EAST SPAR FIELD—FROM DISCOVERY TO SALES

1996 ◽  
Vol 36 (1) ◽  
pp. 30
Author(s):  
G. M. Pitt ◽  
L. E. Kuryiowicz ◽  
IP. F. Campbell
Keyword(s):  
Joint Venture ◽  
Gas Pipeline ◽  
Window Of Opportunity ◽  
Engineering Construction ◽  
North West ◽  
The North ◽  
Wet Gas ◽  
Development Concept ◽  
Gas Market ◽  
Geotechnical Studies

The East Spar field is located 40 km west of Barrow Island on the North West Shelf, offshore WA, and con­tains 23.6 G.m3 (834 Bscf) of proven and probable wet gas in-place in the Early Cretaceous Barrow Group. The trap is structural, but with negligible time closure.At the time of the discovery and early appraisal of East Spar in late 1993, a rapid deregulation of the gas market was taking place. In combination with the concept of a gas pipeline to the central WA Goldfields region, a marketing 'window of opportunity' was created for the East Spar field, if the development could be crystallised in the available period of 9 months. This required ap­praisal drilling, geotechnical studies, reservoir engineer­ing and facilities engineering to be advanced on parallel fronts, with close co-ordination and communication be tween all disciplines.The concept of an alliance between the East Spar Joint Venture and the engineering/construction contractors was identified as a way of retaining flexibility to alter the development concept during this period, and provide other benefits during the subsequent construction phase. This alliance was ultimately formed to include represen­tatives from WMC (on behalf of the East Spar Joint Venture (ESJV)), Kvaerner-R J Brown and dough Engi­neering.The East Spar facilities will comprise a subsea comple­tion and gathering system, with all produced fluids being piped to processing facilities on Varanus Island. The treated gas will then be transported to the mainland via the existing sales gas pipeline to the onshore Dampier to Bunbury pipeline, which connects with the Goldfields Gas pipeline. The condensate will be exported from Varanus Island by tanker. First sales are expected in October 1996

THE GOLDFIELDS GAS PIPELINE: 'OPENING A NEW FRONTIER'

1996 ◽  
Vol 36 (1) ◽  
pp. 599
Author(s):  
B.M. Ride
Keyword(s):  
Joint Venture ◽  
Major Effect ◽  
Gas Pipeline ◽  
Liquid Fuels ◽  
Mining Operations ◽  
Simple Method ◽  
North West ◽  
Demand Growth ◽  
The North ◽  
New Frontier

Gas exploration and development in the northwest Pilbara in WA has increased due to the commitment of the Goldfields Gas Transmission Joint Venture to a 1,380 km gas pipeline linking the north west Pilbara to the east Pilbara iron ore region and the northern and central Goldfields. Construction of the GGT pipeline was approved in January 1995 and it is expected the pipeline will be servicing major mining operations in Newman, Mt Keith, Leinster and Kalgoorlie by August 1996. Other existing mining operations located near the pipeline are expected to convert from distillate for power station fuel to gas in 1996-97. Major new mining prospects in these highly prospective minerals provinces also offer potential for increased gas demand and GGT Pipeline throughput.The commercial arrangements for GGT Pipeline services are the first in Australia to be offered under the open access arrangements espoused by the Federal and WA Governments, and have set a benchmark for other pipelines in Australia. The innovative distance related pipeline tariff arrangements offer prospective gas shippers a simple method for evaluating use of the GGT pipeline and securing gas transmission services.The GGT Pipeline has had and will continue to have a major effect on the WA gas scene, stimulating gas exploration by capturing an established base load energy market currently dependent on liquid fuels and stimulating further WA gas demand growth.

NORTH WEST SHELF 3-D SEISMIC—A DECADE OF DEVELOPMENTS

1993 ◽  
Vol 33 (1) ◽  
pp. 315
Author(s):  
P.S. Vaughan
Keyword(s):  
Joint Venture ◽  
Spatial Sampling ◽  
Seismic Surveys ◽  
North West ◽  
The North ◽  
Technological Developments

Woodside as Operator, on behalf of three Joint Venture groups, over the last decade has acquired eight 3-D seismic surveys covering some 4 600 km2 over the Rankin Trend and Dampier Sub-Basin Production Licences and Exploration Permits on the North West Shelf of Australia. This area represents approximately 45 per cent coverage of the present Woodside operated acreage in the area. The acquisition, processing and interpretation technology and also the benefits derived from the 3-D technique have changed remarkably since the first North West Shelf 3-D survey in 1981. This paper focusses on the main technological developments in 3-D seismic, particularly involving multi-source and streamer technology, increased spatial sampling and interpretation techniques which have changed the role of 3-D seismic in Exploration strategies through the 1980s and into the 1990s.

