Muderong Shale Research Articles

THE ORIGIN AND INFLUENCE OF OVERPRESSURE WITH REFERENCE TO THE NORTH WEST SHELF, AUSTRALIA

The dominant cause of overpressure in basins is rapid loading of fine-grained sediments in which incomplete dewatering leads to additional overburden load being supported partly by the pore fluids. The principal controls on the magnitude of overpressure created are permeability and compressibility of the fine-grained rocks, coupled with the loading or sedimentation rate. High magnitude overpressure requires rapid sedimentation and/or evolution of sediment permeability to nanoDarcy values at shallow depth. By contrast, most fluid expansion mechanisms can be shown to be ineffective at generating large magnitude overpressure at realistic basin conditions. Only gas generation (either directly from kerogen or by oil to gas cracking) has the potential to create large magnitude overpressure, and only if the connected reservoir volume is very restricted.The origin of overpressure in the North West Shelf, especially the Northern Carnarvon Basin has previously been suggested to be due to petroleum generation, principally because the top of overpressure is coincident with, or lies below, the hydrocarbon generation window. To achieve high magnitude overpressure by this mechanism requires large volumes of gas generative source rocks connected to reservoirs of extremely limited extent. The volume of reservoir rocks in the basins is relatively high, and gas generation appears to be only a secondary mechanism. The most likely origin of overpressure is burial of the Jurassic and Lower Cretaceous group sediments (including the Muderong Shale) with early development of the Muderong Shale as a pressure seal. Lateral stress cannot be discounted as an additional mechanism of overpressure generation. However, lateral strain appears to be significantly less than vertical strain.Overpressure has the potential to influence the petroleum system in the North West Shelf if there has been high magnitude overpressure for prolonged periods of geological time. Normally pressured units today may have had a history of overpressure in the geological past. Reservoir quality can be enhanced by overpressure, but trap seal integrity either strengthened or weakened by overpressure. Timing of maturation and migration of hydrocarbon can also be affected.

BARROW ISLAND OIL FIELD

The Barrow Island Field in the Barrow Sub-basin of the Carnarvon Basin was discovered in 1964 by West Australian Petroleum Pty Limited. It is the largest oil field in Western Australia. Appraisal drilling has defined in-place oil of 200 GL (1,250 MMBBL) and in-place gas of 16.5 Gm3 (580 BCF) primarily in the Lower Cretaceous Windalia Sand Member of the Muderong Shale and in- place gas of 14.5 Gm3 (515 BCF) in Middle Jurassic Biggada Formation. Additional hydrocarbon reservoirs have been discovered, including oil and gas in the Upper Jurassic Dupuy Formation, the Lower Cretaceous Malouet Formation, Flacourt Formation and Tunney Member, Mardie Greensand Member and M zones of the Muderong Shale and in the Upper Cretaceous Gearle Siltstone. Approximately 850 wells have been drilled to appraise and develop these accumulations, and to provide water source and water injection wells to enhance recovery. Production commenced in December 1966, with the first shipment of oil in April 1967. Although numerous hydrocarbon reservoirs have been developed, 95% of the 44 GL (278 MMBBL) of produced oil has been from the Windalia Sand.Structural development of the Barrow Island anticline occurred initially during the Middle Jurassic and continued intermittently during the Cretaceous and Tertiary. Initial charging of the Dupuy and Malouet formations with oil from the Upper Jurassic Dingo Claystone occurred in the Early Cretaceous prior to the development of the shallower closures. Periodic wrench- related movement on the Barrow Fault during the Early to Late Cretaceous produced closures at the Lower Cretaceous reservoirs and provided a catalyst for oil migration and charging of these closures. Significant amounts of an extremely biodegraded component, and several less biodegraded phases are present in the oil in the Windalia Sand, indicating several phases of oil charging of the Barrow structure from Middle and Upper Jurassic sediments. In the Tertiary, gas sourced from Triassic and Jurassic sediments migrated into the Barrow structure via a dilated Barrow Fault, charged the Middle Jurassic Biggada Formation and displaced some of the oil in the Lower Cretaceous reservoirs.

