Organic-rich mudrocks (ORM) from the Brushy Canyon Formation in west Texas were deposited in the Middle Permian during the Guadalupian epoch in the Delaware Basin. Brushy Canyon ORM were examined for Re-Os isotope systematics with a goal of constraining their depositional age, the 187Os/188Os value of seawater at their time of deposition, and to examine how Re and Os partition into organic material in ORM. For these samples, Rock-Eval pyrolysis data (HI: 228-393 mg/g; OI: 16-51 mg/g) indicates predominantly Type II marine kerogen with minor contributions of Type III terrestrial organic matter. Rhenium and osmium abundances correlate positively with HI, and negatively with OI, which are proxies for organic matter type and degree of preservation. These data are consistent with previous work that indicates Re and Os abundances are controlled by the availability of chelating sites in the kerogen. Brushy Canyon Formation samples have (total organic carbon) TOC values between 0.97 and 4.04% and show a strong positive correlation with both Re and Os abundances, consistent with correlations between these parameters in other ORM suites. The positive slopes in these correlations are distinct between marine (higher slopes) and non-marine (lower slopes) lacustrine environments of deposition. The Brushy Canyon’s steep slopes are consistent with marine deposition of its organic matter and an open-ocean non-restricted setting. The relationship to other Re-Os and TOC data sets appears to be a function of the restrictivity of marine conditions, and associated variations in reducing conditions during ORM accumulation of the Delaware Basin compared with more restricted lacustrine basins with local drawdown of Re and Os.
The Re-Os isotope systematics of ORM from the Brushy Canyon Formation yields a Model 1 age of 261.3 ± 5.3 Ma (2.0% age uncertainty; MSWD = 0.82). Within the uncertainty, this agrees with the expected Guadalupian age for this formation. This Re-Os age represents the first direct, absolute age for Guadalupian organic matter in the Delaware Basin. The initial (187Os/188Os)i = 0.50 ± 0.06 obtained by isochron regression represents the 187Os/188Os of seawater at this time. This value is significantly less radiogenic than modern day seawater (~1.06). The lower 187Os/188Os of Guadalupian seawater recorded is likely caused by a decrease in the relative flux of radiogenic Os from continental weathering due to a number of local and global climatic and tectonic changes that were occurring during this time.
Bradshaw, Marita (Geoscience Australia, GPO Box 378, Canberra A.C.T., 2601, Australia Email: email@example.com) | Foster, Clinton (Geoscience Australia, GPO Box 378, Canberra A.C.T., 2601, Australia Email: firstname.lastname@example.org) | Willcox, Barry (Geoscience Australia, GPO Box 378, Canberra A.C.T., 2601, Australia Email: email@example.com) | Struckmeyer, Heike (Geoscience Australia, GPO Box 378, Canberra A.C.T., 2601, Australia Email: firstname.lastname@example.org)
AUSTRALIA'S FRONTIER BASINS AND PROSPECTS FOR NEW PETROLEUM PROVINCES. Marita Bradshaw, Geoscience Australia, GPO Box 378, Canberra A.C.T., 2601, Australia Clinton Foster, Email: email@example.com Barry Willcox, Heike Struckmeyer Abstract Within Australia's marine jurisdiction (AMJ) there are at least ten deepwater basins related to Mesozoic rifted margins that have the potential to contribute at least one new petroleum province of global significance. Current offshore exploration activity in Australia is focussed around giant fields in the north west (North West Shelf) and in the south east (Bass Strait) quadrants of the AMJ, representing less than one percent of the prospective acreage. Frontier basins in deepwater along Australia's southern and eastern margins are vastly under-explored with only three exploration wells having been drilled in water depths beyond 500 metres and limited, sometimes only regional, seismic coverage. Despite this minimal exploration, active petroleum systems are indicated by remote sensing techniques (SAR, ALF), seismic evidence of bottom simulating reflectors (BSRs), flat spots and gas escape structures, beach strandings of asphaltites, and oil and gas shows in the few wells in this region. Key prospects for hydrocarbon exploration in the future include the basins of the Great Australian Bight, the west Tasmanian margin and the Lord Howe Rise. Australia's southern margin is conjugate with Antarctica and was the site of a major Mesozoic rift valley system approximately 4,000 kilometres long. At its eastern end the giant Gippsland Basin fields were discovered in the 1960s, but the western two-thirds of the margin is essentially unexplored. A giant Late Cretaceous delta complex is apparent even on present day bathymetry. It is comparable in area to the Niger Delta, with prograding sequences up to 5,000 metres thick. These sand-rich sequences overlie mobile units representing Albian and Turonian marine shales; and the total sedimentary section is up to 15,000 metres thick. Along the western margin of Tasmania and on the South Tasman Rise the break-up had a strong trans- current component producing a series of strike-slip basins up to 6,000 metres thick. Restricted marine environments were maintained along this part of the margin until the final separation of Australia and Antarctica in the Oligocene. The Lord Howe Rise is a large continental fragment lying between Australia, New Caledonia and New Zealand in the Tasman Sea. It covers an area of 740,000 square kilometres in waters shallower than 3000 metres. It is underlain by a number of sedimentary basins, some in excess of 4,000 metres thick. BSRs indicative of gas hydrates, flat spots and diapiric features have been observed on the limited seismic coverage. BLOCK 1 -- FORUM 2 157 AUSTRALIA'S FRONTIER BASINS AND PROSPECTS FOR NEW PETROLEUM PROVINCES Introduction Australia's marine jurisdiction covers 14.2 million square kilomet
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The A$250 million Stuart Stage 1 Oil Shale Project in Queensland, Australia is one of the most significant new developments in the non-conventional oil industry. The Stuart Project is a joint venture between Australian companies Southern Pacific Petroleum N.L. and Central Pacific Minerals N.L. (SPP/CPM), and Canada's Suncor Energy Inc. (Suncor). An important milestone was reached in 1999 with completion of construction of the Stuart Stage 1 technology demonstration plant. This 4,500 b/d (715 m3/d) plant, constructed by Bechtel, is currently being commissioned by Suncor, the project operator.
