Western Australia is Australia’s number one petroleum producer with 67 per cent of crude oil and condensate production, and 69 per cent of natural gas production in 2007.
With such a large number of developing projects comes the need for infrastructure to support the projects, including transmission lines between gas fields and end users.
The development of WA pipeline infrastructure
The Dongara field, located in the Perth Basin, was discovered in 1966 by WAPET. The field was discovered to have 480 PJ of recoverable gas and approximately 100 MMbbl of oil. The discovery of the oil field spurred the construction of the 420 km Dongara to Pinjara Pipeline, which connected the gas field to Perth. Construction of the pipeline was completed in 1971 and the pipeline is now owned by APA Group and known as the Parmelia Pipeline.
In the north of Western Australia, the North West Shelf Venture is Australia’s largest natural resources development, producing gas for Western Australia’s domestic market and gas, condensate and oil for export from its offshore gas and oil fields.
The $25 billion North West Shelf project delivered its first LNG cargoes to Japan in 1989, and it now ships more than 200 cargoes a year to customers around the world including Japan, China, and South Korea.
After almost 25 years of pipeline gas production, the venture remains Western Australia’s largest single producer of domestic gas providing about 65 per cent of total State production. Pipeline gas is processed at its Karratha facility.
The North West Shelf Venture is underpinned by huge gas reserves, with only 11 Tcf of 33 Tcf total reserves produced to date.
A major feature of the Western Australian energy industry is the Dampier to Bunbury Natural Gas Pipeline (DBNGP) that links gas fields on the North West Shelf to the southwest of Western Australia. The pipeline supplies 90 per cent of the southwest’s gas needs.
Construction of the more than 1,500 km pipeline began in 1983 and was completed in 1984. The pipeline has continued to expand through looping and compression in order to keep up with Western Australia’s growing energy needs. Originally built by the State Energy Commission of Western Australia, the pipeline is now owned by Dampier Bunbury Pipeline.
A 104 km sub-sea pipeline running from the North Rankin “˜A’ platform to Dampier as part of the North West Shelf development was constructed in tandem with the DBNGP, reaching completion in 1983. The pipeline delivers North West Shelf gas to shore.
Following the completion of the DBNGP, major pipeline construction did not recommence in the State until the 90s and largely focused around supplying gas to remote Western Australian industry.
In 1995, Clough completed the 214 km Karratha to Port Hedland gas pipeline for Pilbara Energy. The pipeline was the first stage of a project designed to provide energy for BHP Iron Ore’s then existing operations and planned downstream processing in the Pilbara region.
The 1,380 km long Goldfields Gas Pipeline was completed in 1996. Running through the centre of Western Australia, the pipeline supplies more than a dozen mines between Yarraloola in the Pilbara and Kambalda, along with the township of Kalgoorlie.
Since 2000, new compression facilities have been added to expand the pipe’s capacity. 2004 saw the construction of the 340 km Kambalda to Esperance Pipeline, owned by the Esperance Pipeline Company.
The 365 km Midwest Pipeline was constructed in 1999 and carries natural gas from Geraldton to the Windimurra Vanadium mine in Windimurra.
The 443 km Telfer Natural Gas Pipeline that runs from Port Hedland to the Telfer gold mine operated by Newcrest Mining in north Western Australia completed construction in 2004. The APA Group-owned pipeline is underwritten by a long-term gas transportation agreement with Newcrest Mining. In 2005, a 45 km lateral was constructed from the Telfer pipeline to the Nifty gold and copper mine, which fired the expansion of Nifty’s operations at the mine.
The present: project possibilities
While pipeline construction in Western Australia has recently focused on supplying gas to industrial users, the current number of gas field development proposals has meant that pipeline construction in the state is leaning towards linking gas fields with existing infrastructure.
While Western Australia already relies heavily on the North West Shelf for its needs, a number of other developments that will spur the construction of pipelines have been planned for the resource-rich area.
In particular, LNG developments continue to progress, with Woodside’s $12 billion Pluto Gas Project, the largest of all major and advanced energy projects. In addition, a number of very large LNG projects including the Browse, Gorgon, Ichthys and Sunrise projects are continuing to progress.
Recently, there has been some concern about the economics of developing large LNG projects with the removal of the excise exemption on condensate, which meant that all condensate production from fields located in the North West Shelf project area and onshore Australia would be subject to the excise.
The North West Shelf Venture (NWSV) said that its principal concerns are that the project requires continued substantial investment to underpin safe and reliable operations; and, Australian fiscal arrangements need to be sufficiently stable to attract such investment.
In addition, the NWSV said the surprising way that this change was announced has unnecessarily detracted from Australia’s reputation as an attractive and stable investment destination by introducing a new element of sovereign risk not previously seen in this industry in Australia.
