Western Australia
The North West Shelf LNG Project remains Australia’s largest natural resource development after almost 25 years of production and involves the development of a number of offshore gas fields and associated pipeline infrastructure. In addition, the project is currently being expanded by the North West Shelf Venture (NWSV), which includes Woodside, BHP Billiton, BP Developments Australia, Chevron Australia, Japan Australia LNG and Shell Development.
The North Rankin Gas Field, located in 125 m of water, approximately 135 km offshore from Karratha on the northwest coast of Western Australia, commenced production in 1984. Two trunklines connect the field to Withnell Bay.
The main trunkline, Trunkline 1, is a 135 km long, 40 inch diameter pipeline that runs from the North Rankin A platform to Withnell Bay.
The second 135 km long, 42 inch diameter trunkline was developed as part of a $800 million upgrade of the Woodside-operated NWSV’s trunkline systems. Trunkline 2 connects the onshore gas plant to the interfield line between the Goodwyn A and North Rankin A platforms. First gas flowed in February 2004.
In April 2008, Woodside announced the development of North Rankin 2(NR2), which will involve the installation of a second 23,600 tonne platform at the North Rankin field. The proposed platform will be connected by a 100 m bridge to North Rankin A. Upon completion, both platforms will be operated as a single integrated facility.
J Ray McDermott has been contracted to construct the platform, with project start-up expected in 2013. At the time of writing, jacket fabrication was continuing for the platform.
Also part of the NWSV, the Angel Gas Field platform stands in approximately 80 m of water and is supplied by three subsea production wells. Hydrocarbons from the Angel platform are processed through the NWSV’s integrated system via a 49 km subsea pipeline tied back to the existing North Rankin A platform.
The $1.6 billion development achieved practical completion in August 2008, with first gas flowing in September following scheduled maintenance at the NWSV LNG train 4.
In addition to operating the NWSV, Woodside is currently developing its Pluto Gas Field.
As part of the project, gas from the Pluto and Xena fields will be developed and transported through a subsea 180 km, 36 inch diameter pipeline to an LNG plant where it will be liquefied and shipped to customers in Japan. A percentage of gas produced will supply the domestic gas market via a tie-in to the Dampier to Bunbury Natural Gas Pipeline (DBNGP).
Allseas has commenced pipelay operations to connect the Pluto and Xena fields to the onshore processing facility.
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.
As operator of the offshore Browse Gas Project, Woodside is set to select a location for an LNG plant for the development mid-year.
The project includes the Brecknock, Brecknock South and Tarosa fields, estimated to contain reserves of over 20 Tcf of gas and 300 MMbbl of condensate. The fields are located approximately 400 km north, northwest of Broome in Western Australia. The initial development concept for Browse involves offshore facilities and two LNG processing trains, each with a capacity of 7 MMt/a.
Woodside has said that it will require a 450 km pipeline to link the gas fields to an onshore processing plant.
Currently, the Browse joint venture partners – BP, Royal Dutch Shell, Chevron and BHP Billition – are deliberating between developing the processing facility either at James Price Point, located 60 km north of Broome, or adjacent to Woodside’s Pluto project at Karratha.
The Western Australian Government has selected James Price Point as the site for the development of a Kimberley LNG Hub. Woodside Chief Executive Officer Don Voelte said there were no
“stumbling blocks” stopping the project being developed in the Kimberley, rather than at Karratha, and that construction of the plant at James Price Point could start in 2011.
Other developments near the NWS include Apache Energy and Santos’ Reindeer and Julimar gas fields.
The Reindeer Gas Field, located in offshore permit WA-209-P, approximately 80 km off the Port of Dampier, was discovered in 1997 and has a gross recoverable resource range of 410-640PJ. Gas and liquids from the field will be exported from an unmanned wellhead platform to Apache Energy’s proposed $260 million Devil Creek Gas Plant, to be located near Dampier, via a 105 km pipeline. Clough has been awarded an engineering, procurement and construction contract for the plant, which will have the capacity to produce 215 TJ/d of gas.
In February, construction works associated with the project’s offshore gas supply pipeline were delayed, with works at Gnoorea Point and Forty Mile Beach now anticipated to commence in late 2009. First gas is targeted by the end of 2010.
Apache is also conducting conceptual engineering for its Julimar Gas Field, 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, where gas will then be transferred to the DBNGP.
The Gorgon LNG Development has an estimated resource base of more than 40 Tcf of gas and is located up to 200 km offshore in water depths of up to 1,300 m.
The joint venture between Chevron, Shell and ExxonMobil, involves installation of a subsea gathering system and pipelines from the Gorgon, Jansz and Io fields to Barrow Island. A 300 TJ/d gas processing facility located on the central-east coast of Barrow Island would process the gas.
LNG is then to be shipped to international markets while domestic gas would be delivered via a 90 km subsea pipeline to the Western Australian mainland.
