Offshore Carnarvon Basin Research Articles

ProbGRV: a workflow for geostatistical depth conversion and probabilistic assessment of gross rock volume

Understanding and estimating the probability of geological success (Pg) and original hydrocarbon-in-place (OHIP) are an integral part of the geoscientist’s role from exploration though to development. This paper presents a workflow developed at Santos for the systematic assessment of two key elements in this process: the probability of structural closure (Pcl); and, the estimation of the uncertainty of gross rock volume (GRV). There are two distinct parts to the workflow. Firstly, Kriging and sequential Gaussian simulation (SGS) are used in map-based, seismic time-to-depth conversion to generate multiple equi-probable depth maps (in the order of 1,000+ realisations). Numerous depth conversion methods are considered where appropriate. Secondly, every depth map realisation is validated for structural closure around a target location (e.g. a proposed or existing well). Primary outputs from the workflow include estimates of Pcl, and probability distributions of GRV and pool area for valid maps, which may then be used directly in estimating geological risk and OHIP. Secondary outputs from the workflow include basic statistics associated with depth conversion uncertainty, such as target depth prognosis and the distribution of the depth to lowest closing contour. The ultimate objective is to provide the interpreter with a greater appreciation of the range of possible outcomes given the uncertainty in structural geometry. This workflow, named probGRV, has been designed and developed within Santos using commercially available geophysical software and in-house proprietary software. During the past few years, the workflow has been implemented on key assets at various stages of the prospect/field life cycle and in both pre- and post-drilling campaigns for audit purposes. Case studies from the Cook Field in the onshore Eromanga Basin and the Finucane South Field in the offshore Carnarvon Basin are shown to illustrate the methods and results.

Seafloor geomorphology and submarine landslide hazards along the continental slope in the Carnarvon Basin, Exmouth Plateau, North West Shelf, Australia

3D exploration seismic data were interpreted to investigate the locations and characteristics of submarine slope failures along the continental slope in the offshore Carnarvon Basin on Australia’s North West Shelf. Seisnetics™, a patented genetic algorithm was used to process the 3D seismic data to extract virtually all trough and peak surfaces in an unbiased and automated manner. The extracted surfaces were combined in the 3D visual database to develop a seafloor digital terrain model that extends from the continental slope to the Exmouth Plateau. The 3D data were used to map the subsurface extent and geometry of landslide failure planes, as well as to estimate the thickness and volumes of slide deposits. This paper describes the geomorphic characteristics of five of the survey areas. Geomorphic mapping shows the presence of slope failures ranging from small (20 km across) mass transport complexes (MTC). The features are associated with debris flow chutes, turbidity flow channels, and debris fields. Analysis of failure planes show prominent grooves or striations related to the mobilisation of slide material down both the continental slope and Exmouth Plateau and into the Kangaroo Syncline. Submarine slope failures can occur at the continental shelf break in about 200–300 m of water and run out to the Exmouth Plateau surface in about 1,100–1,400 m water depths. The largest individual slides in the survey areas have widths of 30 km and minimum run-out lengths of 75 km, though associated turbidity flow deposits likely extend much further. The subsurface expression of the large MTCs illustrates a history of sediment accumulation along the mid-slope followed by repeated slope failure and debris run-out. Sediment accumulation and slope failure processes are actively occurring along the continental slope and submarine landslides thus are a major driver of hazard to subsea infrastructure development. Smaller more frequent slides may pose a greater hazard than large infrequent MTCs.