Common-user LNG hub
The Western Australian and Federal governments plan to establish a common-user LNG hub to minimise the impact that future development has on the Kimberley’s natural and cultural heritage.
The governments, through the Northern Development Taskforce, have identified nine possible sites for a common-user LNG processing hub to serve the Browse Basin, four of which the Kimberley Traditional Owners believe are suitable for development.
Following a consultation process with fourteen different Native Title groups, Traditional Owners have said that they are willing to consider Gourdon Bay, James Price Point, North Head, and Anjo Peninsula for further discussion in selecting a final location for development.
If the project goes ahead it will involve great opportunity for the pipeline industry to link Western Australia’s gas fields into the common-user hub.
Gorgon and Wheatstone developments
Another proposed project that attempts to mitigate its effect on the environment is the Gorgon LNG joint venture between Chevron, Shell and ExxonMobil. The development involves the installation of a sub-sea gathering system and pipelines from the Gorgon and Jansz fields to Barrow Island. A 300 TJ/d gas processing facility located on the central-east coast of Barrow Island would process the gas and reservoir carbon dioxide would be removed and re-injected into deep saline reservoirs beneath the island.
LNG is then to be shipped to international markets while compressed domestic gas would be delivered via a sub-sea pipeline to the Western Australian mainland. The Gorgon project is located approximately 130 km off the northwest coast of Western Australia.
The venture recently extended the front-end engineering and design contract to the Kellogg joint venture – made up of KBR, JGC Corporation, Clough Projects Australia and Hatch Associates Group – to incorporate a third 5 MMt/a LNG train to be developed at the same time as the original two.
In March, Chevron announced plans to develop a new LNG project, based on its Wheatstone natural gas discovery, located 145 km offshore in the Carnarvon Basin.
The facility would be located on the northwest coast of mainland Australia and have initial capacity of at least two 5 MMt/a LNG production train with expansion capacity for an additional three production trains. The facility would also involve a 220 km pipeline and a 250 MMcf/d domestic gas plant.
Pluto Gas Project
The Pluto LNG Project is being undertaken by a joint venture between Woodside, the Kansai Electric Power Company and Tokyo Gas Company. As part of the project, gas from the Pluto and Xena fields will be developed and transported through a sub-sea 180 km, 36 inch diameter pipeline to an LNG plant where it will be used for domestic gas supply as well as being liquefied and shipped to customers in Japan.
The development, is located approximately 190 km northwest of Karratha. J Ray McDermott has been awarded the construction of the offshore platforms, and Acergy has been awarded the contract to install sub-sea tie-ins and flowlines for the project.
The construction of the LNG modules and storage tanks for the Pluto Gas Project, has commenced in Thailand. The company also said that shore crossing preparation works are completed and the construction of the jetty has commenced.
Woodside is currently in discussions with potential contractors about the engineering, procurement and construction management contract for a second LNG train for the Pluto development. An investment decision on the second train is expected by the end of the year.
North West Shelf Venture
Joint venture participants Woodside, BHP Billiton, BP Developments Australia, Chevron Australia, Japan Australia LNG and Shell Development reached a significant milestone with the expansion of their North West Shelf Venture project following the start up of operation and production of LNG for export from the fifth LNG processing train early in September.
The ongoing expansion will increase the production capacity by 4.4 MMt/a to 16.3 MMt/a of LNG.
Earlier in the year, the venture contracted J Ray McDermott subsidiary PT McDermott Indonesia to construct the North Rankin B platform substructure and piles.
The North Rankin redevelopment project will provide additional compression to unlock low pressure reserves from the North Rankin and Perseus gas and condensate fields off Karratha, Western Australia.
The platform will be connected by a 100 m bridge to the existing North Rankin A platform. The NR2 Project will also include necessary tie-ins and refurbishment of North Rankin A. Upon completion, both platforms will be operated as a single integrated facility.
North Rankin is located in 125 m of water, approximately 135 km offshore from Karratha on the northwest coast of Western Australia. Production from the North Rankin and Perseus fields started in 1984 and the mid-1990s respectively.
In addition, the Angel Gas Field achieved mechanical completion in August. The development included the North West Shelf Venture’s third fixed platform that will be remotely operated, three wells, and a 49 km pipeline to join an existing offshore trunkline to shore. Following scheduled maintenance at LNG train 4, first gas production commenced in late September.
Browse Basin LNG developments
In May, Woodside contracted a joint venture between Technip, Chiyoda and Fluor to study a design concept for the Browse LNG Development, which is located 425 km northwest of Broome in Western Australia.
The project involves development of the Brecknock, Brecknock South and Tarosa fields, estimated to contain reserves of over 20 Tcf of gas and 300 MMbbl of condensate. Woodside is looking to develop Browse as Western Australia’s second LNG production hub with a site for the development focused on two options – Kimberley or Burrup.