A NEW TECTONO-STRATIGRAPHIC SYNTHESIS OF THE NORTH WEST CAPE AREA

1991 ◽  
Vol 31 (1) ◽  
pp. 154 ◽  
Author(s):  
R.J. Malcolm ◽  
M.C. Pott ◽  
E. Delfos
Keyword(s):  
Seismic Data ◽  
Joint Venture ◽  
Lateral Displacement ◽  
Landsat Imagery ◽  
Block Rotation ◽  
Surface Mapping ◽  
North West ◽  
The North ◽  
Oil Flow ◽  
Transfer Faults

The North West Cape area in the Exmouth Sub-basin was the site of the first onshore oil flow in Australia at Rough Range-1 in 1953. Subsequently, exploration focused on two large surface anticlines, Cape Range and Rough Range. By 1984, 30 unsuccessful wells had made it clear that the subsurface was far more complex than indicated by the surface mapping and limited seismic data. A detailed reappraisal of the subsurface structure and stratigraphy was needed.A joint venture group operated by Ampol Exploration began a new phase of exploration by recording over 1200 km of seismic data, both regional and detailed, between 1985 and 1989. An integrated interpretation of seismic data, well information and Landsat imagery has improved the understanding of structural and stratigraphic complexities and has given direction to the current exploration effort.Five of the most significant tectonic episodes to affect the North West Cape area have been recognised. They are Late Carboniferous and Early Jurassic (Sinemurian) rifting phases, Callovian-Oxfordian and Berriasian-Valanginian syn-rift pulses related to break-up and, finally, structural inversion in the Late Miocene. Each of these episodes is associated with characteristic structural styles and stratigraphic sequences.Significant lateral displacement along transfer faults during Sinemurian rifting and again during the Berriasian- Valanginian syn-rift pulse has resulted in the formation of tear faults that swing westward and merge with the plane of the transfer faults. Fault-block rotation and uplift associated with these tear faults provide potential structural and stratigraphic traps. The influence that transfer faults have on the hydrocarbon prospectivity of the North West Cape area has been recognised, including their role in the distribution of reservoir and source rocks.These tectono-stratigraphic concepts have provided a sound framework for future exploration in the North West Cape area, and may have implications for hydrocarbon prospectivity in other parts of the North West Shelf and on passive margins elsewhere.

US gas pipeline shortage may drive energy diversity

2015 ◽  
Keyword(s):  
Natural Gas ◽  
Gulf Coast ◽  
Gas Production ◽  
Gas Pipeline ◽  
South Texas ◽  
Content Type ◽  
North West ◽  
Natural Gas Pipeline ◽  
North East ◽  
The North

Subject The effects of natural gas pipeline supply constraints in the US North-east. Significance The shale 'revolution' has caused a sharp rise in US natural gas production, but it has been located in areas without gas infrastructure. Production has been concentrated along the Gulf Coast, and the pipeline network is oriented from that region to the North-east and Pacific North-west. Newer areas of energy production, such as Bakken in North Dakota, Eagle Ford in South Texas, and Marcellus in Appalachia, have poor connections to major markets, and constraints have led to pricing spikes in the North-east. Impacts The majority of proposed pipelines for the next several years target areas in the upper Midwest, Mid-Atlantic, and South-east markets. Manufacturers in the North-east will face competitive disadvantage from paying the highest energy costs in North America. Pipeline constraints will not dampen enthusiasm for liquefied natural gas (LNG) exports, especially out of West Coast ports.

scholarly journals Neolithic pits and Late Bronze Age roundhouses in the Upper Ury Valley, Aberdeenshire

2019 ◽  
Vol 148 ◽  
Author(s):  
Richard Moore ◽  
Claire Lingard ◽  
Melanie Johnson ◽  
Ann Clarke ◽  
Mhairi Hastie ◽  
...  
Keyword(s):  
Bronze Age ◽  
Gas Pipeline ◽  
Late Bronze Age ◽  
Early Neolithic ◽  
North West ◽  
The North ◽  
Pipeline Route ◽  
The Bronze Age ◽  
Small Tributary

Archaeological monitoring of works on a gas pipeline route in Aberdeenshire, north-west of Inverurie, resulted in the discovery and excavation of several groups of Neolithic pits and four Bronze Age roundhouses. The Neolithic pits were concentrated around the Shevock Burn, a small tributary of the Ury, and in the East and North Lediken areas to the north. They produced significant assemblages of Early Neolithic Impressed Ware and of Modified Carinated Bowl. The Bronze Age roundhouses included the heavily truncated remains of a post-built structure near Pitmachie, the remains of a pair of ring ditch structures near Little Lediken Farm, and another ring ditch structure close to Wrangham village.