Higher-resolution palynostratigraphy of the Norian-Carnian (Triassic) Upper Mungaroo Formation, offshore Carnarvon Basin

Palynostratigraphic correlations within the Triassic fluvio-deltaic upper Mungaroo Formation (M. crenulatus and upper S. speciosus zones) of the Carnarvon Basin have proven to be difficult. Although two reliable pollen extinction datums have long been established in the uppermost 200 m of the formation, correlations within the sector below (up to 1,500 m) have had to rely on broad algael and pollen acmes, with variable results. A revised palynostratigraphic scheme is presented in this extended abstract, which has been largely in use within Shell and Morgan-Goodall Palaeo Associates since mid/late 2010, and which has not been previously published in detail. For consistency, the subzone names remain the same as those in previous use; however, crucially, a framework for their reliable identification in more recently-analysed wells is provided by several Morgan gradational sub-types of key pollen species (viz. of Cycadopites stonei, Ephedripites macistriatus and Samaropollenites speciosus). Within this robust framework that is based on top-ranges, base-ranges and rapid switches in the ratios of gradational and related morphotypes, numerous thin marine incursions and regional to sub-regional swampy phases are evidenced. Lateral and vertical relationships between marine incursions and swampy phases are sometimes apparent, and clustering of a few of the above pollen events at these levels hints at condensation. The revised framework has been successfully used in the high-resolution, regional-stratigraphic interpretation of both seismic and well data and is contributing to an increasing understanding of the variability of the Upper Mungaroo depositional system in the Greater Carnarvon Basin.

New evidence for the age of the Athol Formation (Middle Jurassic; Bajocian) in the Tusk-1 and Tusk-2 wells, offshore Carnarvon Basin, Western Australia

The co-occurrence of ammonites with palynomorphs in the Athol Formation of the Tusk-1 and Tusk-2 wells drilled in the offshore Carnarvon Basin, Western Australia confirms the Early Bajocian (Middle Jurassic) age of the Dissiliodinium caddaense dinoflagellate cyst Oppel Zone. The macrofaunas refine this Early Bajocian age to the early Laeviuscula Chronozone. A belemnite from the Tusk-1 well has a strontium isotope (87Sr/86Sr) ratio consistent with the biostratigraphical age. All the identifiable ammonites belong to Pseudotoites robiginosus (Crick). Pseudotoites is prominent in the Early Bajocian of the Indo-Pacific Realm, being known mainly from onshore Western Australia and the Southern Andes, together with rare occurrences in Irian Jaya (west New Guinea); somewhat surprisingly, it is also rarely present in southern Alaska. The palynofloras studied from the Tusk-1 and Tusk-2 wells contain abundant specimens of the marine dinoflagellate cyst Dissiliodinium caddaense, and are assigned to the Dissiliodinium caddaense Oppel Zone. The Athol Formation is a correlative of the Newmarracarra Limestone of the onshore Perth Basin, Western Australia; the distribution of both these units indicates a marine transgression onto the Australian block during the Early Bajocian.

ENVIRONMENTAL UPDATE 2004

This paper presents the highlights of development activity of 2004 for the petroleum industry within Australia. In the face of declining oil production within Australia there were few new oil field developments in 2004 (Exeter- Mutineer; Jingemia). The start up of liquids stripping at Bayu-Undan in the Timor Sea and other gas/condensate fields such as Apache’s Linda, however, helped to arrest the declining trend. The first oil fields that define a new oil province in the Exmouth Sub-basin were the subject of extensive appraisal programs and Woodside gave the green light for start of the A$1.48 billion Enfield development.The story for natural gas in 2004 is somewhat more buoyant with several developments in domestic supply around Australia, including coal seam methane (CSM) production on-stream on the east coast. The national pipeline grid extended with the opening of the A$500 million SEAgas pipeline between Port Campbell and Adelaide. Minerva gas production followed at the end of the year, leading the way for the approval of gas developments at Thylacine- Geographe (A$1.1 billion) and Casino (A$200 million) in the Otway Basin. The Yolla gas production platform was installed on site in the Bass Basin. Apache and Santos signed an agreement to supply gas from John Brookes, offshore Carnarvon Basin, and Woodside looked to Blacktip, in the Bonaparte, to supply gas to the Northern Territory.2004 was a cornerstone year for LNG. A new carrier was delivered to the NWS Joint Venture and gas flowed from the fourth LNG train for the first time. Deliveries under new contracts started to Japan and Korea and a major contract for supply was signed with China. Other potential LNG projects began significant appraisal programs at fields such as Scarborough on the NWS.

