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4.6 the New Age of Lng Projects—Gorgon

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4.6 the New Age of Lng Projects—Gorgon THE NEW AGE OF LNG PROJECTS—GORGON LNG LA NEUVELLE ERE DES PROJETS GNL—GORGON LNG Daryl J Houghton Gorgon Asset Team Leader Mobil Exploration & Producing Australia Level 26, QV1 Building, 250 St George’s Terrace Perth, Western Australia Larry S Rosenblatt Vice President, LNG Venture Development Mobil LNG Inc. 12450 Greenspoint Drive Houston, Texas 77060-1991 ABSTRACT The development of the Gorgon area gas fields, off the west coast of western Australia will combine the latest advances in technology, commercialisation, safety and reliability, and government and partner relations. This paper will present an overview of the Gorgon LNG project which is evolving from the discovery of gas resources in difficult-to-produce waters off Western Australia to a likely two-train LNG project. The paper will discuss: · The vision of a long-term gas aggregation center for the Greater Gorgon area gas resources. · Remote subsea production tied back to central processing facilities. · The latest in LNG plant sizing and optimisation. · Cooperation with varied partner, government, and neighbouring project objectives. · The current status of the Gorgon LNG project. RESUME La mise en exploitation des gisements de gaz de la région de Gorgon aularge de la côte ouest de l'Australie-Occidentale aura l'avantage decombiner les derniers progrès en technologie, en commercialisation, ensécurité et en fiabilité d'une part, et les rapports entre le gouvernementet les partenaires d'autre part. L'article suivant présente une vue d'ensemble du projet Gorgon LNG.Celui-ci, ayant commencé avec la découverte de ressources en gaz au largede l'Australie-Occidentale, dans des eaux qui posent des difficultés deproduction, est en voie de développement en projet de gaz naturel liquéfiécomprenant probablement deux chaînes de production parallèles. L'articleque voici examine les points suivants: 4.6–1 · La vision d'un réservoir collecteur central pour l'emmagasinage à long terme des ressources en gaz provenant de la région du grand Gorgon, · La production sous la mer en lieu éloigné, rattachée à des installations de traitement centrales, · Tout ce qu'il y a de plus récent en fait de dimensions et d'optimisation des usines de gaz naturel liquéfié, · La coopération avec les objectifs variés des partenaires, du gouvernement et des projets avoisinants, · L'état actuel du projet Gorgon LNG. 4.6–2 THE NEW AGE OF LNG PROJECTS—GORGON LNG INTRODUCTION The Gorgon project is well on the way towards becoming Australia’s second LNG project. Start-up for Gorgon is targeted in late 2002 with the first of two LNG trains commencing production. Gorgon’s design is for a nominal 6.6 MMTA of LNG delivered to customers. The Gorgon project is based on large gas reserves discovered offshore from the north west coast of Australia. Project definition activities have passed through the feasibility stage and have moved into detailed front end engineering. LNG marketing in Asia is a focus of activity this year with sales agreements targeted by the end of 1998. Formal commitment to the Gorgon LNG project is also targeted for the end of 1998. The Gorgon LNG project is being developed by the CTMS Joint Venture, a consortium of Chevron, Texaco, Mobil and Shell. The CTMS JV participants have been in business together, exploring for and producing oil and gas in Western Australia for over 40 years. In recent years the focus of activity has switched to large gas fields such as Gorgon and the LNG business. Mobil entered the CTMS JV in 1996 when MEPA (Mobil’s Australasian E&P affiliate) purchased Ampolex Limited, one of the original joint venture participants. MEPA has significant Australasian operations with oil production in the north west of Australia at the Griffin and Wandoo oil projects and in Papua New Guinea (PNG) at the Kutubu oil project. MEPA has significant exploration potential with extensive acreage off the north west of Australia and in the PNG fold belt. MEPA also has large gas reserves in the development phase e.g., the Gorgon gas field. MEPA is based in Perth and employs approximately 170 people. GORGON PROJECT: HISTORY AND BACKGROUND The CTMS JV had its origins in the 1950s when the initial participants discovered oil at Rough Range in the north west of Western Australia in 1953. The discovery was made by the operator for the Joint Venture, West Australian Petroleum Pty Ltd (better known as WAPET). Rough Range was not a commercial success but in 1964 exploration persistence paid off with the CTMS JV discovering a large oil field on Barrow Island. Since that time WAPET has produced over 270 MM barrels from the Barrow Island oil field. The JV’s oil business grew further with the discovery of the Saladin oil field near Thevenard Island in 1985. Other oil fields nearby, Roller and Skate, were subsequently discovered and brought into production with Saladin. Total oil production from these CTMS JV oil fields peaked at around 65,000 barrels/day in 1994. The CTMS JV’s gas business activities started in 1966 with discovery of the onshore Dongara gas field. The Dongara gas field was developed to supply the Perth market, some 400 km south. 