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.

JOHN BROOKES GAS FIELD DEVELOPMENT

2005 ◽  
Vol 45 (1) ◽  
pp. 13
Author(s):  
A.J. McDiarmid ◽  
P.T. Bingaman ◽  
S.T. Bingham ◽  
B. Kirk-Burnnand ◽  
D.P. Gilbert ◽  
...  
Keyword(s):  
Low Cost ◽  
Time Frame ◽  
Gas Production ◽  
Gas Field ◽  
Initial Development ◽  
North West ◽  
Field Development ◽  
The North ◽  
Production Wells ◽  
Development Approach

The John Brookes gas field was discovered by the drilling of John Brookes–1 in October 1998 and appraisal drilling was completed in 2003. The field is located about 40 km northwest of Barrow Island on the North West Shelf, offshore West Australia. The John Brookes structure is a large (>90 km2) anticline with >100 m closure mapped at the base of the regional seal. Recoverable sales gas in the John Brookes reservoir is about 1 Tcf.Joint venture approval to fast track the development was gained in January 2004 with a target of first gas production in June 2005. The short development time frame required parallel workflows and use of a flexible/low cost development approach proven by Apache in the area.The John Brookes development is sized for off-take rates up to 240 TJ/d of sales gas with the development costing A$229 million. The initial development will consist of three production wells tied into an unmanned, minimal facility wellhead platform. The platform will be connected to the existing East Spar gas processing facilities on Varanus Island by an 18-inch multi-phase trunkline. Increasing the output of the existing East Spar facility and installation of a new gas sweetening facility are required. From Varanus Island, the gas will be exported to the mainland by existing sales gas pipelines. Condensate will be exported from Varanus Island by tanker.

THE ROLE OF AMPLITUDE VERSUS OFFSET TECHNOLOGY IN PROMOTING OFFSHORE PETROLEUM EXPLORATION IN AUSTRALIA

2007 ◽  
Vol 47 (1) ◽  
pp. 163 ◽  
Author(s):  
P. E. Williamson ◽  
F. Kroh
Keyword(s):  
Petroleum Exploration ◽  
Gas Field ◽  
North West ◽  
Preliminary Results ◽  
Exmouth Plateau ◽  
The North ◽  
Amplitude Versus Offset ◽  
Cable Lines ◽  
The Cost ◽  
Amplitude Versus

Amplitude versus offset (AVO) technology has proved itself useful in petroleum exploration in various parts of the world, particularly for gas exploration. To determine if modern AVO compliant processing could identify potential anomalies for exploration of open acreage offshore Australia, Geoscience Australia reprocessed parts of four publicly available long cable lines. These lines cover two 2006 acreage release areas on the Exmouth Plateau and in the Browse Basin on the North West Shelf. An earlier study has also been done on two publicly available long cable lines from Geoscience Australia’s Bremer Basin study and cover areas from the 2005 frontier acreage release on the southern margin. The preliminary results from these three reprocessing efforts produced AVO anomalies and were made publicly available to assist companies interested in assessing the acreage. The results of the studies and associated data are available from Geoscience Australia at the cost of transfer.The AVO data from the Exmouth Plateau show AVO anomalies including one that appears to be at the Jurassic level of the reservoir in the Jansz/Io supergiant gas field in adjacent acreage to the north. The AVO data from the Caswell Sub-basin of the Browse Basin show an AVO anomaly at or near the stratigraphic zone of the Brecknock South–1 gas discovery to the north. The geological settings of strata possibly relating to two AVO anomalies in the undrilled Bremer Basin are in the Early Cretaceous section, where lacustrine sandstones are known to occur. The AVO anomalies from the three studies are kilometres in length along the seismic lines.These preliminary results from Geoscience Australiaand other AVO work that has been carried out by industry show promise that AVO compliant processing has value—particularly for gas exploration offshore Australia—and that publicly available long-cable data can be suitable for AVO analysis.

