Gone are the days when Oman could view gas as a sideshow to getting at lucrative oil. The US Energy Information Administration states that Oman has 849.5 billion cubic metres (bcm) of natural gas reserves as of 1 January 2011.
The current CIA World Factbook states that the Sultanate produced 24.76 bcm of gas in 2009, 14.72 bcm of which was consumed domestically. Business Monitor International predicts that Oman’s annual gas demand will rise by 22.1% by 2014 over 2009 demand.
The EIA says Oman’s natural gas consumption rose rapidly over the past decade, seeing a 135% increase from 1999 to 2009. The trend is continuing, and a shortfall in feedstock for power generation is already hampering Oman’s economic development, especially its industrial policy. $3.46 billion of petrochemicals projects have been cancelled or forestalled as a result of a lack of guaranteed gas feedstock.
A rapid rise in domestic demand for power generation and downstream projects, together with the need for gas for reinjection into Oman’s mature oil fields and locked-in liquefied natural gas (LNG) export obligations have left the sultanate with a gas supply gap that it quickly needs to close.
The problem is common in the gulf, but has been made especially acute in Oman after its LNG export program is coming back to bite it.
When oil prices fell below $10 per barrel in 1998, the Omani authorities launched a diversification programme known as Vision 2020, which involved gas sales to finance infrastructure projects. These took the form of long-term LNG supply deals, chiefly to Japan’s Osaka Gas and South Korea’s Korea Gas, both signed in 2000.
The Sultanate has worked to close the gap, reducing LNG exports to around 80% of capacity in 2010, according to Robin Mills, a Dubai-based independent energy economist.
Brent is currently trading at $110 a barrel and the gas landscape has been changed enormously, with the US now looking to export LNG. Oman’s Asian LNG deals have locked away a share of the country’s gas resources that it might now prefer to apply to its value-added petroleum product ambitions, if it had the choice.
Muscat cannot solve its gas problems simply by transferring LNG from the export market to domestic customers. Lower prices paid for domestic gas would adversely affect revenues of both companies, hampering state budgets that form the basis of economic growth.
FEW OPTIONS
A nuclear solution to Oman’s energy needs is unlikely to arrive on time to head off the gas squeeze, as Abu Dhabi is unlikely to see any progress on the construction of its nuclear plants and a related GCC power grid before 2017.
Qatar has no shortage of gas, but has to date prioritised LNG exports to extra regional markets in Asia and Europe to maximize revenues. The gas giant has been supplying 200 million cu ft per day of gas to Oman through the trans GCC Dolphin pipeline, under a deal struck in 2007. Mills says gas above this commitment will be expensive.
Iran is pitching to export gas to Oman, and says it is in active negotiations with a view to striking a deal by the end of March 2012, Javad Owji, managing director of National Iranian Gas Co told local news sources.
“We’ve been discussing with Iran to import gas and we will continue to discuss that, for Oman requirements,” Nasser bin Khamis Jashmi, undersecretary at Oman’s ministry of oil and gas, said on 11 October, according to Tehran Times.
The countries signed a prvisional agreement for the construction of a 200km underwater pipeline to transport 1 billion cubic feet of gas a day from the Iranian island of Kish to Oman in 2009.
Iranian gas would be a great deal cheaper than Dolphin gas or imported LNG, but may have serious political drawbacks.
TIGHT SPOT
Oman is not short of gas reserves. However, these are buried deep into the country’s hard rock formations, and surrounded by packed sand and stone, making it difficult and expensive to recover.
The Sultanate has only recently been approaching its upstream gas sector development with the same urgency and ingenuity with which it has taken to cutting-edge enhanced and improved recovery scheme on the oil side. Last year, BG Group pulled out of a tight gas project at the Abu Butabul gas and condensate field, after determining that the $800 million up-front investment was not commercial.
Muscat is now hopeful that BP will decide to pour $15 billion into a long-awaited 10 year tight gas production project at the 2,800 sq km 100 trillion cu ft Khazzan field, known as Block 61.
BP signed an exploration and production sharing deal with Oman in January 2007 and a commercial price for the gas must be struck quickly to ensure BP can plug Oman’s gas leak in time.
Oman has other tight gas fields that could make contributions to supplies, but none has the potential of the BP project.
BP appointed Worley Parsons to carry out the the select stage engineering of the Khazzan Project, which involved the engineering definition of options for the extended well testing of tight gas reservoirs contained within the field. Extended well testing was completed in 2010, after the completion of 3D seismic – the largest ever commissioned by BP onshore – by Global Geophysical Services.
If the project gets the green light it will trigger a contracting boom in Oman. The project is slated to include a 30 mcmd gas processing plant, export pipelines, 300-400 wells – most drilled horizontally in difficult conditions – and 600 km of flowlines and gathering systems. The company is currently taking applications from vendors interested in becoming approved suppliers.
BP, which declared the g&g results “very encouraging,” is now working on the full field development plan – expected to be submitted to the government in early 2012 – after which it will attempt to strike commercial terms for investment. The firm has already plowed around $600 million into the project.
PICKING A PRICE
In a recent Reuters report, the company has said that it will not make a decision on whether to proceed with full field development until 2013, a blow for Oman.
Each well will have to penetrate five km of low-porosity rock before going horizontal, a process which will take several months, with production not slated to begin by BP until 2016 or 2017 on the basis of a 2013 start. Mills says the price must be right.
“Clearly gas prices will have to rise substantially to make such difficult gas projects commercial, to $4-5 per million British thermal units or more,” Mills says. “The government will then either have to raise prices to end-consumers or subsidise prices from other sources. With current high LNG prices, additional gas availability would be valuable even at higher costs.”
Reuters has reported BP CEO Bob Dudley saying the high cost of the project could lead BP to withdraw if a sufficient aggregate price for the gas cannot be agreed. Given the alternatives, Oman will have to work hard to ensure BP commits.