THE GERYON, ORTHRUS, MAENAD AND URANIA GAS FIELDS, CARNARVON BASIN, WESTERN AUSTRALIA

The Geryon, Orthrus, Maenad and Urania Gas Fields are located in permit WA-267-P in approximately 1,200 m of water, and between 35 km northwest and 70 km north of the Gorgon Gas Field in the offshore Carnarvon Basin of Western Australia. Five wells were drilled in these fields between August 1999 and February 2001 as part of a six-well, three-year obligatory drilling program. The primary objectives were late Triassic sandstones of the upper Mungaroo Formation. The Geryon and Urania Fields are three-way footwall structures, while the Orthrus and Maenad Fields comprise four-way horst structures where progressively older units subcrop against the Callovian Unconformity. All objective reservoirs were amplitude associated and had strong AVO signatures, which was instrumental in the high exploration success rate and excellent exploration prediction of OGIP from seismic data.This paper will briefly discuss the description of late Triassic and early Jurassic reservoirs and the transition of the AA sand of the Mungaroo Formation from fluvial to marginal marine facies in the Greater Gorgon Area, the recent drilling results of the Triassic Prospects in WA-267-P, and the geophysical attributes of the AA sand Mungaroo Formation reservoirs.The WA-267-P Triassic Gas Fields are estimated to contain approximately 210 billion m3 (7.4 TCF) recoverable sales gas. The close proximity of these Triassic gas fields to each other, the clean gas composition and size of resource base suggests these fields are excellent candidates for a future gas development in Western Australia.

A REVISED DEPOSITIONAL MODEL FOR EAST SPAR AND ITS IMPACT ON FIELD PERFORMANCE

The East Spar gas condensate field is located in production licence WA-13-L in the offshore Carnarvon Basin. Production commenced in 1996 with two subsea wells linked to processing facilities on Varanus Island via a multi-phase pipeline. The pressure performance of the field has been significantly different to predevelopment expectations. This prompted a reexamination of the seismic and well data to investigate the potential for alternative reservoir models.Integrated stratigraphic and seismic interpretation reveals that the Barrow Group reservoir sands were deposited within an incised valley of limited lateral extent. Sea level fall instigated erosion of a valley that on transgression was filled with successive fluvial, estuarine and marine sediments. Good quality sands are expected to be limited to this valley, the upper part of which can be mapped on seismic. Poor sand development in East Spar–2ST is consistent with its location at the edge of the incised valley.Before development, the primary production mechanism was expected to be a strong bottom water drive comparable with other Barrow Group fields in the Carnarvon Basin. The revised depositional model, however, and the observed decline in reservoir pressure, indicate that connection to this regional aquifer is limited. This implies that water influx will probably be later, and ultimate recovery higher, than previously anticipated.

ABSTRACT: Thermal history modeling using organic matter maturation data from normal pressure systems in the Offshore Carnarvon Basin, Northwest Shelf, Australia

ABSTRACT: Thermal history modeling using organic matter maturation data from normal pressure systems in the Offshore Carnarvon Basin, Northwest Shelf, Australia

