Road to the future

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A member of the Petrofac HSE team atop a telecommunications tower at one of the company’s sites in Oman.

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Omani leader Sultan Qaboos (third from left) attends a meeting of the six-nation Gulf Cooperation Council. (AFP/Getty Images)

Oman has exported 7.5 billion barrels of crude over the last 40 years but, today, according to Nasser bin Khamis Al Jashmi, undersecretary at the Ministry of Oil and Gas, the sultanate faces many challenges.

"Now we are moving from primary production, to secondary production, through tertiary measures like enhanced oil recovery (EOR)," he said.

According to 60% state-owned oil company Petroleum Development Oman (PDO) - which accounts for 80% of the sultanate's oil supplies and is 34% owned by Royal Dutch Shell - annual average oil production in 2006 was 589000 barrels per day (bpd) within a target of 580000 - 600000 bpd. Oman faces an ongoing struggle to stem a fall in production, which peaked in 2001 at 950000 bpd. The challenge is reflected in the most recent production figures, published in August by the Ministry of National Economy, showing crude production down 5.3% in the first five months of the year at 713000 bpd from 753200 bpd in the same period last year.

Oil reserves are estimated at around 5.5 billion barrels, the majority of which can be found in the north and central areas of the sultanate where the large fields - including Al-Huwaisah, Fahud and Yibal - are in decline. Based on current output levels, these reserves would be exhausted in less than 20 years. In November 2006, the government said it would spend US $4 billion over the next few years to increase production, mainly through EOR. This is part of an overall US $10 billion announced in April 2006 to be spent on upstream oil and gas projects through 2011.

PDO says oil output is expected to reach 800000 bpd before the end of the decade. Its first major EOR project at Harweel will raise production to 100000 bpd by 2010. In late 2005 it awarded the UK's Petrofac a US $1 billion contract to build a new oil and gas processing station with a gas enrichment/sweetening plant and associated facilities to support up to 60000 bpd of oil production. A second major EOR project is under way at the Qarn Alam field. Last year PDO completed 313 new wells, lower than its target of 385, which the company attributed to ‘unfavourable market conditions' and ‘high staff turnover and delays in new contract implementation', as well as ‘increasing technical complexities'.

In June, PDO won shareholder approval for the full development of the Mabrouk field, discovered in 1979 and currently producing 8000 bpd. Some 80 new wells are to be drilled and a production station and gathering system built by 2009, after which output is expected to rise to 15000 - 20000 bpd of oil and one to two million m³ per day of gas.

The company estimates that more than half its oil production by 2010 will come from wells not yet drilled, or production facilities not yet built. PDO currently operates 3750 wells over 120 fields. As well as EOR and increased oil recovery programmes, it has launched a Well and Reservoir Management (W&RM) scheme, which has had a positive impact on the No-Further-Activity (NFA) decline rate (an average of annual production compared year-on-year).

The 2006 NFA decline was within target, at 87.4% and although slightly lower than the previous year, PDO said it was nonetheless part of a trend of continuing improvement since 2000.

The application of W&RM technologies has been key to reducing the NFA decline. One example is streamline modelling, which has been applied to improve water-flood pattern management. Water-flooding is critical to the company, as half of its oil production is obtained with the aid of this technique.

In 2006, average water production was 4.3 million bpd and the separation, transport and disposal of this huge volume represents one of the increasingly complex challenges faced by PDO. To address this, it is considering building a pipeline to carry water from the south to re-inject in fields in the north, but this is likely to prove expensive. In 2006, streamline modelling suggested that shutting in two oil-producing wells in the Thuleilat field would enable water injection wells to better support other producing wells. This had led to an increase in production of more than 1200 bpd from the field. The overall result was a reduction in the NFA decline at the Thuleilat field from a historical average of 12% to 4% in 2006.

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