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LNG market update: part one

Hydrocarbon Engineering,


The market for LNG is expanding in leaps and bounds. World trade has grown from 10 billion ft3/d in 1997 to 32 billion ft3/d in 2012, and is expected to continue its rapid expansion for the next decade. According to BG Group, LNG demand will grow at 5%/y to 2025, amounting to approximately 60 billion ft3/d.

As there is no global natural gas market, several regional markets have evolved with their own supply and demand dynamics. Thanks to horizontal drilling and hydraulic fracturing that have economically tapped unconventional resources, North America has far more natural gas than it consumes. In Russia, large conventional reserves have long been exported to Europe. Now, both producing regions are seeking to tap into LNG markets, which command a price premium of up to five times the local prices.

In North America, Cheniere Energy is constructing an LNG plant in Sabine Pass, Louisiana. The facility will have a capacity of 19.8 million tpy (7 million tpy converts to approximately 1 billion ft3/d). It also recently received approval for a second LNG facility in Corpus Christi with a capacity of 13.5 million tpy.

In Canada, there are several proposals to ship shale gas from northwest British Columbia to LNG trains in the deepwater port of Kitimat, and hence to Asia. Shell, Korea Gas, Mitsubishi and PetroChina are planning the LNG Canada project. Capacity will be 12 million tpy with an option to expand to 24 million tpy; phase I will cost approximately CAN$10 - 15 billion.

Russia, which already exports LNG from Sakhalin Island, has a massive new project underway. Novatek and partner Total have announced plans to build a 16.5 million tpy plant on the Yamal Peninsula in the Arctic Kara Sea. The US$27 billion project, which is expected to reach startup in 2017, will deliver the LNG to market using up to 16 Arctic class carriers.

The average cost for a 5 million tpy plant located in an easy to access region is approximately US$6.5 billion (US$2 billion for upstream facilities, US$3.5 billion for liquefaction and US$1 billion for insulated transportation ships). Remote locations can quickly add 50% or more to the base price.

Cost escalation

Recently, cost escalations have plagued the sector. Chevron’s Gorgon LNG plant, located on Barrow Island on Australia’s North West Shelf, will have a capacity of 15.6 million tpy. It was originally slated to cost US$37 billion, but the final price tag is now grown to US$54 billion. The nearby Wheatstone project has also seen budget escalations. Originally tagged at US$26 billion, the 8.9 million tpy facility has now jumped to almost US$30 billion.

The recent collapse of oil prices has also had a knock on effect upon the LNG sector. Many LNG contracts are tied to the cost of oil; prices in Asia have fallen below US$10/million Btu, down 50% from the same period last year. While little can be done about the commodity price, operators are looking at ways to bring costs back down to earth.

Several imaginative innovations have arisen. Floating LNG (FLNG) plants have several advantages over conventional facilities. The unit can be constructed where labour and infrastructure costs are relatively low, then towed to site. There is no need for transportation pipelines between the field and the plant. Transfer to LNG carrier ships occurs adjacent to the facility, eliminating the need for a dedicated harbour.

Shell opted for an FLNG for the Prelude field off the coast of West Australia. The vessel, which includes raw gas treatment, liquefaction and storage, is 488 m long, 74 m wide and weighs 600 000 t; it is approximately five times the size of the largest aircraft carriers. The vessel, which is expected to enter operation in 2016, is estimated to cost up to US$12.6 billion. Several other FLNG facilities are being planned for fields in Malaysia, the Timor Sea and Australia.

Small scale LNG plants have been devised for commercial use. Based upon work at the US DOE Idaho National Laboratory, a compact system for liquefying methane was built in California. The plant is located adjacent to a main gas line. As the pressure drops to commercial distribution levels, sufficient energy is created to power the process. Methanol is injected into the gas stream in order to bind with water and allow it to liquefy and drain away. As the temperature drops, CO2 eventually solidifies and can be removed; the result is pure liquid methane that can be stored for use. According to the inventors, the process greatly reduces transportation costs and capital (a plant can cost as little as US$2 million), and creates a flexible fuel source that can be used for peak shaving. GE now offers a fully integrated, skid mounted LNG unit that can produce between 25 - 600 gal./d of LNG for use in remote power, utility and transportation applications.

LNG operators are looking more closely at the economics of medium scale LNG plants. Conventional wisdom states that the most cost efficient scale for an LNG train is in the 5 million tpy range. Yet cost overruns have shifted attention to smaller output facilities. AltaGas and partners are proposing a CAN$600 million train that would produce 500 000 tpy from a plant mounted on a barge and anchored at the mouth of a waterway leading to Kitimat, British Columbia. The concept is based upon designs being refined in China, where manufacturers are creating barge mounted LNG plants at construction costs amounting to US$500/t, compared to up to US$1500/t on land. The plants can be constructed at a central location and delivered onsite much faster than conventional facilities.

Read part two of this article here.


Written by Gordon Cope. This is an abridged article taken from the May 2015 issue of Hydrocarbon Engineering.

Read the article online at: https://www.hydrocarbonengineering.com/special-reports/27042015/lng-market-update-part-one-666/


 

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