SEISMIC BASED RESERVOIR CHARACTERISATION OF THE WANDOO OIL FIELD

The Wandoo Oil Field of Western Australia's offshore Carnarvon Basin is located in the WA-14-L production licence approximately 70 km northwest of Dampier. Hydrocarbons from the 22 m thick oil column are produced from the informally named Unit A and Unit B of the Vf. australis Sandstone reservoir through 15 extended-reach horizontal wells. Cumulative production from the field is over 30 MMBBL of the estimated 160 MMBBL initial oil- in-place. Production reached a plateau rate of 40,000 BOPD in April 1997 and is now declining in line with the predicted reservoir performance.A multidisciplinary team was formed to develop a detailed reservoir model using 3D seismic data, a regional 2D seismic database and geological and engineering data from 11 vertical and 19 horizontal wells. The M. australis Sandstone was divided into six depositional units defined by changes in well log character, glauconite content and reservoir quality. These units were subdivided into 27 correlatable flow units and 6 laterally extensive non- reservoir siderite layers.An estuarine-deltaic depositional system is suggested for the M. australis Sandstone reservoir at Wandoo. The recognition of erosional features at various scales and distinct areas of higher quality reservoir indicate that this system wras subject to frequent changes in relative sea level. The top of the Unit B was identified as the most significant sequence boundary with the overlying Unit A deposited as a transgressive sand of limited distribution.A 3D geological model honouring the revised interpretation has been constructed and used as input for reservoir simulation resulting in an improved production history match. The concepts developed have been successfully tested by a horizontal multi-lateral production well.

PRESSURE STUDY OF THE FLACOURT FORMATION AQUIFER IN THE THEVENARD ISLAND AREA OF THE BARROW SUB-BASIN

Thevenard Island area lies in the offshore Carnarvon Basin off the northwest coast of Western Australia. The Flacourt Formation of the Cretaceous Barrow Group sequence is the primary oil-producing reservoir. West Australian Petroleum Pty Limited (WAPET) as operator on behalf of its participants (Chevron, Texaco, Shell and Mobil) has been producing from this reservoir since 1989. It has widely been held that in this area the relatively thick, multi-darcy Barrow Group oil accumulations have had infinite aquifer pressure support with no regional draw-down effect.After the commencement of oil production from the Flacourt Formation, wireline pressure surveys in exploration and development wells have indicated anomalous pressure trends in the reservoir. Initially, the accuracy of pressure gauges and elevation measuring devices were questioned.Recent studies based on WAPET's production history in the region and re-analysis of wireline pressure data have shown that the Flacourt Formation does experience regional draw-down in aquifer pressure due to production. This paper demonstrates the existence of draw-down and how this information has aided in the evaluation of the Flacourt Formation and the overlying Mardie Greensand reservoirs.

Geology and Exploration in Southwest Pacific Australian Region: Western and Northwestern Margin Basins of Australia

The Marginal basins of Western and Northwestern Australia extend approximately 3,800 km along the coast and comprise both continental shelf and adjacent deepwater plateau areas. From north to south, the principal basins are the Sahul/Malita, Browse, Carnarvon, and Perth basins. The stratigraphic sequence within each basin is broadly similar, with initial widespread Triassic-Early Jurassic deposition in broad regional pre-rift sags. Middle Jurassic to Late Jurassic rifting on the Northwest Shelf and early Cretaceous rifting in the Perth basin varies in intensity across the region, and provides the primary control of hydrocarbon distribution through trap type, reservoir, and source rock quality. The best-developed oil source rocks of the region are found in these Jurassic rifted sequences. Although drilling to date has been generally sparse, with only some 824 wells throughout the entire area, significant accumulations of gas and oil have been found in the offshore Carnarvon basin and the Vulcan Graben area of the Browse basin. Recent discoveries of commercial oil at Jabiru in the Vulcan graben and Griffin in the Carnarvon basin have again focused activity on the area's oil potential. Many structural traps remain to be drilled and the potential for stratigraphic trapping has been only slightly explored. Large,more » poorly explored frontier areas, between the established producing areas and in the Perth basin, as well as adjacent deepwater, are available. However, present data suggest that not all key success factors, notably mature oil source rocks and good reservoirs, may be present in these areas.« less

