin evolution is fundamental to the development of successful play concepts. The Sm-Nd geochronometer can be used to determine quantitatively the `average' age at which segments of continental crust have been extracted from the earth's mantle. Variations in Nd model ages within sedimentary rock sequences indicate changes in sedimentary provenance over time and provide a potential correlation tool.In the Eromanga Basin, there is a distinct lithological contrast between the main reservoir unit, the Jurassic Hutton Sandstone, and the overlying Birkhead Formation. The quartz-rich Hutton Sandstone is characterised by relatively old Nd model ages, generally within the range 1.3–1.5 Ga. In contrast the lithic-rich Birkhead Formation has much younger model ages, generally Neodymium model ages measured in mudstones within the Flag Sandstone from the Harriet Field in the Barrow Sub-basin of the North West Shelf, range from 2.1–2.5 Ga. The old ages are consistent with the sediments being derived from the Archaean shield areas and the younger Proterozoic complexes of Western Australia. Tentative correlations based on model ages between mudstone units from two wells are consistent with correlations based on heavy mineral suites.Neodymium model ages have application to correlation at both regional and local scales within basins. Reliable information can be obtained on both sandstones and mudstones on samples as small 50 g. Potentially they can provide important quantitative information complementary to that derived from more conventional approaches.

Membrane seal and tertiary migration pathways in the Bodalla South oilfield, Eromanga Basin, Australia

The Middle Jurassic Hutton Sandstone oil accumulation at the Bodalla South oilfield in the Eromanga Basin, Australia is primarily a structural trap with stratigraphic control. In common with many others in this basin it does not appear to be full to the structural spill point. Analysis of mercury injection curves has revealed that the caprock of the Hutton Sandstone (i.e. the Birkhead Formation, which is predominantly a lithic sandstone) is a membrane type seal. The calculated maximum size of oil column that will accumulate beneath this caprock is 12.64 m and the maximum oil column encountered to date is 11.25 m. There is no waste zone above the Hutton Sandstone reservoir at Bodalla South.

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.

Tertiary uplift estimation from velocity data in the Eromanga Basin

The Tertiary uplift of the Eromanga Basin over PELs 5&6 (SA) and ATP 259P (Queensland), has significantly complicated depth-porosity relationships in the important oil-bearing Hutton Sandstone, as well as altering migration pathways. Because seismic reflection data in the Eromanga Basin are focused on the lower part of the succession, they are not suitable for imaging and mapping the Tertiary unconformities. In this study, an estimate of the magnitude of Tertiary uplift across the acreage has been made by cross-plotting interval velocity and depth for the lithologically homogenous Cretaceous marine shales near the top of the succession. Deviations from a depth-velocity baseline fitted to data from the basin depocentres have enabled quantification of uplift. The uplift estimates have been used to produce pre-uplift depth structure maps which can be used to map pre-uplift hydrocarbon migration pathways. Maximum burial depth can also be calculated, providing a better predictor of porosity in the Hutton Sandstone than present burial depth.

The application of a joint MT CSAMT survey to oil exploration

A survey was carried out over the Tallyabra anticline in the Eromanga Basin Queensland, using both controlled source and passive magnetotelluric techniques to investigate the structure in the top 2 km. The results from the controlled source system were very encouraging and, using the resistivity log from the well Kenmore 7 as a control, the top of the oil bearing Hutton Sandstone was resolved at a depth of about 1400 m. The magnetotelluric results were consistent with those from the controlled source, but the data accuracy was so much lower that in these circumstances they added little information.