THE PERSEUS FIELD, NORTH WEST SHELF, AUSTRALIA: A GIANT GAS ACCUMULATION IN A COMPLEX STRUCTURAL/STRATIGRAPHIC TRAP

The Perseus Field contains reported expectation (proven plus probable) dry gas and condensate reserves of 6.48 TCF (183 × 109 m3) and 165.7 MMBBL (26.3 × 106 m3), respectively, in a complex structural/stratigraphic trap. Gas is predominantly reservoired in Bathonian shallow marine sandstones of the Legendre Formation which subcrop the Upper Jurassic-Lower Cretaceous 'Main Unconformity' in a graben separating the Goodwyn and North Rankin horsts. The Lower Cretaceous Muderong Shale forms the main regional top seal. The Lower-Middle Jurassic Athol Formation forms the seat seal for the Perseus trap and subcrops the Main Unconformity northwest of North Rankin. The maximum gross gas column for the field is approximately 360 m. The Athol Formation and underlying Murat Siltstone also form the topseal for the small Searipple Field, which underlies Perseus.The Perseus trap is dip-closed to the northwest. A steep fault scarp forms the southern margin of the trap. Trap integrity is dependent upon fault seal along the western flank of the field, where the reservoir section is juxtaposed against Athol Formation claystones in a long narrow fault block downthrown from the Goodwyn block. At the southwestern corner of the field this fault block is absent and the Perseus reservoir is juxtaposed against Triassic reservoir section in the Goodwyn block.The NRA22 well, drilled from the North Rankin A platform, has been producing gas from the Perseus Field since mid-1991. Reservoir pressure measurements and production history data have been of immense value in the exploration and appraisal of this field, both in driving further drilling and in understanding the results. Integration of geoscientific and engineering data and expertise within a multi-disciplinary team was essential for the efficient appraisal and evaluation of the field.

PETROLEUM PLAY ELEMENT PREDICTION FOR THE CRETACEOUS-TERTIARY BASIN PHASE, NORTHERN CARNARVON BASIN

A regional tectono-stratigraphic framework has been developed for the Cretaceous and Tertiary section in the Northern Carnarvon Basin. This framework places traditional observations in a new context and provides a predictive tool for determining the temporal occurrence and spatial distribution of the lithofacies play elements, that iss reservoir, source and seal.Two new, potential petroleum systems have been identified within the Barremian Muderong Shale and Albian Gearle Siltstone. These potential source rocks could be mature or maturing along a trend that parallels the Alpha Arch and Rankin Platform, and within the Exinouth Sub-basin.A favourable combination of reservoir and seal can be predicted for the early regressive part of the Creta- ceous-Tertiary basin phase (Campanian-Palaeocene). Lowstand and transgressive (within incised valleys) reservoirs are more likely to be isolated and encased in sealing shales, similar to lowstand reservoir facies deposited during the transgressive part of the basin phase, for example, the M. australis sand play.The basin analysis revealed the important role played by pre-existing Proterozoic-Palaeozoic lineaments during extension, and the subsequent impact on play elements, in particular, the distribution of reservoir, fluid migration, and trap development. During extension, the north-trending lineaments influenced the compart mentalisation of the Northern Carnarvon Basin into discrete depocentres. Relay ramp-style accommodation zones developed, linking the sub-basins, and acting as pathways for sediment input into the depocentres and, later in the basin's history, as probable hydrocarbon migration pathways. The relay accommodation zones are a dynamic part of the basin architecture, acting as a focal point for response to intraplate stresses and the creation, modification and destruction of traps and migration pathways.

