As of the end of 2012, Oman had 12.18tn cubic feet (tcf) of proven gas reserves and expected reserves of 17.82 tcf, according to the Ministry of Oil and Gas. Thanks to ongoing exploration efforts, new discoveries mean that the country’s proven reserves have not depleted over the past decade, despite growing consumption – they stood at 31.8 tcf in 2002, more than quadrupling in the decade before from 7.1 tcf in 1992. Furthermore, the country’s reserves to production ratio is 32.8, suggesting that the country has more than three decades until current reserves are depleted at current levels of extraction.
Strong domestic demand from power generation and industry saw production rise by 3.5% in 2012, to 1.27 tcf, from 1.23 tcf in 2011. Output has grown rapidly in recent years, more than doubling from 539.53bn cu ft (bcf) in 2002. Growth in the gas sector has been stimulated by the opening of two liquefied natural gas (LNG) plants, Oman LNG in 2000 and Qalhat in 2005, both run by state-owned company Oman LNG, since September 2013.
The plants have combined annual export capacity of 10.4m tonnes (around 500 bcf). But due to the strength of domestic demand, they have not produced more than 8.8m in the past five years, with output at 8.4m in 2012.
Oman is one of the largest dry natural gas producers in the Middle East and ranked 26th in the world in 2011, according to the US Energy Information Administration (EIA). Some 22% of the dry gas it produced in 2012 was used in oil extraction, reinjected into reservoirs. Overall demand has soared in the past decade, by 168% between 2002 and 2011; Oman is now in the unusual position of both importing and exporting gas.
In 2012, the country exported 395 bcf, which is almost 80% of the country's total capacity, in 131 cargoes, according to the EIA. Almost all exports go to South Korea and Japan, with small amounts to China. Its imports are around 71 bcf per year bought from Qatar via the UAE on the Dolphin pipeline. The Omani government plans to divert all LNG to the domestic market by 2024 as current demand is so strong, but new discoveries may change this tactic.
In January 2007, BP signed an exploration and production-sharing contract with the government for the appraisal and development of an area of 2800 sq km at Block 61 in north-central Oman, and the Khazzan and Makarem gas fields. The fields are split into four reservoirs – Barik, Miqrat, Amri and Buah – which, once producing, will be linked to the nearby Saih Rawl gas plant, a government-owned facility at what is currently Oman’s largest commercially operating gas field.
The gas will be fed into Oman’s gas grid and is expected to supply the domestic market, on which demand is growing strongly, driven by industrial development and population growth. BP acquired the concession for exploration rights to 100% of Block 61, which covers an area larger than that of central London. The company has a production target of 1 bcf per day when it commences full commercial operation in 2017. BP expects to invest $20bn to $24bn over the lifetime of the project – a huge sum by local standards, which indicates BP’s confidence in the block’s future and the investment environment in Oman. “The government provides a sound basis on which we can invest with confidence,” Oliver Broad, communications and external affairs vice-president at BP Middle East, told OBG. “We have invested hundreds of millions of dollars and the government has been very supportive.”
The gas resources are so-called tight gas, surrounded by rocks of low porosity, and this is one of the largest unconventional gas fields in the Gulf, according to BP, and one of the biggest international oil company (IOC) projects not led by a state partner. It has entailed one of the world’s largest 3D surveys – the largest onshore 3D survey in BP’s history – requiring a substantial amount of up-front investment.
The UK company has been undertaking a thorough exploration and appraisal programme using its proprietary technology, Distance Separated Simultaneous Sweeping (DS3), a system of seismic surveying using two or more vibrators to record seismic data at the same time, that has made the project one of the most productive and efficient onshore surveys ever.
Drilling started in September 2008, and in March 2011, the first gas export was achieved, from BP’s extended well test project to the Saih Rawl gas plant. In September 2013, the Dalma 5 rig spudded (made initial drilling) the well at Khazzan, the first development well to be drilled at Block 61.
At the time of writing, 11 appraisal wells had been drilled and BP was moving into full-field development. The company plans to drill up to 300 wells in the field in all. There will also be around 600 km of flowlines and gathering systems for collecting and distributing the gas. Output from the field will be fed into the national pipeline system, and will not require extensive investments in new pipeline connections.
“BP is optimistic of moving ahead on the final implementation plan and developing a very important resource for the country,” Broad told OBG. “This could be a new supply of affordable gas that would be supportive of economic growth. It can meet demand in desalination, power and industrial uses to support Oman’s development agenda.”
The project is indicative of the benefits of technology transfer that international companies have brought to Oman – and indeed its Gulf neighbours and other hydrocarbons-rich emerging markets. Tight gas, as its name suggests, can be difficult to extract, requiring sophisticated technology and experienced technicians. BP’s technicians have worked on similar projects, and the company has been particularly active in extracting tight gas in North America. Working on the concession also adds an interesting new asset to even BP’s large, diverse global portfolio. “There is a real feeling that we can leverage our technology and experience from North America,” Broad said. “The value offer of technical competence and technology is critically important. It’s a big frontier resource and opens up a really distinctive position in the Middle East.”
Extraction at the Khazzan field will involve hydraulic fracturing, or “fracking”, a technique which involves injecting high-pressure liquid (usually water with chemicals) into wellbores to create small factures along which the gas can flow to collection wells. Fracking has become controversial in some parts of the world in recent years, including the UK and Eastern Europe, and some countries have gone as far as to issue moratoriums on the use of the technology, due to concerns over its seismic impact and pollution of water sources.
Broad asserts the hydraulic fracking has been used for half a century already. The chemicals used to keep the pores open, he says, are little different from household detergents. Furthermore, there is no human population or sensitive wildlife above the field – this is largely empty desert. Broad says that one of the biggest challenges of hydraulic fracking in Oman is responsible, efficient use of the limited water resources, and careful disposal of waste water in an arid country.
In September 2013, Oman signed an agreement with Iran that would see the sultanate import Iranian gas via a new submarine pipeline under a 25-year deal worth $60bn. If realised, the deal could provide a substantial boost for Oman’s gas supply and potentially exports, though a previous agreements proved controversial and did not come to fruition.
However, the pipeline plans have been revived again as Oman’s domestic demand has put exports at risk, with limits to supply from Qatar, and against a backdrop of thawing relations between the West and Iran, which has the world’s largest gas reserves.
Now the governments of both countries want to see the pipeline “implemented as soon as possible”, according to the new Iranian energy minister, Bijan Zanganeh, having signed the agreement with Oman.
Serious challenges remain, however. Oman’s US ally is understood to be wary of the deal, and sanctions mean that Petroleum Develop Oman’s partners, such as Shell and Total, are likely to be reluctant to process Iranian gas for LNG export along the lines of the 2007 deal, though the imports could be used to supply domestic customers, freeing local resources for export.
Perhaps more importantly, pricing is an issue, given Oman’s heavily subsidised gas prices, which would make buying Iranian gas at market prices and selling it locally expensive for the government, as state funds would be needed to bridge the gap. It is possible that Iran, which is seeking new markets for its gas and aiming to increase hard currency earnings, would accept below-market fees, but almost certainly not as low as Oman’s current consumer gas prices. Finally, particularly given uncertainty in the region, the project has a long lead time – Iranian suggestions that exports could start within two years seem optimistic, due to the technical challenges of developing a subsea pipeline.
The growth of Oman’s gas production has been one of the success stories of the past decade for the sultanate. While supply is tightening as domestic usage soars, the Block 61 project is a very promising development for the country, and should help support further investments, as well as broader economic growth.
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