4.6–3 In the early 1970s the CTMS JV turned its attention to offshore exploration west of Barrow Island. The exploration program focussed on what is now known as the Gorgon area which is located in the southern part of the Rankin Trend, a major geological feature forming the western margin of the Barrow sub-basin (which is part of the larger Carnarvon basin). The exploration program to date has resulted in the discovery of five significant gas fields (Gorgon, Chrysaor, Dionysus, West Tryal Rocks and Spar). The largest of the fields are found in tilted fault block structures with Triassic reservoirs and have much in common with the North Rankin and Goodwyn gas fields which underpin the North West Shelf LNG project. The Gorgon area gas fields are located approximately 60 km from Barrow Island and approximately 200 km west of Dampier on the Australian mainland (Dampier is the site for the North West Shelf LNG project). Water depths in the Gorgon area vary from 100 m at Spar, to around 200 m at Gorgon and over 1000 m at Dionysus. In 1980, when Gorgon was discovered, such water depths posed a significant challenge to development. Today tapping a gas field in 1000 m of water is becoming almost routine. The Gorgon area fields were discovered in exploration permit WA-25-P which was granted to the CTMS JV in 1968. The first well was drilled in the area in 1972 and the first gas discovery was at West Tryal Rocks in 1973. Gorgon was discovered seven years later in 1980 when the Gorgon 1 well was drilled. Gorgon 1 was a major success encountering approximately 130 m of net gas pay over a 500 m Mungaroo reservoir interval at about 4000 m subsea. During testing the well flowed at an aggregate rate of 1940 kcm/day (68 mmscf/day) from three distinct zones. This gave encouragement for follow-up wells on the Gorgon structure which is over 40 km long and 5 km wide. North Gorgon 1 and Central Gorgon 1 were drilled in 1982 and 1983 respectively, both discovering gas. North Gorgon 1 demonstrated the likelihood of a gas field of at least 25 km in length. These further drilling results on Gorgon confirmed the presence of inert gases in the reservoir fluids, which averages 16 % of carbon dioxide and nitrogen together, and a relatively low level of liquids. For the remainder of the 1980s Gorgon was studied to determine economically feasible ways of developing the Gorgon gas fields which were in relatively deep water, contained dry gas and a level of inerts that would require treating. These early studies suggested a 4 MMTA LNG project based on Gorgon would be marginal. Despite this situation the CTMS JV believed that technology improvement, cost reduction and opportunities in the LNG market in Asia justified further development work. The current development phase on Gorgon started in the early 1990s with a target of creating an LNG project. The first stage was to undertake a large 3D seismic program over the entire Gorgon field in 1992. In total 1170 sq km of seismic was acquired. Interpretation of this 3D seismic led to 4 more wells being drilled in the Gorgon area between mid 1994 and early 1996. North Gorgon 2, 3 and 4 were drilled to delineate the northern section of the field. North Gorgon 2 was drilled in the centre of the northern part of the Gorgon field and encountered excellent quality reservoirs. When tested the well produced at an aggregate rate of 4880 kcm/day (170 mmscf/day) from four distinct zones. North Gorgon 3 and 4 4.6–4 were drilled to confirm northern and western extensions to the Gorgon field, both discovered gas. The fourth well in this period was Chrysaor 1, a wildcat about 10 km north of Gorgon. Chrysaor was also a major success discovering a new field that tested at an aggregate rate of 2860 kcm/day (101 mmscf/day) from two intervals. Following these wells the CTMS JV’s attention switched to studies establishing the level of reserves in the Gorgon area and undertaking feasibility and conceptual engineering studies in 1996 and 1997. The reservoir studies are now complete and gas reserves clearly support a 2 train LNG project for well over 20 years. The engineering studies have demonstrated that, with changing technology, a Gorgon LNG project is technically robust and economically attractive. The key changes to Gorgon development concepts have been the adoption of now proven subsea technology for gas production, a shallow water concrete gravity base platform to collect and process raw gas and significant increases in LNG train throughputs.
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