WANDOO—A NEW TREND

In June 1991 a flow of 4 560 barrels of 19° API oil per day, from a depth of 600 m, heralded the discovery of a new hydrocarbon trend along the eastern margin of the Dampier Sub-basin on the North West Shelf of Australia. Wandoo–1 recovered oil and gas from lower Cretaceous sands associated with the M.australis dinoflagellate zone (Barremian), and gas from lower Jurassic Aalenian sands.The main reservoir at Wandoo is the M. australis Sandstone Member of the Muderong Shale. This is interpreted to be a shelfal shoal sand deposited in a minor regression phase during the regional transgression of the Muderong Shale. This reservoir is split into two main lithotypes, a glauconitic subarkose to subarenite, and an overlying greensand. Oil and gas have been recovered from both units, which are considered contiguous for reservoir definition. General reservoir parameters are exceptional. Since the initial discovery a 3D seismic survey has been acquired and appraisal drilling has proven approximately 250 MMSTBOIP.The unusual features of the field necessitated innovative exploration techniques and the need for a strong appraisal program. These techniques included a six streamer, high resolution, three dimensional seismic survey and its associated processing; development of methods to recover and preserve core in extremely unconsolidated sediments; use of non destructive core analysis methods such as nuclear magnetic resonance; and petrophysical analysis that incorporates the resistivity suppression problems of glauconite. Without core a very pessimistic view would have been taken of the M. australis Sandstone reservoir.The Wandoo discovery is on an exciting new trend previously overlooked due to the shallowness of reservoirs, lack of locally recognised source rocks and the dominance of other oil and gas trends in the Dampier Sub-basin and Barrow Sub-basin to the south.

THE DEVELOPMENT GEOLOGY OF THE TUBRIDGI GAS FIELD

The Tubridgi Gas Field is located in the south of the Barrow Sub-basin, onshore in the Carnarvon Basin, Western Australia. The accumulation was discovered by Pan Pacific Petroleum NL in June 1981 with the drilling of the Tubridgi-1 well. Subsequent to Tubridgi-1, eight appraisal wells have been drilled, six of which were successful. The latest wells, Tubridgi-7 and-8, drilled in September 1990 by current operator Doral Resources NL, have enabled geological and petrophysical models for the field to be refined. These models were utilised for reserve determinations which were used to negotiate gas supply contracts and secure project financing to ensure the fields successful commercial development. Tubridgi gas is trapped within a broad, low relief, northeast-trending anticlinal closure. Reservoirs for the accumulation are the Middle to Upper Triassic Mungaroo Formation, Upper Cretaceous Flacourt Formation of the Barrow Group and Birdrong Sandstone of the Cretaceous Winning Group. All three units exhibit porosities averaging 29-30 per cent, with permeabilities of 3-16 D in the Mungaroo and Flacourt Formations and 157 mD in the Birdrong Sandstone. Vertical seal for the accumulation is the Muderong Shale of the Winning Group.The Tubridgi Gas Field is the first onshore Carnarvon Basin hydrocarbon accumulation to be commercially developed. Gas production into the Dampier-to-Bunbury Natural Gas Pipeline commenced on 26 September 1991 and within one month had reached contract volumes averaging 22 MMCFD (623 000 m3/d). Field life is anticipated to be ten years.

Organic Matter Types in Early Cretaceous Strata Offshore Northwest Australia

Coring done on the Exmouth Plateau of the northwest Australian margin during Ocean Drilling Program Leg 122 encountered organic-carbon-rich siltstones and shales deposited during the Early Cretaceous. The types of organic matter contained in these stratigraphic units have been assessed using information provided from pyrolysis GC/MS, by extractable biomarker analysis, by Rock-Eval pyrolysis, and be carbon isotope analysis. The indicators of total organic matter type - pyrolysis GC/MS, Rock-Eval, and carbon isotopes - reflect predominantly continental plant sources of this material throughout the Early Cretaceous. The extractable indicators, however, show a decreasing dominance of land-plant biomarkers in younger strata. Comparison of stratigraphic sequences, sediment provenance, and organic matter types indicates that these offshore deposits are equivalent to the onshore occurrences of the Neocomian Barrow Formation and the Aptian Muderong Shale. The strata on the Exmouth Plateau are thermally immature, unlike their equivalents on the Australian continent. Tectonic isolation of the Exmouth Plateau from the Mainland evidently terminated the deltaic mode of rapid sedimentation at the end of the Aptian. Subsequent marine environments produced little organic matter offshore of northwest Australia. Burial and concomitant thermal maturation of the land-derived organic matter were therefore limited.