DEMETER HIGH RESOLUTION 3D SEISMIC SURVEY—REVITALISED DEVELOPMENT AND EXPLORATION ON THE NORTH WEST SHELF, AUSTRALIA

2006 ◽  
Vol 46 (1) ◽  
pp. 101 ◽  
Author(s):  
K.J. Bennett ◽  
M.R. Bussell
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
New Technologies ◽  
Seismic Survey ◽  
Future Application ◽  
3D Seismic ◽  
Gas Field ◽  
North West ◽  
The North ◽  
Exploration And Development

The newly acquired 3,590 km2 Demeter 3D high resolution seismic survey covers most of the North West Shelf Venture (NWSV) area; a prolific hydrocarbon province with ultimate recoverable reserves of greater than 30 Tcf gas and 1.5 billion bbls of oil and natural gas liquids. The exploration and development of this area has evolved in parallel with the advent of new technologies, maturing into the present phase of revitalised development and exploration based on the Demeter 3D.The NWSV is entering a period of growing gas market demand and infrastructure expansion, combined with a more diverse and mature supply portfolio of offshore fields. A sequence of satellite fields will require optimised development over the next 5–10 years, with a large number of wells to be drilled.The NWSV area is acknowledged to be a complex seismic environment that, until recently, was imaged by a patchwork of eight vintage (1981–98) 3D seismic surveys, each acquired with different parameters. With most of the clearly defined structural highs drilled, exploration success in recent years has been modest. This is due primarily to severe seismic multiple contamination masking the more subtle and deeper exploration prospects. The poor quality and low resolution of vintage seismic data has also impeded reservoir characterisation and sub-surface modelling. These sub-surface uncertainties, together with the large planned expenditure associated with forthcoming development, justified the need for the Demeter leading edge 3D seismic acquisition and processing techniques to underpin field development planning and reserves evaluations.The objective of the Demeter 3D survey was to re-image the NWSV area with a single acquisition and processing sequence to reduce multiple contamination and improve imaging of intra-reservoir architecture. Single source (133 nominal fold), shallow solid streamer acquisition combined with five stages of demultiple and detailed velocity analysis are considered key components of Demeter.The final Demeter volumes were delivered early 2005 and already some benefits of the higher resolution data have been realised, exemplified in the following:Successful drilling of development wells on the Wanaea, Lambert and Hermes oil fields and identification of further opportunities on Wanaea-Cossack and Lambert- Hermes;Dramatic improvements in seismic data quality observed at the giant Perseus gas field helping define seven development well locations;Considerably improved definition of fluvial channel architecture in the south of the Goodwyn gas field allowing for improved well placement and understanding of reservoir distribution;Identification of new exploration prospects and reevaluation of the existing prospect portfolio. Although the Demeter data set has given significant bandwidth needed for this revitalised phase of exploration and development, there remain areas that still suffer from poor seismic imaging, providing challenges for the future application of new technologies.

FORMATION EVALUATION IN HIGHLY-DEVIATED, LONG REACH DEVELOPMENT WELLS ON THE NORTH RANKIN GAS FIELD, NW SHELF, AUSTRALIA

1990 ◽  
Vol 30 (1) ◽  
pp. 310
Author(s):  
D. Lasserre
Keyword(s):  
Drilling Fluid ◽  
Drill Pipe ◽  
Vertical Resolution ◽  
Gas Field ◽  
Log Data ◽  
Formation Evaluation ◽  
North West ◽  
The North ◽  
Reservoir Description ◽  
Resistivity Log

A large proportion of the North West Shelf development gas wells are long reach (greater than 3500 m) and highly deviated. For reservoir description and management purposes, comprehensive formation evaluation needs to be carried out in these wells.Considerable difficulties have been encountered with electric log data acquisition due to friction and borehole conditions in these long, highly-deviated wells. As a result, new techniques to log the zones of interest were introduced. A system using the drill pipe to transport the downhole logging tools has been successfully used.Also, low-toxicity oil-based mud (LTM) was introduced in order to ease drilling problems and borehole conditions. However, owing to the non-conductive nature of the oil-based drilling fluid, improvements were required in the vertical resolution of the resistivity measurements and the estimation of the formation porosity.A computer program using a forward deconvolution technique recently developed by Shell's research laboratory in Holland has been successfully applied to enhance the vertical resolution of the resistivity log reading.The large range of uncertainty on the pore volume has been reduced to reasonable level by calibrating the porosity log data against core data obtained in a well drilled with LTM.