LITHOSTRATIGRAPHY OF THE LOWER EROMANGA BASIN SEQUENCE IN SOUTH WEST QUEENSLAND

Five fully-cored and wire-line logged stratigraphic bores have been drilled by the Queensland Department of Mines, relatively close to producing oil fields in the Eromanga Basin, south-west Queensland. Correlations between the stratigraphic bores and petroleum wells have established lithologic control in an area where lithostratigraphy is interpreted mainly from wire-line logs. The Eromanga Basin sequence below the Wallumbilla Formation has been investigated, and a uniform lithostratigraphic nomenclature has been applied; in the past, an inconsistent nomenclature system was applied in different petroleum wells.Accumulation of the Eromanga Basin sequence was initiated in the early Jurassic by major epeirogenic downwarping; in the investigation area the pre-Eromanga Basin surface consists mainly of rocks comprising the Thargomindah Shelf and the Cooper Basin. The lower Eromanga Basin sequence in the area onlaps the Thargomindah Shelf and thickens relatively uniformly to the north-west. The sequence comprises mainly Jurassic/Cretaceous terrestrial units in which vertical and lateral distribution is predominantly facies-controlled. These are uniformly overlain by the mainly paralic Cadna-owie Formation, signalling the initiation of a major Cretaceous transgression over the basin.The terrestrial sequence over most of the area comprises alternating coarser and finer-grained sedimentary rocks, reflecting major cyclical changes in the energy of the depositional environment. The Hutton Sandstone, Adori Sandstone and 'Namur Sandstone Member' of the Hooray Sandstone comprise mainly sandstone, and reflect high energy fluvial depositional environments. Lower energy fluvial and lacustrine conditions are reflected by the finer-grained sandstone, siltstone and mudstone of the Birkhead and Westbourne Formations, and 'Murta Member' of the Hooray Sandstone. Similar minor cycles are represented in the 'basal Jurassic' unit. The Algebuckina Sandstone, recognised only in the far south-west of the investigation area, comprises mainly fluvial sandstones.

THE HUTTON SANDSTONE-BIRKHEAD FORMATION TRANSITION, ATP 269P(1), EROMANGA BASIN

The Hutton Sandstone and Birkhead Formation are the reservoir and seal, respectively, for most ofthe oil discovered in the Eromanga Basin. The traps are generally simple anticlinal closures; however stratigraphic complexities are common. Development well failures in ATP 269P(1) are commonly caused by stratigraphic variations at the Hutton-Birkhead transition.In ATP 269P(1) two distinct sandstone compositions are present over the Hutton-Birkhead transition, and are end-members of a spectrum of compositions. The first end-member consists of porous and permeable quartzose sandstone which is typical of the Hutton Sandstone. The second end-member is a lithic labile sandstone which is generally not of reservoir quality and is typical of the Birkhead Formation. Mixed and interbedded varieties are common, and are included in the Birkhead. The sandstone composition indicates that the quartzose 'Hutton' variety was derived from a stable, plutonic-metamorphic craton, whereas the lithic 'Birkhead' variety was sourced from a tectonically mobile belt, consisting of acid to intermediate volcanics, regional metamorphics, and metasediments.The Bodalla South Field displays a gradational change from quartzose sandstone in the Hutton to mixed and interbedded varieties in the Birkhead. Substantial range in reservoir quality is seen in the field and is related to sandstone composition and to a fluviodeltaic environment of deposition. In the Kenmore Field lithic sandstone, deposited in channels eroded into the quartzose sediments, provides stratigraphic enhancement of the structural closure.Similar relationships are seen in the Jackson-Naccowlah area and the Surat Basin and are linked to a change from a single provenance during deposition of the Hutton to a dual provenance during deposition of the Birkhead. This change was caused by increased activity in a mid-Jurassic arc system off the present Queensland coast and has important implications for petroleum exploration in the Eromanga and Surat Basins.

SOUTH-WEST QUEENSLAND GAS — A RESOURCE FOR THE FUTURE

Natural gas has been discovered in 22 fields in the Central Eromanga and Cooper Basins of southwestern Queensland in the area comprised by ATP 259P. Proved, probable and possible reserves in excess of 36 × 109 m3 (1.27 TCF) are located in four discrete structural provinces. Fluvial sandstones of the Early Permian Patchawarra Formation and Late Permian Toolachee Formation contain the majority of the reserves. Minor amounts of gas are reservoired in the Early Permian Epsilon Formation, the Early-Middle Triassic Nappamerri Formation and the Early Jurassic Hutton Sandstone and Birkhead Formation. Considerable gas-liquids reserves are also found in these reservoirs.Existing reserves are located primarily in structural traps although lithofacies variations are widely recognised, particularly in the Patchawarra Formation, indicating both new play opportunities and difficulties in assessing the undiscovered gas potential of the permit. Additional gas potential is identified in flank areas of the more prominent structural axes such as the Jackson-Wackett-Innamincka Trend in fault-bounded, pinchout and sub-unconformity trapping configurations.More than 200 prospects and leads are identified with the potential to entrap approximately 51 × 109 m3 (1.80 TCF) of gas on an unrisked basis. When combined with reserves from established fields, the ultimate potential of the ATP is assessed as 87 × 109 m3 (8.10 TCF).Despite the very high success rate of previous exploration and appraisal programs, the ultimate gas potential of the Queensland portion of both the Cooper and Eromanga Basins has been only partially addressed. Exploration and appraisal programs providing future additions to proved and probable reserves are considered low risk and are dependent upon an agreement with the Queensland government that would enable the ATP holders to produce and sell gas interstate.