In addition, joint venture partners Karoon Gas and CononoPhillips are looking to discover 7 Tcf of gas for the sanction of a possible LNG project in the Browse Basin, which would involve the construction of a 1,000 km natural gas pipeline.
The pipeline would run through the Timor Sea to connect to the Browse Basin to an onshore LNG plant.
Should the project reach sanction, first liquids and LNG is expected on the market by approximately 2015.
Also in located in the Browse Basin, the Western Australian Government has found itself in a tug-of-war with the Northern Territory over Inpex’ proposed $12 billion Ichthys LNG Project.
Inpex and Total E&P are considering developing an LNG facility either in Darwin or the Maret Islands. The two sites would both require long pipelines from the field, with Darwin located 850 km from Ichthys, and the Maret Islands located 190 km from the Ichthys field.
Reindeer and Julimar gas fields
Apache Energy and Santos are progressing the development of their Reindeer Gas Field, located in offshore permit WA-209-P, approximately 80 km off the Port of Dampier. The field, discovered in 1997, has a gross recoverable resource range of 410 – 640 PJ. Gas and liquids from the field will be exported from an unmanned wellhead platform to the proposed Devil Creek Gas Plant via a single 105 km pipeline.
The Devil Creek Gas Plant will connect to the DBNGP. The proposed production capacity of the plant is approximately 110 TJ/d of sales gas with first gas targeted for mid-2010. Clough has been awarded the engineering, procurement and construction contract for the gas plant in addition to a $200 million contract for the installation of the Reindeer offshore facilities.
Apache is also conducting conceptual engineering for its Julimar Gas Field, also located in the Carnarvon Basin. The Julimar development would involve an approximately 100 km long pipeline to be constructed from the field to the Devil Creek Gas Plant.
The company plans to have the Julimar and Reindeer discoveries coming to the market with the Australian natural gas price up from last year due to the growth of the domestic mining industry and the LNG export market.
Mt Gibson pipelines
Mt Gibson Iron plan to construct water, gas and ore slurry pipelines, which will service a mine currently being developed at Extension Hill, Mt Gibson.
The pipeline corridor will include a 400 mm steel slurry pipeline from the mine to the port at Geraldton, a 450 mm polyethylene water main to carry water back from Geraldton to the mine site, and a 250 mm steel gas pipeline from the DBNGP to the mine, where a 35 MW gas powered power station will be installed.
Mt Gibson Iron has completed a definitive feasibility study and environmental approval has been received, with the Mount Gibson board approving the commencement of construction of the entire project.
Dampier to Bunbury Natural Gas Pipeline
Earlier in the year, Dampier Bunbury Pipeline completed the Stage 5A expansion on the DBNGP, while also announcing the Stage 5B expansion.
Construction of the Stage 5A expansion, which increased firm full haul capacity by approximately 100 TJ/d, commenced in February 2007 and involved the installation of 570 km of parallel pipe effectively duplicating 50 per cent of the DBNGP mainline.
The decision to commence the Stage 5B expansion came after receiving additional firm capacity requests from existing and prospective shippers, and DBP was encouraged by new domestic gas developments such as the Reindeer, Julimar, Pluto, Wheatstone and Gorgon fields. The company said that future pipeline expansion may be required by 2011-12 when a number of these developments are targeted for completion.
The new firm capacity requests totalled approximately 75 TJ/d of firm full haul capacity and 125 TJ/d of part haul capacity and will be required by shippers from 2010.
DBP said that Stage 5B will involve a further 440 km of looping, which, when completed, would result in the DBNGP system being more than 75 per cent duplicated. Construction of the expansion project is planned to begin in 2009.
At the time of going to print, work was well advanced on project engineering, approvals and procurement for the Stage 5B expansion. The coating of linepipe was in progress with first deliveries anticipated in December and final pipelaying tenders were being assessed.
Varanus Island incident
Following an incident at Apache Energy’s Varanus Island facility in June, partial gas supply recommenced from the East Spar processing facilities in August with pre-incident rates of production expected by the end of 2008.
A pipeline rupture caused an explosion at the facility, which is located approximately 116 km west of Dampier. Varanus Island is an oil, condensate and gas processing hub for a number of North West Shelf offshore platforms and supplies 30 per cent of Western Australia’s domestic gas supply, with the vast majority of its customers being industrial users.
While the DBNGP was capable of meeting all its contracted obligations, APA Group said that the incident disrupted gas supplies to the Goldfields Gas Pipeline and the Telfer Gas Pipeline.
The incident resulted in the total cessation of production from the John Brookes Gas Field, since gas from the field is processed on Varanus. The field recommenced production in August.