THE DEVELOPMENT OF GORGON AREA GAS

2002 ◽  
Vol 42 (2) ◽  
pp. 113
Author(s):  
I.J. Grose
Keyword(s):  
Natural Gas ◽  
Environmental Performance ◽  
Joint Venture ◽  
Unit Cost ◽  
Clean Energy ◽  
North West ◽  
Design Concepts ◽  
The North ◽  
Competitive Prices ◽  
Exxon Mobil

Australia will increasingly need to turn to natural gas to offset declining oil production and meet an expanding global need for clean energy. The Gorgon Development Joint Venture Participants, (ChevronTexaco/Exxon- Mobil/Shell), are poised to develop the significant Gorgon gas reserves located 130 km offshore the North West Australian coast to help fulfil this need.The Gorgon Development has access to extensive proved reserves of 13.8 Tcf and a development plan that can supply gas to a Barrow Island landfall at world competitive prices. Several concepts are being considered for development of the Gorgon reserves.Technology will play a key role, with the extensive use of subsea production facilities and innovative LNG design concepts being considered.The focus is on a design that would have a low unit cost and also provide new benchmarks in safety and environmental performance. The development of the Gorgon reserves could also facilitate the establishment of other gas-based industries in Western Australia and offers the opportunity for new gas-to-liquid (GTL) plants to lead Australia’s transition to a gas-based economy.The Gorgon Development is expected to attract nearly A$4 billion investment for an LNG development and a further A$2 billion for a major industrial gas consumer. Total export income could reach A$2,500 million per year for 30 years.

HARRIET GAS GATHERING PROJECT, BARROW SUB-BASIN

1992 ◽  
Vol 32 (1) ◽  
pp. 56
Author(s):  
Adrian Williams ◽  
Dave Macey
Keyword(s):  
Offshore Platforms ◽  
Gas Field ◽  
North West ◽  
Associated Gas ◽  
The North ◽  
Wet Gas ◽  
Start Up ◽  
New Development ◽  
Transmission Pipeline ◽  
Gas Fields

Since start-up of Harriet oil production in early 1986, the TL/1 joint venturers have attempted to find a use for the oil-associated gas as well as other gas from neighbouring small gas fields. Initially, supplies from the North West Shelf Project were well in excess of local demand and acted as a damper on new development projects. With time, however, gas reserves in the Harriet area were augmented through new discoveries and the State's demand grew steadily until, in mid 1990, a new project could be justified. In December 1990, an agreement was reached with the State Energy Commission of Western Australia (SECWA) for the supply of 140 PJ (123 BCF) of gas over a ten year period, with an option for a further 65 PJ (57 BCF). First gas supplies are planned for June 1992.The project is based on the supply of Harriet solution gas as well as free gas from the Campbell, Sinbad and Rosette fields. Bambra is a potential future addition but is not required initially for the contract.The project involves small offshore platforms at Campbell and Sinbad, a wet gas pipeline from these platforms to Varanus Island, a facility on the Island to dry the gas and boost the pressure, and a transmission line to SECWA's system, approximately 100 km distant.The transmission pipeline has considerable reserve capacity over the initial contract flowrate of 30 to 60 TJ/day (26 to 52 MMCFGD) and provides a basis for further small gas projects utilising either flare gas from new oil developments or new gas field developments.

‘Back to the Future' A review of Australian reservation and other natural gas export control policies

2019 ◽  
Vol 59 (2) ◽  
pp. 505
Author(s):  
James Plumb
Keyword(s):  
Natural Gas ◽  
Gas Production ◽  
Export Market ◽  
North West ◽  
The North ◽  
History Of ◽  
Gas Market ◽  
The Government ◽  
Regulatory Controls ◽  
Land Reserve