THE TINTABURRA OILFIELD

The Tintaburra oilfield, discovered in December 1983 with the drilling of Tintaburra 1, is situated within Petroleum Lease 29 (previously within Authority to Prospect 299P Part 2) on the southeast margin of the Eromanga Basin, Queensland.Tintaburra 1 recorded the first flow of oil from the Cretaceous Wyandra Sandstone Member of the Cadnaowie Formation in the Eromanga Basin and established the presence of oil columns in the Murta Member and Hutton Sandstone. The Hutton Sandstone produced 1750 barrels of 44° API gravity oil per day on drill stem test.The results of six successful appraisal wells show the field to be a simple structural accumulation at the top Hutton level. The top Hutton accumulation is believed to be full to fault-independent closure. The hydrocarbons are trapped on the western upthrown side of the Tertiary reverse faulted Tintaburra Anticline. Approximately 80 per cent of reserves are reservoired in the top Hutton.The discovery extended the productive limits of the Eromanga Basin 100 km to the north and east from theJackson oilfield, and highlighted the potential of Tertiary structures, previously thought by many to be non-prospective.Channelling at the 'C' horizon (base Wallumbilla Formation) extends across the southern part of the field, complicating depth mapping by virtue of the large velocity contrasts between channel and host sediments. Velocity and raypath distortion below the channel are major geophysical complexities that have been successfully overcome, allowing more accurate location of appraisal wells.Appraisal drilling, combined with high quality seismic data, has identified the nature of the Early Cretaceous submarine channelling, and has identified new channel-related plays. 'C' horizon channelling imparts a strong stratigraphic component to the Murta and Wyandra accumulations. Integrated core and log studies indicate that every reservoir within fault-independent closure, and overlain by a laterally continuous effective seal, contains oil. Facies variations within the top Hutton/base Birkhead interval have important implications for trap integrity and are generally not resolvable seismically.The high API gravity, low pour point Wyandra and Murta crudes are distinct from the waxy, paraffinic Hutton crudes, and geochemical analysis of the oils and source rocks indicates a probable Eromanga-sequence origin for all the crudes.

POROSITY AND PERMEABILITY OF RESERVOIRS AND CAPROCKS IN THE EROMANGA BASIN, SOUTH AUSTRALIA

When effective porosity and permeability are measured at simulated overburden pressure, and grain size variation is taken into account, two distinct relationships are evident for Eromanga Basin reservoirs. Reservoirs in the Hutton Sandstone and Namur Sandstone Member behave such that significant porosity reduction can be sustained with retention of high permeability, whereas permeability of reservoirs in the Birkhead Formation and Murta Member is critically dependent on slight porosity variations. Logging tool responses are compared with core-derived data to show in particular the effects of grain size and clay content on the gamma ray, sonic, and density tools, where clay content is assessed from cation exchange capacity measurements. Sonic and density crossplots, constructed to provide comparison with a water-saturated 'reference' reservoir, are advantageous in comparing measured effective porosity from core plugs at overburden pressure with porosity calculated from logs. Gamma ray and sonic log responses of the Murta Member in the Murteree Horst area are clearly distinct from those of all other reservoirs, perhaps partly due to differences in mineralogy and shallower depth of burial compared with other formations.