The DBNGP increased its shipments of gas from the North West Shelf joint venture facilities on the Burrup Peninsula by more than 25 per cent in an attempt to cover Western Australia’s gas supply issues, and DBP permanently staffed the three northern-most compressor stations to maximise gas delivery.
The Western Australian Chamber of Commerce and Industry said that the disruption exposed the state’s dependence on a limited number of gas production plants and highlighted the need to implement policies that encourage the development of a more diverse primary fuel base.
The future for WA
The Chamber of Minerals and Energy Western Australia has said that the state has a large energy consumption as a consequence of general economic expansion and the growth in mineral processing and extraction, but also has become a substantial energy exporter. Because of this, the Chamber has noted that, in the longer term, Western Australia must find a balance between ensuring the security of energy supply to meet the ongoing needs of the expanding domestic economy, while also facilitating the growth in energy exports.
Former Deputy Premier Eric Ripper outlined managing the retention of leases, as well as future LNG, tight gas and coal seam gas (CSG) projects as bolstering the state’s energy demand.
Mr Ripper said “There has recently been renewed interest in onshore exploration in the area north of Perth and also in the Canning basin.
“Such onshore development also has potential to help ensure Western Australia meets its domestic gas needs, with onshore developments more likely to feed into the domestic gas market.”
Companies such as Arc Energy, New Standard Exploration, Australian Worldwide Exploration (AWE) and Emerald Oil and Gas are currently exploring permits in this area. Arc has proposed a 630 km pipeline to run from east of Broome to the Pilbara to deliver gas from its Canning Basin permits. The Great Northern Pipeline construction was initially to commence in April/May 2009 with gas deliveries to market commencing in mid-2010, however Arc’s merger with AWE has seen progress on the pipeline slow.
In addition, the new Western Australian Government has said that it will construct a $225 million natural gas pipeline from Bunbury to Albany via Bridgetown and Manjimup, following its election win.
The proposed South West Pipeline will measure 200 mm in diameter and is expected to carry around 50-100 TJ/d of gas.
The development will be conducted as a joint venture between a government-owned utility and a private sector proponent and would begin construction in the first term of the Government.
Coal seam gas in the pipeline?
Interest in CSG prospects in Western Australia has been increasing with Westralian Gas and Power (WGP) and Oswal Resources signing a Memorandum of Understanding to explore WGP’s CSG leases in southwest of the state.
Mid-year, Greenpower Energy discovered 1.63 Tcf of contingent CSG resources within permit EP 447 of Western Australia’s North Perth Basin. The company said that field fracture permeabilities within the Cattamarra coal measures may be sufficient for the development of economic gas flow rates, and that the prospects are ideally placed in infrastructure terms since they are situated adjacent to APA Group’s Parmelia Pipeline.
Greenpower director Ron McCullough said “This is a very positive indication for commercial gas production from this area. With gas shortages in Western Australia we are seeing increasing interest in operations in the state. The company is devoting close attention to next steps with these assets.”
In order to sure up the state’s gas security, Western Australia’s Department of Industry and Resources called for companies to unlock tight gas reserves in the State’s southwest Perth Basin.
Tight gas refers to gas held in tight (low permeability) sandstone reservoirs that don’t naturally flow gas to surface. The rocks must be “˜coaxed’ through fracture stimulation to yield their gas. Tight gas fields are very common in other parts of the world, now providing over 20 per cent of the USA domestic gas supply.
In June, Latent Petroleum and Alcoa formed a joint venture to appraise and develop the Warro Gas Field, located in the onshore Perth Basin, 200 km north of Perth.
If proven to be commercially viable, Warro will become a major supplier of domestic gas to industry and will be the first commercially viable tight gas field in Western Australia. The field covers approximately 7,000 hectares and holds up to 5 Tcf of gas in place. Drilling is expected to commence in the fourth quarter of 2008.
Gas from the field will be piped to the gas processing plant from various well pad groupings before being delivered to the DBNGP and the Parmelia Pipeline 30 km to the west where it will be sold to customers north and south along the pipelines. Latent plans to construct the 30 km connecting pipeline in the fourth quarter of 2009.
Prelude and Crux – floating LNG
Companies such as Shell and Nexus Energy have noted the difficulty of accessing suitable onshore sites for LNG developments, particularly around the Browse Basin and Kimberley coast.
Shell Gas and Power Executive Director Linda Cook noted that the Prelude Gas Field, located in the Browse Basin, could be developed using floating LNG, providing a lower cost development for small gas accumulations located far from shore and reducing the project’s environmental footprint.
Nexus and joint venture partner Osaka Gas are considering floating LNG for the development of their Crux project, located in the Timor Sea approximately 600 km north of Broome.
The companies expect to reach a Final Investment Decision before the end of 2008.
BHP and ExxonMobil are also said to be considering floating LNG for their Scarborough LNG Development, which is located 280 km offshore beyond the North West Shelf.