The Stuart oil shale deposit has an estimated in situ resource of 3 billion barrels of shale oil. The Stuart Project incorporates the Alberta-Taciuk Processor (ATP), a new generation of oil-shale retorting technology which was chosen following a A$150 million R&D program in the 1980s. Upon technical and operational success in Stage 1, the next step is to scale up the ATP in Stage 2 to a commercial sized module producing 15,000 b/d (2,350 m3/d). This could lead to a commercial scale operation of at least 85,000 b/d (13,500 m3/d).
Success at Stuart will have important implications for Australia in terms of job creation and development of a new source of indigenous oil supply. It could also be important for world oil supply given the immense size of the world's oil shale resource.
Despite the immense size and pervasive nature of the world's oil shale resource, large-scale commercial development has yet to be achieved. Oil shale industries have operated in many countries since the 19th century, but the development of relatively inexpensive and plentiful supplies of conventional crude oil in the first half of the 20th century made most of these operations redundant.
The oil crisis of the early 1970s triggered a new and significant round of expenditures in oil shale research and development, particularly in the carbonate oil shales of the Green River Formation in the western USA. However, disappointing performance, falling oil prices and reduced government support took their toll and most of this effort ceased by the late 1980s.
This paper describes the most significant new development in the oil shale industry, the A$250 million Stuart Stage 1 technology demonstration project in Queensland, Australia which is currently in the final phases of commissioning. The project is designed to process 6,000 t/d of oil shale to produce 4,500 b/d (715 m3/d) of oil products. Partners in this joint venture include two Australian based companies, Southern Pacific Petroleum N.L. and Central Pacific Minerals N.L. (SPP/CPM) and Suncor Energy Inc. (Suncor), the project operator and a major oil sands producer based in Canada.
Stuart is one of a number of high quality oil shale deposits in Queensland that are favourably located near deepwater ports and existing infrastructure.
AUSTRALIAN OIL SHALES
Australia is no stranger to oil shale development. Production from oil shale deposits in the states of Tasmania and New South Wales dates back to the 1860s. The last producing mines closed in the early 1950s after government support ended. Between 1865 and 1952 about 4 million tonnes of oil shale were processed.(1)
An exploration program was carried out by SPP/CPM in the 1970s and early 1980s to find high quality oil shale deposits amenable to open-pit mining operations in areas near infrastructure and deepwater ports. This program was successful in finding a number of silica based oil shale deposits of commercial significance along the coast of eastern Queensland (see Figure 1).