Production and development across Australia 2016

2017 ◽  
Vol 57 (2) ◽  
pp. 363
Author(s):  
Frankie Cullen
Keyword(s):  
Coalbed Methane ◽  
East Coast ◽  
Price Volatility ◽  
Volatile Oil ◽  
Gas Production ◽  
North West ◽  
The North ◽  
Start Up ◽  
Reduction Strategies ◽  
Gas Supply

In 2016, sustained depressed and volatile oil prices led companies to continue cost reduction strategies. Proposed developments have seen delays and reductions in scope as a result. Australian oil production declined by around 10%. However, new and continued liquefied natural gas (LNG) production bolstered both Australian and global gas supply. Australia was the strongest contributor to global LNG growth in 2016, showing the biggest year-on-year increase. In the first half of 2016, 20% of global LNG came from Australia, second only to Qatar with 29% of the market share. Australia remains on track to become the world’s largest LNG producer in the next 3–5 years. 2016 saw the start-up of Gorgon LNG in March, the first of Chevron’s two North West Shelf LNG projects and the third of several producing, developing and proposed LNG projects within the North Carnarvon Basin – already Australia’s most prolific producing basin. On the east coast, development of the coalbed methane (CBM) to LNG projects continued with an additional train brought onstream at each of the Origin/ConocoPhillips-operated APLNG Project and Santos’ GLNG Project. This further increased production in the Bowen–Surat Basins and drove discussions around the ability of east coast gas to meet both the demands of the LNG projects and ensure continued domestic gas reliability. Additional gas may be required for both, opening opportunities for production from other basins. Gas production continues to drive the Australian industry, with substantial inputs from LNG and unconventional operations. The next phase, in all sectors, will be key to Australia’s future in the global energy market. Will it be able to overcome the expected challenges of global oversupply, continued price volatility and domestic reliability concerns to fulfil its potential?

DEVELOPMENT OF THE NORTH RANKIN FIELD, NORTH WEST SHELF, AUSTRALIA

1983 ◽  
Vol 23 (1) ◽  
pp. 164
Author(s):  
M. David Agostini
Keyword(s):  
Seismic Survey ◽  
Process Equipment ◽  
Two Phase ◽  
Gas Field ◽  
North West ◽  
The North ◽  
Christmas Trees ◽  
High Level ◽  
Inflow Performance ◽  
Standard Steel

The North Rankin gas field discovered in 1971, has been evaluated by a series of appraisal wells and refinement of this is underway through the use of a 3D seismic survey. Extensive production testing on two wells was used to establish reservoir fluid characteristics, inflow performance and to predict reservoir behaviour.The North Rankin 'A' platform has been constructed of a standard steel jacket design. Components of the structure were built in Japan, Singapore, Geraldton, Jervoise Bay and Adelaide. Provision exists for 34 wells to be drilled from the structure to exploit the southern end of the North Rankin field.Simultaneous drilling and producing activities are planned, requiring well survey and deviation control techniques that will provide a high level of confidence. Wells will be completed using 7 inch tubing, fire resistant christmas trees, and are designed to be produced at about 87 MMSCFD on a continuous basis. Process equipment on this platform is designed to handle 1200 MMSCFD and is intended primarily to dry the gas and condensate and to transfer gas and liquid to shore in a two phase 40 inch pipeline. The maintenance of offshore equipment is being planned to maximise the ratio between planned and unplanned work.The commencement of drilling activities is planned for mid 1983, with commissioning of process equipment occurring in the second quarter of 198 The North Rankin 'A' platform will initially supply the WA market at some 400 MMSCFD offshore gas rate, requiring 7 wells. The start of LNG exports is planned for April 1987. The intial gas for this will be derived from the North Rankin 'A' platform.