THE YAMMADERRY, COWLE AND ROLLER DISCOVERIES IN THE BARROW SUB-BASIN, WESTERN AUSTRALIA

The TP/3 Part I permit in the Barrow Sub-basin has been held by WAPET since 1952. Improvements in seismic quality and oilfield economics in the early 1980s resulted in the 1985 Saladin oil discovery, which subsequently led to the Yammaderry, Cowle and Roller discoveries.Yammaderry-1, drilled in 1988, encountered 16.5 m of gas capping a nine metre oil column. In 1989, Cowle-1 penetrated a 14 m oil column and tested at 1016 m3 (6390 BBL) of oil per day. Roller-1, drilled in 1990, encountered six metres of gas capping nine metres of oil and tested at 866 m3 (5450 BBL) of oil per day. Roller-2, deviated downdip to find the oil/water contact, proved an 18 m oil column, confirmed later by Roller-4.Early Cretaceous Barrow Group deltaic sandstones are the reservoirs for the Saladin, Yammaderry, Cowle and Roller oil fields. The Barrow Group is overlain by the Mar- die Greensand, the basal unit of the Muderong Shale which forms the regional seal. The transitional acoustic character of the Mardie Greensand and its thickness, variable fluid saturation and lithology, cause problems in picking a top Barrow Group event. Vertical Seismic Profiles acquired in the Yammaderry, Cowle and Roller wells have helped tie the wells to the seismic data.With Saladin on stream, and Yammaderry and Cowle under development, a major seismic survey was completed in late 1990 to delineate Roller and to detail prospects for future drilling in the revitalised TP / 3 Part 1 permit.

THE SALADIN OIL FIELD

The Saladin Oil Field is located immediately east of Thevenard Island, 25 km northwest of Onslow, in the Barrow Sub- basin, northwest Australia. Saladin 1, drilled in 1985 on a structure mapped from 1984 and older seismic data, tested 47° API oil at 875 kL/d (5510 B/D) from the Early Cretaceous Barrow Group. Additional shallow- water seismic was shot in 1985 and a Telseis* survey conducted in early 1986 over Thevenard Island and its fringing shoals. Saladin 2 in 1986, and Saladin 3 in 1987, tested at 1745 and 1790 kL of oil per day respectively (10 975 and 11 280 BOPD), setting successive Australian single- zone flow records. The fourth well, Saladin 7, was drilled in 1988 on a 1987 seismic line and tested at 1720 kL of oil per day (10 820 BOPD).The oil occurs in southeast- dipping Barrow Group sands overlain by and upthrown against Muderong Shale across the northeast- trending Saladin Fault. The Barrow Group sands have porosities around 24 per cent and permeabilities averaging 5- 6 darcies. Some claystone layers are present, and carbonate cement reduces porosity but less so permeability in parts of the oil column. A bioturbated sand has low permeabilities due to clay burrow- linings.Oil- in- place is currently estimated at 11 MkL (70 MMBBL). Field development will involve offshore platforms and deviated wells from Thevenard Island, on which oil storage and treatment facilities will be placed, and an offshore loading terminal for tanker transport. First oil production is scheduled for mid- 1989.

