The World’s Largest Oil and Gas Projects – What You Should Know

Commentary by Jacki Pick

Source: Oil&Gas Monitor

Inpex’s (Japan) Ichthys project is located in the Browse Basin, approximately 135 miles offshore from Northwestern Australia. Ichthys represents the largest discovery of hydrocarbon liquids in Australia in 40 years and is ranked among the most significant oil and gas projects in the world. Australia is geographically positioned to fully engage the Asia-Pacific region, where 60% of the world’s LNG is traded, Japan being the largest importer. With ten LNG export projects, Australia’s export capacity could surpass Qatar’s 77mpta export capacity by 2020.

Inpex describes Ichthys LNG as “effectively three mega-projects rolled into one, involving some of the largest offshore facilities in the industry, a state-of-the-art onshore processing facility and a 550 mile pipeline uniting them for an operational life of at least 40 years.”

Total reserves are estimated at 12 trillion cubic feet. Potential production is estimated at 8 million tons per year, greater than 1 million tons of LPG per year and 100,000 barrels of condensate per day.

The natural gas and condensate will first move through a floating central processing facility, permanently moored near the Ichthys, to insure that the hydrocarbons are prepared for transmission through the pipeline. The condensate will then move from the processing facility to a floating production, storage and offloading facility for additional offshore processing. Natural gas will move via pipeline to the Bladin Point (Darwin) onshore facility for conversion to LNG. The facility includes two LNG trains, one condensate plant, and product storage tanks.

Ichthys progress has been steady, despite the price slump. Inpex commenced drilling 20 wells and the construction of pipeline in February 2015, and by March 2015, the project was greater than 68% complete. Mooring installation works began in May of 2015. The central processing facility and floating production, storage and offloading facility were being integrated in South Korea by June, with an estimated deployment date in 2016. The FPSO hull is floating. Around 70 large LNG modules have arrived at the onshore site. Both onshore LNG storage tank roofs have been lifted into place. Thirty miles of flowlines, greater than 30 flowline sleeper structures, and a 6,000 ton riser support structure tower with a 120 yard arch have been installed in the field. Inpex announced a joint partnership with Shell to construct a subsea optical fiber cable system with the Nextgen Group. Initially, the cable system will provide for Ichthys and Shell’s Prelude FLNG projects which are quite close together offshore Western Australia. The subsea cable will provide a highly reliable and stable high-speed voice and data service, essential for offshore facilities. Total estimated cost is US$34 billion.

The Kearl Oil Sands Project in Alberta, Canada is an onshore, unconventional, open-pit mining operation by ExxonMobil (30%) and Imperial Oil (70%). Estimated reserves are 4.6 billion barrels, making Kearl sufficient to supply North American energy needs for an estimated 40 years. Canada is the largest foreign crude supplier to the U.S. and has the third largest reserves worldwide after Saudi Arabia and Venezuela. Its heavy, high sulfur, diluted bitumen is ideal for coker feed. Kearl connects to the North American pipeline system, ultimately reaching the U.S. Gulf Coast, the mid-continent and the East, to refineries configured for heavy crude.

The Kearl is planned for three stages. Imperial completed the first stage in 2013 at a cost of C12.9 billion, with a return of 95,000 – 110,000 bpd. The second stage started ahead of schedule in June 2015 at a cost of C9 billion and is expected to double Kearl’s capacity with an additional 110,000 bpd. Further expansion is being delayed, but at completion, Kearl could produce between 345,000 – 500,000 bpd.

Kearl has reduced costs and improved its environmental impact by using proprietary froth treatment technology to produce its blended bitumen, eliminating the need for an upgrader and the associated labor costs. Likewise, strategic cogeneration reduces energy use, saving costs and eliminating pollution. The Kearl Project has survived two downturns in the oil market, first in 2008 and presently since June 2014. In both instances, ExxonMobil and Imperial pushed ahead with production, having already made significant investments in the project. While Western Canada Select crude is the lowest priced crude on the market, trading at far less than half the price of Brent, this project continues with the initial long-term planning having been designed to insulate the project from fluctuations in the commodity prices.

Queensland Curtis LNG (QCLNG), BG Group, is the world’s first project to turn coal seams gas (CSG) into liquefied natural gas (LNG). The project, commenced in 2010, is centered in the Surat Basin, onshore in eastern Australia, and will provide an estimated 12 million tons of LNG for both the Australian domestic market and international markets. The project includes a 335 mile buried pipeline network to link the gas fields to nearby Gladstone and a liquification plant on Curtis Island where the gas is converted to LNG. Queensland Curtis is one of the largest infrastructure projects in Australia, costing approximately US$20.4 billion, according to QCLNG. QCLNG has secured long-term sales agreements totaling nearly 10 million tons per year with the China National Offshore Oil Corporation (CNOOC), Tokyo Gas, GNL Chile, Chubu Electric, and the Energy Market Authority of Singapore. Both CNOOC and Tokyo Gas have acquired single digit stakes in the first two LNG trains.

QCLNG loaded its first cargo in December of 2014, and projected expansion of its second train is expected in the third quarter of 2015.