The venture has awarded the downstream front-end engineering and design (FEED) contract to the Kellogg consortium – comprising KBR, JGC Corporation, Clough and Hatch Associates Group, while the upstream FEED has been awarded to a joint venture of Technip and JP Kenny.
In May this year, the Western Australian Environmental Protection Agency recommended that a third 5 MMt/a LNG train could be developed. A final investment decision is now expected in the second half of this year.
Chevron is also proposing the development of the Wheatstone field. The company plans to produce 10 MMt/a of LNG through two LNG trains, which will be supplied by gas from the field 145 km off the Pilbara coast.
The Wheatstone field contains an estimated 4.5 Tcf of gas.
Chevron has chosen Ashburton North for the onshore development site, requiring the installation and operation of two export pipelines to transport gas from the field to the onshore plant. The first of these lines will be approximately 220 km long and 860 mm in diameter.
The second will be laid to allow future tie-ins from other gas fields.
A 250 MMcf/d domestic gas plant is also set to form part of the development.
BHP and ExxonMobil are looking at a number of options for the development of the Scarborough Gas Field, located 280 km offshore beyond the North West Shelf. However, the technical challenges of building such a long pipeline mean that the companies are also considering floating LNG. A floating operation would also avoid Western Australian state laws that require gas projects to set aside 15 per cent of their reserves for the state market.
Joint venture partners ConocoPhillips and Karoon Gas have planned a multi-well drilling program for Browse Basin permits WA-314-P, WA-315-P and WA-398-P, located approximately 480 km north of Broome. The results of this program may sanction the development of a possible LNG project if 7 Tcf of gas is found.
The project would include the construction of a 1,000 km long natural gas pipeline running through the Timor Sea to connect the Browse Basin to an onshore LNG plant.
Northern Territory
Inpex’s $20 billion Ichthys LNG Project is expected to produce more than 8 MMt/a of LNG, 1.6 MMt/a of LPG and 100,000 bbl/d of condensate.
AMEC will provide the offshore FEED services for the project, which includes the 850 km pipeline connecting the Ichthys Gas Field to Blaydin Point on the Middle Arm Peninsula in Darwin.
JP Kenny and Aker Solutions have been contracted to aid AMEC Engineering with the FEED contract for the project. JP Kenny will design the pipeline and umbilicals, risers and flowlines for the project, while Aker will complete FEED for the hulls for the semi-submersible central processing facility and FPSO vessel for condensate treatment and storage.
A final investment decision is expected near the end of 2009 or early in 2010, and first LNG is scheduled for late 2014-2015.
The Blacktip Gas Field has been developed by ENI to bring gas onshore via a 110 km offshore pipeline to supply Northern Territory’s Power and Water Corporation for 25 years. Gas will be piped to a gas processing facility at Wadeye and then transported to the existing Amadeus Basin to Darwin Pipeline via APA Group’s onshore Bonaparte Gas Pipeline.
Saipem was contracted to construct the offshore pipeline, completing construction works in May this year.
Woodside, Shell, ConocoPhillips and Osaka Gas are currently considering the development of the Greater Sunrise Gas Fields. The fields have estimated recoverable reserves of 7.7 Tcf of gas and are located in the Timor Sea, approximately 450 km northwest of Darwin and 150 km south of East Timor.
Woodside is considering two options for the development of the field – either a floating LNG facility or piping the gas to Darwin for processing. The pipeline option could include an expansion of the Wickham Point Bayu-Undan LNG plant at Darwin.
A decision is expected to be made in the second half of this year.
Victoria
The $275 million Henry Gas Field development project, located approximately 8.5 km north of the Casino Gas Field, received formal sanction in November 2008.
The field will be developed by using existing infrastructure associated with the Casino field and will involve the installation of a 17 km, 12 inch diameter subsea pipeline and control umbilical from the existing Casino facilities to the Henry and Netherby development wells, as well as the installation of a further 5 km subsea pipeline and control umbilical to the Pecten East location.
Helix Energy Solutions will install the 17 km subsea pipeline and control umbilical while Cameron will supply subsea trees and Dyco the umbilicals and umbilical termination assemblies.
The uncoated linepipe for the Henry field was produced in Japan by Marubeni-Itochu Tubulars Oceania and has been sent to Australia for coating. Installation of the pipeline was expected to occur during the first half of this year, however has been delayed until the fourth quarter due to the unavailability of a pipelay barge.
The joint venture partners of the project are Santos as operator, Australian Worldwide Exploration and Mitsui E&P Australia.
In the second half of 2008, ROC Oil acquired an interest the Basker Manta Gummy (BMG) Oil and Gas Fields, located in the offshore Gippsland Basin, following its acquisition of Anzon Australia.
The Basker field was discovered in 1983, Manta in 1984 and Gummy in 1990.