Oil and Gas Developments in Australia in 1989

Offshore discoveries at the beginning and end of 1989 brightened an otherwise uneventful year. Wanaea 1, spudded in 1988 in the Dampier subbasin, flowed oil in February. Cowle 1, in the offshore Carnarvon basin, was testing at year end. Talbot 1 became the only discovery in the Vulcan basin (at the opposite end of Australia's vast North West Shelf) in the closing days of 1989. It was a year of reduced onshore exploration activity (the lowest since 1980), but there was more offshore activity than since 1984 in the Gippsland, Carnarvon, and Bonaparte basins, and the Vulcan subbasin. At year end, 5 offshore wildcats and 1 development well were in progress: 3 in the Carnarvon basin, 2 in the Vulcan subbasin, and 1 in the Otway basin. Onshore, no finds of significance were recorded in 1989. Although appraisal drilling at Katnook in the Otway basin was successful and 1 wildcat was completed as a gas well, 2 neighboring prospects were found wanting. In the Cooper-Eromanga region, the 15 discoveries were small, and no discoveries were made in the Surat basin, Denison trough, Pedirka basin, or onshore Canning and Carnarvon basins. Geophysical activity was the lowest onshore since 1978, but offshore activity was the highest for the decade. Average daily production of 472,000 bbl (compared with 519,000 bbl in 1988) of crude oil and condensate amounted to about 80% of Australian refinery capacity. Sixty-six percent of the production came from Gippsland basin fields and 15% from Carnarvon basin, where new fields came on-stream. LNG from the North West Shelf was brought on-stream for the first time. While the number of exploration permits in force throughout the nation did not change significantly, large tracts were relinquished in the Canning basin in Western Australia and over portions of the southern Eromanga, Arrowie, Eucla, Murray, Pedirka, and Pirie-Torrens basins in South Australia. Agreement during 1989 between Australia and Indonesia about sharing of potential production in the eastern Timor Sea off Austral a's North West Shelf is expected to open this area to exploration in the near future.

THE NORTH WEST SHELF

The region of the North West Shelf dealt with in this paper is underlain by three of the four basins which make up the Westralian Superbasin. The Bonaparte Basin lies outside the scope of this paper; the other basins are the Browse Basin, the offshore Canning Basin, here named the Western Canning Basin, and the offshore Carnarvon Basin, here called the Northern Carnarvon Basin. Sediments belonging to ten depositional sequences (Pz5, Mzl to Mz5, and Czl to Cz4) are present in the basins, the oldest being of Late Carboniferous and Permian age (Pz5).Deposition commenced in rift (interior fracture) basins under fluvial/deltaic conditions in the Late Permian/Early Triassic (Mzl), when the North West Shelf was part of Gondwana. Continental breakup took place in the Middle Jurassic (breakup unconformity between Mz2 and Mz3), and marine conditions prevailed over the Westralian Superbasin thereafter, with deposition taking place in a marginal sag setting. Siliciclastic sediments gave place to carbonates in the Late Cretaceous (Mz5) as the Indian Ocean grew larger.Parts of the area have been under permit since 1946, and to date some 227 exploration wells have been drilled. The most intensive exploration has taken place in the Northern Carnarvon Basin (191 wells), followed by the Browse Basin (20 wells), and Western Canning Basin (16 wells). Thirty- four economic and potentially economic discoveries have been made. The main target reservoirs are Triassic, Jurassic and Cretaceous, and the regional seals are Triassic and Cretaceous. The fields are of two types: pre- breakup unconformity (mainly tilted horst blocks), and post- breakup unconformity (usually four- way dip closures). Of the five producing fields, the North Rankin Gas Field is a pre- breakup field, while the four oil fields (Barrow, Harriet, South Pepper and North Herald) are all post- breakup.

Volcanic rocks from edel no. 1 petroleum exploration well, offshore Carnarvon basin, Western Australia

Abstract The volcanic rocks recorded from the Edel No. 1 well are probably Mesozoic in age and consist of a variety of trachytes, nosean phonolites, and ‘lamprophyres’. They can be thought of as a mixture of variable amounts of alkali feldspar, pyroxene, biotite, hornblende, and minor nosean. Chemically they are all undersaturated with respect to SiO2.