A long history of wet gas pipelines in Victoria

2015 ◽  
Vol 55 (2) ◽  
pp. 415
Author(s):  
Steve Henzell
Keyword(s):  
Oil And Gas ◽  
Gas Pipelines ◽  
Gas Field ◽  
Initial Development ◽  
The North ◽  
Wet Gas ◽  
Industry Practice ◽  
Offshore Oil And Gas ◽  
The 1960S ◽  
Marginal Field

Australia's relative isolation and the harsh environment in Bass Strait have led to many innovations in offshore oil and gas developments. The initial developers were moving into frontier territory when Bass Strait was developed, with the harsh sea state and the water depths presenting major challenges. The original development of Bass Strait in the 1960s was tied to a wet gas pipeline philosophy, which was a novel step-out from normal industry practice. For example, the North Sea developments, which started shortly after Bass Strait, adopted dry gas export pipelines and required substantially larger platforms to process the gas for export. The cold waters of Bass Strait require an active hydrate management strategy and the success of hydrate inhibitors has been a key element in using wet gas pipelines. The initial development relied on methanol for hydrate inhibition, but this changed to a glycol-based hydrate inhibitor within 10 years of production start-up, due to challenges in the onshore production facilities. The use of mono-ethylene glycol for management of wet gas pipelines was demonstrated in Bass Strait. The success of the initial developments has given operators the confidence to pursue marginal field developments that rely on wet gas transport to the beach. The Minerva, Casino, Thylacine and Longtom gas field developments in Bass Strait have all adopted the same strategy, in part because of the confidence provided from operating the initial developments for many years.

THE DEVELOPMENT AND EARLY PERFORMANCE OF THE NORTH RANKIN FIELD

1986 ◽  
Vol 26 (1) ◽  
pp. 420
Author(s):  
F.M. Posaner ◽  
W.H. Goldthorpe
Keyword(s):  
Liquefied Natural Gas ◽  
Processing Capacity ◽  
Domestic Consumption ◽  
Gas Field ◽  
North West ◽  
The North ◽  
And Performance ◽  
Early Performance ◽  
Current Stage ◽  
Gas Recycling

The North Rankin gas field is the first field to be developed as part of the North West Shelf Project and has now been on stream for some two years. With a most likely gas-initially-in-place of 11TCF (308 × 109 m3), it is the largest appraised gas-condensate field in Australia.At the current stage, gas is being produced from one platform (the North Rankin 'A' platform) entirely for domestic consumption. Future development involves the drilling of additional wells to provide gas for export as liquefied natural gas (LNG) to Japan, installation of a second platform, and construction of an additional onshore plant to manufacture the LNG. In addition, a gas recycling project is to be implemented on the North Rankin 'A' platform to increase the recovery of condensate by utilizing spare platform processing capacity available prior to reaching plateau LNG exports.The present paper reviews the development and performance of this major field over the first two years of its producing life. Emphasis is placed on the reservoir pressure performance, particularly in relation to the reservoir geology.

UPPER PERMIAN CARBONATE RESERVOIRS OF THE NORTH WEST SHELF AND NORTHERN PERTH BASIN, AUSTRALIA

1999 ◽  
Vol 39 (1) ◽  
pp. 343 ◽  
Author(s):  
J.D. Gorter ◽  
J.M. Davies
Keyword(s):  
Oil And Gas ◽  
Upper Permian ◽  
Gas Reservoirs ◽  
Secondary Porosity ◽  
North West ◽  
Associated Gas ◽  
The North ◽  
Timor Sea ◽  
Primary Porosity ◽  
Carnarvon Basin