Historically, QCLNG has supplied approximately 20% of Queensland’s natural gas demand. QCLNG’s 140 MW Condamine Power Station is the first combined-cycle power station designed to run on gas from coal seams.

Australia Pacific LNG (APLNG) is the largest producer of CSG in Australia, and its Curtis Project is Australia’s largest position of coal seam gas with a life expectancy of 30 years. The company is a joint venture partnership comprised of Origin Energy Ltd. (37.5%), Sinopec (25%) and ConocoPhillips (37.5%), the latter having experience operating an LNG facility in Darwin (north coast of Australia) since 2006. This project also converts CSG into LNG and has three components: (1) the development of APLNG’s gas fields in the Surat Basin (west of Brisbane) and the Bowen Basin (also SW and Central Queensland) with Bowen containing Australia’s largest coal reserves; (2) construction of a 330 mile pipeline from the gas fields to an LNG facility on Curtis Island, located off Australia’s east coast between Cairns and Brisbane; (3) ConocoPhillips’ construction and operation of an LNG facility on Curtis Island, home to three other LNG facilities. The first two production trains on Curtis are expected to process nearly 10 million tons per year using ConocoPhillips’ proprietary Cascade Process. This project is not within the Great Barrier Reef Marine Park.

This project has secured two offtake agreements to purchase greater than 95% of its production capacity, both with a 20 year contract period that protects investors from low LNG spot prices: 7.6 mpta to joint venture partner Sinopec and 1 mtpa to Kansai Electric (Japan).

In February 2015, APLNG announced that first gas had arrived from the coal seam gas fields to the Curtis LNGF facility via the project’s pipeline. By April, the project began operating the first of seven Bechtel-constructed gas powered generators. Each has a capacity of approximately 15MW, for a combined yield of 105 MW. By July 2015, APLNG announced that it reached a milestone in loading refrigerants for its LNG to its Curtis Island facility, marking the commissioning and start-up phase of the project’s first LNG train. APLNG leadership expects the first exports to begin in the second half of 2015. Train two is expected in 2016.

In 2000, the discovery of the Kashagan oilfields, located offshore in Kazakhstan’s zone of the Caspian Sea, was the largest in four decades. Estimates of recoverable light oil are at 13,000 million barrels, and daily production could reach 1.5 million bpd. Kashagan held promise as the primary oil supply for the Kazakhstan – China pipeline, with projections of first oil set for 2005, eight years earlier than its actual delayed debut in 2013. Partners had included Eni of Italy (16.1%); Royal Dutch Shell (16.1%); Total S.A. (16.1%); ExxonMobil (16.1%); China National Petroleum Corporation (8.33%); Inpex of Japan (7.56%), and KazMunayGaz JCS, the Kazakh state owned oil and gas company which worked in July to sell 50% of its shares in KMG Kashagan B.V. at 16.88% to the JCS Sovereign Wealth Fund, the National Welfare Fund of Kazakhstan, Samruk-Kazyna, for almost $4.7 billion. Participants have come and gone as Kashagan has proven to be one of the world’s most challenging projects, with frequently freezing shallow water, a heavily over-pressurized field, management disputes, and the inherent complications of moving oil with 19% poisonous, corrosive hydrogen sulfide content.

On September 11, 2013, Kashagan finally began production after 12 years of ramp up. The project had to be shut down, however, after only four weeks due to extensive pipeline leakage exacerbated by high levels hydrogen sulfide corroding the steel pipeline. The pipeline must be rebuilt with nickel steel. Restart of production could begin in late 2016 or early 2017.

Original cost estimates for Kashagan were approximately US$10 billion. Estimates of the actual cost of Kashagan – so far – range widely and reach as high as US$116 billion.

The Yamal MegaProject is designed to bring Russia’s Arctic sources natural gas to market from the resource-rich Yamal Peninsula of Northern Russia. Bovanenkovo field is the largest gas field of dozens on the Yamal Peninsula and the Arctic’s largest LNG project, with potential production of 4.9 trillion cubic meters of gas (115 billion meters annually by 2017). This would be equal to approximately one-sixth of all Russian natural gas production in recent years. Developers built an airport, a harbor, and the 355 mile Obskaya –Bovanenkovo railroad to support the project. For the railroad to cross the floodplain of the Yuribey River, engineers constructed the world’s longest and unparalleled bridge of 3.9 kilometers long, beyond the Polar Circle.

This project could satisfy the increasing gas demand in Russia and is a key factor for the development of the Yamal Peninsula, which could outpace production from the established fields of the Nadym-Pur-Taz region.

Total S.A., OAO Novatek (Russia’s second largest natural gas producer), and China National Petroleum Corporation are working to develop Yamal. Gazprom began the investment phase of the US$27 billion project in 2006. The first startup complex, built with a comprehensive gas treatment unit (CGTU) with the annual gas capacity of 30 billion cubic meters and 60 wells, commissioned on October 23, 2012. The U.S. sanctions following the Crimea annexation narrowed Yamal’s financing options, but the project is progressing. Commissioning of the first LNG unit, or train, is to begin in 2016 with commercial production in 2017.

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