HYDROCARBON GENERATION, MIGRATION AND ENTRAPMENT IN THE JACKSON-NACCOWLAH AREA, ATP 259P, SOUTHWESTERN QUEENSLAND

The northern part of the Naccowlah Block, situated in the southeastern part of the Authority to Prospect 259P in southwestern Queensland, is a major Eromanga Basin hydrocarbon province. The Hutton Sandstone is the main reservoir but hydrocarbons have been encountered at several levels within the Jurassic-Cretaceous sequence. In contrast, the underlying Cooper Basin sequence is generally unproductive in the Naccowlah Block although gas was discovered in the Permian at Naccowlah South 1. Oil and gas discoveries within the Eromanga Basin sequence are confined to the Naccowlah-Jackson Trend. This trend forms a prominent high separating the deep Nappamerri Trough from the shallower, more stable northern part of the Cooper Basin.The Murta Member is mature for initial oil generation along the Naccowlah-Jackson Trend and has sourced the small oil accumulations within this unit and the underlying Namur Sandstone Member. The Birkhead Formation is a good source unit in this area with lesser oil source potential also evident in the Westbourne Formation and 'basal Jurassic'. Source quality and maturation considerations imply that much of the oil discovered in Jurassic reservoirs along the Naccowlah-Jackson Trend was generated from more mature Jurassic source beds in the Nappamerri Trough area to the southwest. Maturation modelling of this deeper section suggests that hydrocarbon generation from Jurassic source units commenced in the Early Tertiary. Significant oil generation and migration has therefore occurred since the period of major structural development of the Naccowlah-Jackson Trend in the Early Tertiary. This trend, however, has long been a major focus for hydrocarbon migration paths out of the Nappamerri Trough as a result of intermittent structuring during the Mesozoic. Gas reservoired in Jurassic sandstones at Chookoo has been generated from more mature Jurassic source rocks in the deeper parts of the Nappamerri Trough.Permian sediments in the Nappamerri Trough area are overmature for oil generation and are gas prone. Gas generated in this area has charged the lean Permian gas Field at Naccowlah South, along the Wackett-Naccowlah- Jackson Trend. North of this trend Permian source rocks are mainly gas prone but more favourable levels of maturity allow the accumulation of some gas liquids and oil. However, geological and geochemical evidence suggests that Permian sediments did not source the oil found in Jurassic-Cretaceous reservoirs in the Jackson- Naccowlah area.

CARPENTARIA BASIN: A REGIONAL ANALYSIS WITH REFERENCE TO HYDROCARBON POTENTIAL

The Carpentaria Basin is an epeirogenic intracratonic downwarping which formed during the Mesozoic. It is the northernmost of three main Jurassic-Cretaceous downwarps forming the Great Australian Artesian Basin. The basin is filled with clastic sediments, predominantly derived from Precambrian ridges on the flanks of the basin, which thicken gradually from the basin margins towards the depocentre.The Carpentaria Basin is analogous to the Eromanga Basin immediately to the south, and several rock units were deposited contemporaneously in both basins so that they can be mapped in the subsurface from one basin to the next. There is no change in sedimentary style or lithology.The character of the Base Mesozoic Unconformity, over which the Carpentaria Basin was deposited, changes abruptly from east to west. East of a point approximately coincident with the Queensland-Northern Territory border the unconformity surface is flat and featureless but to the west it becomes very rugged and irregular. This rugged horizon is believed to reflect either ancient karst topography or extensive reefal build-up equivalent to dolomite intersected in Burketown 1. Based on correlations with the McArthur and Georgina Basins it is probably Cambrian or Proterozoic in age. These rocks are known elsewhere to be porous and permeable.The unconformity shelves to the west towards Groote Island and the Northern Territory mainland and sediments of the Carpentaria Basin onlap a shallowing ancient landscape. The western boundary of the basin believed to be prospective for hydrocarbons is taken as the limit of deposition of the Cretaceous Gilbert River Formation.Lithologies and the existence of aquifers in the onshore Carpentaria Basin indicate that suitable reservoirs are present. Sandstones in the Cretaceous Gilbert River Formation, the Jurassic Eulo Queen Group and the Hutton Sandstone have the best reservoir potential. The Gilbert River Formation is the primary objective because it was extensively deposited throughout the basin, whereas Jurassic sandstones are restricted to topographic lows.The Gilbert River Formation is sourced and sealed by shales of the Wallumbilla Formation. Onshore this formation is too shallow to be mature but seismic indicates that offshore it is sufficiently deeply buried to be producing and expelling hydrocarbons.The hydrocarbon prospects of the Carpentaria Basin have in the past been considered low because the Mesozoic sequence onshore is thin and even offshore the total thickness of Mesozic and Cainozoic sediments is only about 1760 m at its maximum. This judgement ignored the fact that, although no economic hydrocarbon discoveries have been recorded from the Carpentaria Basin and/or the underlying Palaeozoic Basins, several shows have been reported. Shows reported in onshore wells suggest hydrocarbon generation within the basin. Geochemical and palynological studies carried out on samples from onshore wells and bores indicate the basal Mesozoic sequence is within geochemical Zone II, where the actual generation of hydrocarbons occurs but where significant mobilization and effective oil expulsion do not take place. These data suggest the deeper offshore portion of the basin should be within the oil window.