Despite record levels of domestic production, forecasters are predicting that the east coast Australian gas market will remain tight in 2019. The introduction of the Australian Domestic Gas Security Mechanism (ADGSM) by the Federal Government in 2017, and the proposal announced by the Australian Labour Party (ALP) to bolster the mechanism, have again thrust the issue of political intervention in the export gas market into sharp focus. This paper provides an overview of the current regulatory intervention at the state and federal level, and looks back at the history of controls imposed upon the Australian gas export market. The paper is divided into two parts: Part 1, which looks at current regulatory controls engaged by various State and Federal governments: (a) the development and implementation of the ADGSM; (b) the development and implementation of the Queensland Government’s Prospective Gas Production Land Reserve policy (PGPLR); and (c) the Government of Western Australia’s (WA Government) domestic gas policy. The paper also reviews policy announcements made by the ALP in the lead up to the 2019 Federal election. Part 2 provides a broad overview of the history of controls on gas exports in Australia, from the embargo on exports from the North West Shelf between 1973 and 1977, through the increasing liberalisation of Australian energy policy during the 1980s and 1990s (and the associated conflict with state concerns of ensuring sufficiency of the domestic supply of gas), up to the removal of federal controls on resources exports (including liquefied natural gas) in 1997.

LEGENDRE: MATURATION OF A MARGINAL OFFSHORE OIL DISCOVERY TO DEVELOPMENT PROJECT

1999 ◽  
Vol 39 (1) ◽  
pp. 504
Author(s):  
J.M. Willetts ◽  
D.J. Mason ◽  
L. Guerrera ◽  
P. Ryles
Keyword(s):  
Joint Venture ◽  
Development Planning ◽  
Development Project ◽  
Horizontal Drilling ◽  
North West ◽  
The North ◽  
Simulation Techniques ◽  
Production Wells ◽  
Light Oil ◽  
Offshore Oil

Commercialisation of the Legendre hydrocarbon resources represents the culmination of over 30 years of exploration and appraisal and more recent development planning, following the discovery by the first well to be flow-tested on the North West Shelf, Legendre–1, in 1968. By application of 3D seismic, reservoir modelling and simulation techniques, horizontal drilling and innovative development options, the WA-l-P Joint Venture is confident of achieving an economic return on a relatively small resource base.The two separate accumulations, Legendre North and Legendre South, are together expected to contain some 14 million m3 (90 MMSTB) of oil-in-place. The oil column in the northern accumulation is 45 m at its maximum, whilst a 20 m column is present in the southern accumulation. Reservoir quality is generally very good with mostly massive sandstones with little or no internal stratification. The reservoir contains a light oil and aquifer support is expected from communication with the underlying Angel Formation sandstones.The subsurface development plan has been designed to optimise the recovery of the oil in place in the two accumulations. Production wells with horizontal sections of 750 m will be used to minimise drawdown and ensure good sweep. Production is expected at a plateau rate of 4,800 to 6,400 m3/d (30−40,000 BOPD). Produced gas will be disposed of by means of a re-injection well downdip of the producers.

PERTH BASIN REJUVENATED

1992 ◽  
Vol 32 (1) ◽  
pp. 33 ◽  
Author(s):  
Peter B. Hall ◽  
Robert L. Kneale
Keyword(s):  
Natural Gas ◽  
Western Australia ◽  
Market Access ◽  
Field Size ◽  
Gas Field ◽  
North West ◽  
The North ◽  
New Concepts ◽  
Technological Developments ◽  
Gas Market

The northern Perth Basin is an area where recent seismic advances combined with new geological insight, have led to exploration success with a significant new gas field discovery at Beharra Springs and a number of other minor discoveries. This paper outlines 'new concepts' with regard to stratigraphy and structure and how this has been balanced with the commercial environment to rejuvenate exploration in the northern Perth Basin. The Perth Basin is unique in Australia, as running through the middle of the Basin is the West Australian Natural Gas (WANG) pipeline which will be operating at approximately 26 per cent of its capacity in 1992. With the deregulation of the natural gas market in 1988, supply of gas to the Western Australian market via the State Energy Commission of Western Australia (SECWA) pipeline from the Carnarvon Basin, and in particular, the North West Shelf project, can now be balanced with supply from the onshore Perth Basin carried by the WANG pipeline.The minimum economically viable gas field in the northern Perth Basin is calculated to be 15 BCF (16.05 PJ) and the expected median field size is 50 BCF (53.5 PJ) of recoverable gas. Based on the historical success rate of one in eight, typical finding costs are 12 c/MCF (12 c/GJ).In the 1990/91 financial year, eight onshore exploration wells were drilled in Western Australia of which five were drilled in the northern Perth Basin. Provided the market access and opportunities remain, it is anticipated that the recent technological developments will sustain exploration and development of the onshore northern Perth Basin.

Sign in / Sign up

Export Citation Format

Share Document