The Perth, Carnarvon, Browse, and Bonaparte basins contain Permian shallowmarine carbonates. Interbedded with clastic oil and gas reservoirs in the northern Perth Basin (Wagina Formation), and gas reservoirs in the Bonaparte Basin (Cape Hay and Tern formations), these carbonates also have the potential to contain significant hydrocarbon reservoirs. Limestone porosity may be related to the primary depositional fabric, or secondary processes such as dolomitisation, karstification, and fracturing. However, in the Upper Permian interval of the North West Shelf and northern Perth Basin, where there are no indications of significant preserved primary porosity in the limestones, all known permeable zones are associated with secondary porosity. Fractured Permian carbonates have the greatest reservoir potential in the Timor Sea. Tests of fractured Pearce Formation limestones in Kelp Deep–1 produced significant quantities of gas, and a test of fractured Dombey Formation limestone in Osprey–1 flowed significant quantities of water and associated gas. Minor fracture porosity was associated with gas shows in dolomitic limestones in Fennel–1 in the Carnarvon Basin, and fractures enhance the reservoir in the Woodada Field in the northern Perth Basin. Karst formation at sub-aerial unconformities can lead to the development of secondary porosity and caverns, as in the Carnarvon Basin around Dillson–1. Minor karst is also developed at the top Dombey Formation unconformity surface in the Timor Sea region.

Early Production Life of Wheatstone Project Offshore Australia Yields Key Lessons

2021 ◽  
Vol 73 (08) ◽  
pp. 51-52
Author(s):  
Chris Carpenter
Keyword(s):  
Oil And Gas ◽  
Asia Pacific ◽  
North West ◽  
The North ◽  
Sand Control ◽  
Single Well ◽  
Early Production ◽  
Northern Carnarvon Basin ◽  
Shelf Region ◽  
Gas Fields

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202246, “Wheatstone: What We Have Learned in Early Production Life,” by John Pescod, SPE, Paul Connell, SPE, and Zhi Xia, Chevron, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Wheatstone and Iago gas fields, part of the larger Wheatstone project, commenced production in June 2017. The foundation subsea system includes nine Wheatstone and Iago development wells tied back to a central Wheatstone platform (WP) for processing. Hydrocarbons then flow through an export pipeline to an onshore processing facility that includes two liquefied-natural-gas (LNG) trains and a domestic gas facility. The complete paper highlights some of the key learnings in well and reservoir surveillance analysis and optimization (SA&O) developed using data from early production. Asset Overview Chevron Australia’s Wheatstone project is in the North West Shelf region offshore Australia (Fig. 1). Two gas fields, Wheatstone and Iago (along with a field operated by a different company), currently tie into the WP in the Northern Carnarvon Basin. These two gas fields are in water depths between 150 and 400 m. The platform processes gas and condensate through dehydration and compression facilities before export by a 220-km, 44-in., trunkline to two 4.45-million-tonnes/year LNG trains and a 200 tera-joule/day domestic gas plant. A Wheatstone/Iago subsea system consisting of two main corridors delivers production from north and south of the Wheatstone and Iago fields to the WP. Currently, the subsea system consists of nine subsea foundation development wells, three subsea production manifolds, two subsea 24-in. production flowlines, and two subsea 14-in. utility lines. The nine foundation development wells feed the subsea manifolds at rates of up to 250 MMscf/D. These wells have openhole gravel-pack completions for active sand control and permanent downhole gauges situated approximately 1000-m true vertical depth above the top porosity of multi-Darcy reservoir intervals for pressure and temperature monitoring. All wells deviate between 45 and 60° through the reservoir with stepout lengths of up to 2.5 km. The two subsea 24-in. production flowlines carry production fluids from the subsea manifolds to two separation trains on the WP. Each platform inlet production separator can handle up to 800 MMscf/D. The two 14-in. utility flowlines installed to the subsea manifolds allow routing of a single well to the platform multiuse header, which can direct flow into the multiuse separator (MUS) or other production separators at a rate of 250 MMscf/D.

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