SHALE OIL: A NEW FUEL FOR THE 21st CENTURY SHALE OIL: A NEW FUEL FOR THE 21ST CENTURY James D. McFarland, Southern Pacific Petroleum N.L. and Central Pacific Minerals N.L. (SPP/CPM), PO Box 7101 Riverside Centre, Brisbane, QLD 4001 Australia Abstract. Over the past 25 years two Australian companies, Southern Pacific Petroleum N.L. and Central Pacific Minerals N.L. (SPP/CPM), and their co-venturers have invested A$400 million in a bid to create a modern shale oil industry in Australia. An important milestone was reached in 1999 with construction of the A$250 million Stuart Stage 1 demonstration plant in Queensland, Australia in a joint venture with Canada's Suncor Energy Inc. (Suncor). The 4,500 b/d (715 m3/d) plant is currently being commissioned by Suncor, the project operator. Stuart is one of 10 high quality, silica based oil shale deposits held by SPP/CPM and its co-venturers along the Queensland coast which contain an estimated 29 billion barrels (4.59 Gm3) of in-situ resource. The Stuart project incorporates the Alberta- Taciuk Processor (ATP) retort technology which was chosen following a A$150 million R&D program in the 1980s. With technical and operational success in Stage 1, the Stuart Joint Venture expects to scale up the ATP in Stage 2 to a commercial sized module producing 15,000 b/d (2,350 m3/d). This could lead to a commercial scale operation of at least 85,000 b/d (13,500 m3/d) by 2007. Success at Stuart creates a new development paradigm for oil shale with important implications for world oil supply. In terms of recent developments, China
has been seeking potential foreign investment in the reconstruction of the Fushun East open- Despite the immense size and pervasive pit coal mine in Liaoning Province where it is nature of the world's oil shale resource, large- planned to mine oil shale in conjunction with scale commercial development has yet to be coal. A similar operation has been underway achieved. Oil shale industries have operated in in the West mine with shale production of 3 to many countries since the 19th century, but the 4 million tonnes per year.(1) development of relatively inexpensive and In Estonia, the world leader in oil shale plentiful supplies of conventional crude oil in mining, the government has been in discussion the first half of the 20th century made most of with private developers to assess expansion these operations redundant. potential. Most of the country's current shale The oil crisis of the early 1970s triggered production of 11 to 12 million tonnes per year a new and significant round of expenditures in is used as a solid fuel in electricity oil shale research and development, generation.(2) Also, the U.S. government has particularly in the carbonate oil shales of the recently signed a co-operation agreement with Green River Formation in the western USA. the Estonian government to invest funds for However, disappointing performance, falling research into technically an
This paper presents general guidelines to determine the feasibility of offshore petroleum projects in terms of field appraisal, subsurface development planning, and facilities options. It also illustrates the multidisciplinary nature of various tasks and includes examples for illustration. The emphasis is on oil fields, particularly marginal fields.
The life of every oil and gas field begins with its discovery. Almost immediately, we want to know what its potential is (in terms of reserves and monetary value) and what the development options are in terms of subsurface plan and facilities.
To answer these questions, a systematic approach is required to evaluate the discovery, to forecast the reservoir behavior under expected producing conditions, and to design the optimum facilities to meet forecasted production. This paper outlines the required process for studying the feasibility of developing offshore petroleum fields.
A petroleum development project typically is divided into a number of major phases: exploration (including permit acquisition), field appraisal (primary and possibly secondary), feasibility study, project implementation (construction), and field production (operation and maintenance, management, and facilities upgrades, including secondary development phases). Different technical departments, each with specific aims, usually manage these phases (Fig. 1).
While the development sequence is similar for all fields, there are notable differences between onshore and offshore projects. Most significantly, the engineering requirements and capital expenditure tend to be one or two orders of magnitude greater for offshore projects than onshore developments. Furthermore, offshore developments tend to have a much longer development schedule before they come on stream. Reserves and well productivity need to be substantially greater for offshore projects to cover the greater capital expenditure and operating cost, respectively.
Pulse testing was used within the Pulse testing was used within the Fortescue field to clarify reservoir geometries and fluid communication pathways within the field. The high pathways within the field. The high levels of communication demonstrated in the test data required a non-standard analysis of the pressure responses. In addition, proper attention to test planning, data acquisition and data planning, data acquisition and data processing allowed valuable insights processing allowed valuable insights into reservoir limits. Most of the structural implications deriving from the pulse tests have been subsequently supported by a recent 3D seismic survey over the area. The results and insights gained from these tests are being incorporated into a full field simulation model of Fortescue, which is an integral part of an ongoing depletion study of the field.
The Fortescue field was discovered in 1978 and is one of Esso Australia and BHP Petroleum's mature oil fields in the Bass Strait offshore Victoria, Australia. Located 62 km offshore in 69 meters of water (Figure 1), the field is a separate oil accumulation in stratigraphic trap on the western flank of the Halibut and Cobia oil fields (Figures 2 and 3). In 1983, the Fortescue "A" and Cobia "A" platforms were installed to develop the field. Fortescue "A" is a 21 conductor platform designed to develop the central platform designed to develop the central and northern regions of the field. Eight wells from Cobia "A" were used for southern Fortescue development. Since production began in 1983, over 200 Mstb (32Mm3) of oil has been produced. The field is estimated to be produced. The field is estimated to be approximately 70% depleted at this stage.
The Fortescue reservoirs contain oil trapped between the marine shales deposited on the erosional unconformity at the top of the Latrobe Group and a base seal complex consisting of interbedded shales and coals, the FM-1.3C and M-1.0.1. It is this impermeable basal unit which hydraulically separates Fortescue from the Halibut and Cobia reservoirs.