Organic Matter Diagenesis and Hydrocarbon Generation on Outer Continental Margin of Northwestern Australia: ABSTRACT

Organic geochemical analyses of sediments and rocks obtained from drill sites on the Exmouth and Wombat Plateaus and the Argo Abyssal Plain on the northwestern margin of Australia were done onboard the JOIDES Resolution during Ocean Drilling Program Legs 122 and 123. These analyses provide information about the sources of organic matter to these offshore locations from Triassic to Holocene times and also indicate the degree of postdepositional diagenesis and maturation the organic matter has experienced. Because this margin has interest to petroleum explorationists, these data have practical as well as fundamental significance. Triassic claystones (equivalent to the onshore Mungeroo Formation) from the Wombat Plateau contain up to several percent of land-derived organic carbon. Neocomian siltstones and claystones (equivalent to the Barrow Group and Muderong Shale) from the Exmouth Plateau hold similar organic matter but at lower concentrations. Younger sediments are generally very lean in organic matter. Gas chromatographic analysis of extractable hydrocarbons shows a large and often dominant contribution of continental components, notably n-alkanes with a strong odd/even ratio and tricyclic diterpanes. Both Rock-Eval and hydrocarbon results agree in indicating low to moderate levels of thermal maturity. Locations on the Exmouth Plateau typically contain large amounts of thermogenic gaseousmore » hydrocarbons dominated by methane. Concentrations peak in Senonian chalk sequences. In Neocomian siltstones and claystones, methane-ethane ratios diminish as concentrations decrease. The source of these hydrocarbons is likely to be the Triassic coals and coaly material below the Dingo claystone, which was not drilled during these legs but has been characterized from industry wells on this passive margin.« less

A DEPOSITIONAL MODEL FOR THE DUPUY MEMBER AND THE BARROW GROUP IN THE BARROW SUB-BASIN, NORTHWESTERN AUSTRALIA

A detailed sedimentological study of the Dupuy Member and the Barrow Group has resulted in a regional model for the deposition of these Upper Jurassic to Lower Cretaceous reservoir sequences in the Barrow Sub-basin. The Dupuy Member is interpreted as a prograding offshore slope sequence of turbidite sandstones and debris flows, which built laterally into the Barrow Sub-basin from along its eastern margin. This slope sequence contains bentonite markers in its upper part. The overlying Barrow Group was deposited by a delta which prograded along the length of the Barrow Sub-basin from the southwest and onlapped the Dupuy Member along the eastern side of the sub-basin. The topsets of the delta are fluvial to shallow marine sandstones, the foresets are offshore claystones, and the bottomsets are submarine mass-flow sandstones. After 8 million years of progradation, the delta was starved of sediment by continental breakup south of the Exmouth Plateau and stopped with its last foreset trending in an east-west arc from Barrow Island across the Exmouth Plateau. The Barrow Group delta was then gradually transgressed by the sea and blanketed by the Muderong Shale. Structural growth of the Barrow Island anticline took place during deltaic deposition and caused anomalous relationships between foresets and bottomsets under the north of Barrow Island. Known hydrocarbon accumulations and common shows in the Dupuy Member and the Barrow Group make these sequences attractive exploration targets.

A REVIEW OF THE HYDROCARBON HABITAT OF THE EASTERN AND CENTRAL BARROW — DAMPIER SUB-BASIN, WESTERN AUSTRALIA

The most completely known section of the Barrow- Dampier Sub-basin in the northern Carnarvon Basin of the Northwest Shelf comprises three depositional super- cycles spanning the Triassic to the Tertiary. Each cycle is made up of an initial transgressive section of mainly fine-grained clastics overlain by a thick, extensive, off- lapping sequence of coarse-grained deposits. The transgressive sedimentary package typically contains a coarse basal unit overlain by a thick, argillaceous unit, whereas the progradational package changes character in each cycle, representing increasingly open marine conditions as the depocentre and its palaeogeography evolved. Continental siliciciastics at the end of the Triassic Supercycle contrast with the marine-marginal marine siliciciastics at the end of the Jurassic-Neocomian Supercycle and the prograding Tertiary carbonate wedge of the youngest cycle. Each of these gross sequences has a distinctive seismic signature upon which are superimposed stratigraphic features reflecting basin evolution from a broad intra-continental depocentre to a mature, passive continental margin basin.In the area east of Barrow Island, potential hydrocarbon source rock quality and richness varies between each cycle but potential source beds frequently occur at similar levels within each supercycle. The Dingo Claystone within the Jurassic-Neocomian depositional package contains by far the thickest and most extensive potential sources in the area and is likely to be the source for most of the hydrocarbon liquids discovered to date in the northern Carnarvon Basin (with the probable exclusion of the majority of the Rankin Platform condensates).The occurrence of oils of mixed composition and considerable variability beneath the Muderong Shale regional seal in areas of low thermal maturity suggests that many of the hydrocarbon liquids have undergone considerable vertical migration and have also a complex genesis. Furthermore, saturate-rich liquid hydrocarbons overprinting an older biodegraded oil are recognised in a number of wells along the basin margin hingeline. The likely migration and entrapment model for the majority of hydrocarbons discovered to date in the area under review involves dynamic charging of reservoirs, mainly during the Tertiary. Two main pulses of generation and migration are recognised in the eastern portion of the sub -basin, and a third phase is probably occuring at present-day, west of Barrow Island.