The BMG oil and gas fields are currently producing oil from five wells, with gas either flared or re-injected into the Basker-4 well. The development wells are connected to a subsea manifold at a water depth of 158 m, which is tied back to the Crystal Ocean FPSO by subsea flowlines. The production capacity is approximately 25,000 bbl/d of oil.
In August 2008, the BMG joint venture – comprising ROC as operator, Beach Petroleum, CIECO Exploration and Production and Sojitz Energy Australia – completed a review of the fields increasing the 2P reserves to 74.2 MMboe.
A 95 km high pressure subsea gas pipeline will connect to the onshore Eastern Gas Pipeline.
ROC said that the route for the pipeline has been selected and approval has been requested. The 8 inch diameter offshore section of the export pipeline has been procured and is in storage. Work is now underway to secure low cost installation vessels for oil and gas hook up campaigns.
Pipelay has been completed on Nexus Energy’s Longtom Gas Field Development pipeline, following the Aussie-1 pipelay barge’s arrival to the Longtom site, located in Vic/P54 offshore Victoria.
Aussie-1 set sail from Singapore to the Longtom site in March and pipelay operations commenced in late April.
Nexus contracted Trident Australasia to construct the 12 inch pipeline, which will connect the Longtom Gas Field to the end of Santos’ existing Patricia-Baleen Pipeline, 19 km away. The raw gas will then continue along the Patricia-Baleen Pipeline to shore where it will be processed at the existing onshore gas plant. First production from Longtom is anticipated in mid-2009. Commissioning of the pipeline is expected in July.
Another up and coming development is the Kipper Gas Field, which was discovered in 1999 and is estimated to contain approximately 620 Bcf of recoverable gas and 30 MMbbl of condensate/LPG.
The field, located in 100 m of water, approximately 45 km from Ninety Mile Beach on the Gippsland coast, will be developed by installation of a number of subsea wells and associated pipeline infrastructure. Gas will be piped to shore and processed through Esso and BHP Billiton’s infrastructure and processing facilities in Gippsland. First gas is expected in 2011.
Meanwhile, 3D Oil has chosen to develop its West Seahorse Oil Field, located in the offshore Gippsland Basin, utilising a mobile offshore production unit (MOPU) with oil to be exported via a 41 km of pipeline to an onshore tank farm.
The company has said that the MOPU will be designed with a capacity of up to 10,000 bbl/d. A 4 inch, 14 km offshore pipeline and a 6 inch, 27 km onshore pipeline will transport oil to a storage and truck loading facility.
A commercial and technical proposal for the supply of an MOPU and top side fit-out has been commissioned by 3D. The company said that it now plans to seek alliances with suitable joint venture partners for the project.
Future offshore horizons
The number of under construction and planned gas projects off the coast of Australia bode well for the offshore pipeline industry.
The NWS continues to be a hub of activity, with the expansion of existing projects, Pluto under construction and the proposed Gorgon, Wheatstone, Reindeer and Julimar developments expected to come online in the next few years.
Similarly, Victorian offshore pipelines associated with the Longtom, Henry and Kipper gas fields have progressed, with further pipeline infrastructure mooted for the BMG Gas Project and the West Seahorse Oil Field.
Offshore field development in the Northern Territory will also require the construction of long subsea pipelines.
In addition, research and development into the design and construction of offshore pipelines is set to aid the industry’s growth. In June 2008, the CSIRO commissioned a flow loop to help researchers find solutions to predict and control the formation of gas hydrates in offshore oil and gas production pipelines by simulating gas-liquid flows at high pressures and low temperatures – conditions that oil and gas pipelines are subjected to in deep-sea environments.
The CSIRO Wealth from Oceans Flagship’s Subsea Pipeline Collaboration Cluster has also been working to economically design and operate subsea pipelines in Australia’s deepwater frontiers. Stretching hundreds of kilometres long and positioned in waters of almost a kilometre deep, the ultra-long pipelines will carry oil and gas from the remote reserves directly to the shore, without the need for production platforms.
The Productivity Commission has recently concluded its study into the regulatory burden on the offshore upstream petroleum sector in Australia, which recommended that government should improve regulatory practice by reviewing and updating all existing legislation to ensure it is consistent with best practice regulation and good regulatory design.
The report also recommended that the National Offshore Petroleum and Safety Authority should be extended to include the safety and integrity of offshore pipelines, subsea equipment and wells, and that a new national offshore petroleum regulator should be established for projects located in Commonwealth waters.
The Ministerial Council on Mineral and Petroleum Resources has also identified a need to develop a national regulatory and management framework for carbon capture and storage (CCS) in offshore and onshore areas, which may lead to the construction of a new pipeline network. The Federal Department of Energy, Resources and Tourism recently released offshore permits for the use of CCS.
The number of proposed offshore projects, an improved regulatory environment for the offshore sector and potential for further pipeline development with regard to CCS is set to see offshore oil and gas industry busy well into the future.