GEOLOGY OF THE JACKSON OIL FIELD

The Jackson oil field was discovered late in 1981 with the drilling of Jackson 1, which was programmed as an exploration well designed to test the Jurassic-Cretaceous Eromanga Basin sequence and the Permian Cooper Basin sequence, if present. The well tested oil from three formations.The first test to produce oil was carried out across a sand in the Early Cretaceous Murta Member of the Mooga Formation. The zone produced 47° API gravity oil at the rate of 338 barrels (53.7 kilolitres) of oil per day. This was followed by two tests which produced 41° API gravity oil at the rates of 188 and 1165 barrels (29.9 and 185.2 kilolitres) per day respectively from thin sands in the Late Jurassic Westbourne Formation. As a fitting conclusion, the well intersected a 100ft (30 m) oil-saturated section in the Jurassic Hutton Sandstone which on testing flowed 41° API gravity oil at a maximum rate of 2616 barrels (415.9 kilolitres) per day.Four appraisal wells subsequently drilled in the Jackson Field confirmed the initial belief that development of the field was a viable proposition.Compared to the Hutton and Westbourne accumulations, the size of the Murta accumulation is relatively insignificant. The accumulation in the Murta is primarily controlled by structure. On the other hand, the Westbourne accumulation appears to have a strong component of stratigraphic control. In the Hutton accumulation, there is a fair amount of variation in the geometry of the sand bodies at the top of the reservoirs. The accumulation is, however, dominantly controlled by structure.

SEISMIC INVESTIGATION OF THE MERRIMELIA FIELD

The Merrimelia oil and gas field, 40 km north of Moomba in SA, is located on the central dome of the Gidgealpa-Merrimelia-Innamincka Trend within the Cooper/Eromanga Basins.Geophysical studies have been instrumental in the investigation of the field since the discovery of commercial Permo-Triassic gas at Merrimelia- 5 in 1970 based on the results of the Merrimelia Seismic Survey. Subsequent seismic recorded during the 1980 Karawinnie Survey resulted in the location of Merrimelia-6 which, in 1981, discovered commercial oil in the Jurassic Namur Member and Hutton Sandstone, and Triassic gas, previously unknown.To allow accurate mapping of the field's oil reserves, a detailed half kilometre grid was recorded during the 1981 Namooka Seismic Survey. The programme comprised 110 km of 24-fold Vibro- seis coverage. Interpretation of the seismic and well data has resulted in recognition of a complex stratigraphic component superimposed on the Merrimelia structural high. Considerable detailed seismic work has contributed to a better understanding of the seismic reflection sequence and hence improved geophysical prognoses.Seismic studies of the Merrimelia field are continuing as further discoveries, most recently oil in the Triassic at Merrimelia-12 and gas in the Tirrawarra Sandstone at Merrimelia-13, are made in the field area.

THE HUTTON SANDSTONE - TWO SEPARATE RESERVOIRS IN THE EROMANGA BASIN, SOUTH AUSTRALIA

The Hutton Sandstone in the South Australian portion of the Eromanga Basin consists of two units, one Early to Middle Jurassic, the other Middle to Late Jurassic in age. The younger unit may conformably overlie the older in areas of persistent subsidence but either may be thin or absent in areas of complex structure.Siliceous and calcareous authigenic cements at the top of the older unit and within the younger unit indicate surficial weathering in a warm arid to humid climate, supported independently by palaeofloral and faunal evidence. Duricrusts of Middle to Late Jurassic age have been recorded in outcrop from the southwest Eromanga Basin margin and the Surat Basin region.Both units have disconformity trap potential and the younger unit has additional poor to excellent stratigraphic trap potential. Exploration strategies will be enhanced by mapping each unit as a separate reservoir and by recognizing the downflank stratigraphic trap potential of the younger unit.