Geochemical Correlation of Windalia Oil and Extracts of Winning Group (Cretaceous) Potential Source Rocks, Barrow Subbasin, Western Australia

Windalia oil is a commercial accumulation in a Cretaceous reservoir at Barrow Island, Western Australia. A chemical correlation study has been made between this oil and hydrocarbons extracted from 37 Cretaceous sedimentary rock samples from different stratigraphic levels in seven wells on and around Barrow Island. Seven established correlation parameters and one new parameter have been applied to establish oil:source rock relations. The new parameter is the ratio of pristane + heptadecane to phytane + octadecane. The influence of maturation on several correlation parameters has been investigated by pyrolyzing source rocks at 300°C for varying times. The changes observed in these experiments have been used to infer the effects which maturation processes have on the co relation parameters. To assess the overall degree of correlation between source rock extracts and oil, each method has been assigned a weighting which reflects its power as a correlation technique. An overall correlation score was obtained for each potential source rock by totaling the contributions from the eight individual methods. It appears likely that the Windalia oil had its source within the Winning Group of sedimentary rocks, the most probable source formations being the Middle shale of the Windalia sandstone member, the Muderong Shale, and the Windalia Radiolarite. Several mechanisms of formation of Windalia oil from these source beds are possible.

THE GEOLOGY OF THE WEST TRYAL ROCKS GAS FIELD

The West Tryal Rocks gas field is located offshore at the western margin of the Barrow Sub- basin, in the Carnarvon Basin of Western Australia. It was discovered by West Australian Petroleum Pty Ltd ( WAPET) in 1973 on a southwesterly extension of the Rankin Platform where, farther north, a number of major gas/condensate discoveries have been made by Burmah Oil Company of Australia Ltd (BOCAL) since 1971.The productive structure at West Tryal Rocks lies at a depth of 3200 m in about 150 m of water. It consists of an elongate north - trending uplifted block of Triassic and possibly Lower Jurassic reservoir rocks called the Mungaroo Beds.The block is unconformably capped by the Lower Cretaceous Muderong Shale which also provides the lateral seal across the bounding faults. The reservoir section dips to the north at a greater rate than does the sealing unconformity so that progressively younger pre-Cretaceous sediments subcrop the unconformity in that direction.Shales of Middle to Late Jurassic age in the Barrow Sub-basin to the east are believed to be the primary source of hydrocarbons, although the overlying Muderong Shale cannot be ruled out.Three main gas-bearing sands have been encountered by the two wells drilled to date. The second well was drilled up-structure from the first and penetrated 144 m of net gas pay of which 133 m is contained in the three sands. The sands are mainly medium to very coarse grained and possess good porosity and permeability.Preliminary reoervvs estimates indicate that the field contains in excess of 28 x 109 m3 (1 x 1012 ft3) of gas (Playford, 1975).The West Tryal Rocks gas field is unique compared to the other Northwest Shelf fields, in that it is slightly overpressured and contains up to 28% of non-combustible gases - predominantly carbon dioxide and nitrogen. Additionally, the field possesses relatively fresh underlying formation waters with high concentrations of bicarbonate ions.