Oil and Gas Developments in Australia in 1981

During 1981, exploration and development drilling continued its trend upward from 1979 and 1980. In 1981, exploration drilling reached its highest level in the past 16 years of Australian oil and gas activity. The exploratory well record was set in 1965 when 157 wells were drilled. The states with the greater amounts of activity in 1981, as in 1980, were Queensland, South Australia, and Western Australia. In Australia overall, there were 125 exploration wells and 107 development wells drilled and/or commenced in 1981. Significant onshore oil discoveries were made in Queensland, South Australia, and Western Australia. The presence of commercial oil in apparently significant quantities in Cretaceous to Jurassic rocks of the Eromanga basin in South Australia and Queensland was greatly extended areally by discoveries at Merimellia 6, South Australia (2,738 BOPD), and at Jackson 1, Queensland (350 BOPD from the Cretaceous Murta Member of the Mooga Formation; 1,165 BOPD from the lower part of the Jurassic Westbourne Formation; and 2,616 BOPD from the top of the Jurassic Hutton Sandstone). There is perhaps up to 25,000 mi2 in the relatively unexplored Eromanga basin where Mesozoic oil might occur. In Western Australia, one of the more important geologic discoveries to occur onshore was the flow of oil (906 BOPD) from Devonian limestone at Blina 1 in the northeast part of the Canning basin. Geophysical work in all categories increased in Australia in 1981 relative to 1980 with nearly twice as much onshore seismic work being completed in 1981. Gravity and magnetic surveys showed a very marked increase also. Natural gas production increased 9.1% in 1981 relative to 1980 to 11,647.48 million m3. Oil production in 1981 increased 6.8% relative to 1980, or by 1,456,510 m3 to 22,773,323 m3 for an average daily production of about 392,500 bbl.

CUTTAPIRRIE 1—AN OIL DISCOVERY IN THE EARLY JURASSIC OF THE EROMANGA BASIN

Cuttapirrie 1 discovered a significant oil accumulation at a depth of 8 016 ft in the Early Jurassic Hutton Sandstone of the Eromanga Basin. In addition, it discovered a small gas accumulation at 9 386 ft in the underlying Permo-Triassic Cooper Basin of South Australia. The well was 210 km from the nearest Jurassic oil field and 30 km from the nearest gas field when it was drilled.

THE GEOLOGICAL EVOLUTION OF THE SOUTHERN TAROOM TROUGH AND THE OVERLYING SURAT BASIN

Isopach, structure contour, and palaeo-geological maps illustrate the geological development of the southern Taroom Trough and the lower part of the Surat Basin sequence.The meridional southern Taroom Trough, 50,000 km2 in area, is a southerly subsurface extension of the outcropping Bowen Basin. It is fault-bounded to the east and plunges northward. The maximum thickness of sedimentary fill increases northward from less than 400 m to 10,000 m, and consists of Lower Permian marine sediments, Upper Permian coal measures, Lower Triassic redbeds, and Middle Triassic stream sediments. The trough's present western margin is depositional, but the faulted eastern margin started to form in the Late Permian in the south and in the Early Triassic in the north; movement ceased in the Early Triassic in the south and in the Late Triassic in the north. Tectonic movements did not recur until Late Jurassic time.Late Triassic erosion preceded deposition of Surat Basin sediments. These sediments extended over ever wider areas, even the basal sands spreading far beyond the Taroom Trough. The fully-developed Surat Basin is 300,000 km2 in area, and contains up to 2500 m of dominantly continental Jurassic sediments and dominantly marine Lower Cretaceous sediments. Lower Jurassic stream sediments (the main petroleum producers of the basin) are thickest and coarsest above the Taroom Trough, suggesting steady subsidence and compaction of the trough sediments.By the Late Jurassic this compaction had virtually ceased, and epeirogenic uplift had given the basin its present shape, with the Mimosa Syncline (above the Taroom Trough) and the south-westerly-trending Dirranbandi Syncline (above a basement depression) being major structural features.Petroleum, which is probably derived from both Permian and Jurassic sources, is most abundant in the Lower Jurassic sandstone on either side of the Mimosa Syncline. Some aspects of the migration and trapping of Permian petroleum are discussed, and it is suggested that the Lower Jurassic Hutton Sandstone in the virtually unexplored Bollon area could be prospective.