Oman prepares for oil expansion and gas production for LNG export

David J. Knott
Senior Editor

Vibroseis trucks are operating under a PDO contract with Western Geophysical Corp., London, on Oman's Block 6. PDO's continuing seismic acquisition program is immense but necessary to guide development drilling in Oman's complex oil reservoirs. PDO and Western Geophysical have developed slip-sweep surveying, which enables simultaneous acquisition of data from two lines of three vibrator trucks and so reduces seismic survey costs. Photo courtesy of Petroleum Development Oman.

Oman's complex geology makes oil and gas developments difficult, but new techniques have eased oil production and en-abled massive gas projects.

The bulk of Oman's oil and gas production comes from the massive Block 6 in the center of the country, operated by the Petroleum Development Oman (PDO) joint venture.

PDO is owned 34% by Royal Dutch/Shell, 60% by the Omani government, 4% by French firm Total, and 2% by local firm Partex.

Oman produced an average 900,000 b/d of oil in 1996, of which PDO contributed 850,000 b/d. The remaining 50,000 b/d was produced by three other license operators: Occidental of Oman Inc., Japan Petroleum Exploration Co. Ltd. (Japex), and Elf Aquitaine SA.

PDO expects Oman's total production to peak at 1.2 million boed during 2004-07. A total of 226 individual projects are planned to increase oil production; without these, oil output would decline.

Reserves

Oman's oil reserves are currently estimated at 5 billion bbl. This is a small amount compared with other Persian Gulf producers, but the Omani government reckons there is more to be discovered.

Brian Ward, managing director of PDO, said Oman has roughly the same estimated oil reserves as the U.K. but a much smaller depletion rate. The government limits oil production so income can be sustained.

"The real bugbear in Oman," said Ward, "is the number of producing wells you need. There are almost 2,200 wells in Oman compared with about 1,400 in the whole of Saudi Arabia.

"Oman's wells are not prolific because of the country's geology. Oil reservoirs are in a difficult geological environment and comprise poorer rocks than in a typical delta environment.

"A typical oil well produces 400 b/d in Oman. You would expect to produce an order of magnitude more from a similar well in Saudi Arabia."

Ward said that, while Omani exploration and production may be challenging, the country holds great potential. PDO estimates the country has 48 billion bbl of oil in place in discoveries and producing fields.

"Out of this total," said Ward, "operators have produced 5 billion bbl and claim reserves of 5 billion bbl. Further volumes are technically accessible and known as 'scope oil.'

"We reckon the first 2.4 billion bbl of scope oil could be produced for less than $10/bbl total cost, while a further 700 million bbl could be produced for $10-15/bbl.

"PDO expects to increase scope volumes in reserves through horizontal drilling and other techniques. We look on this as microsurgery, in terms of drilling."

Ward says PDO has increased its oil reserves every year since it began producing, except for a dip in the late 1970s: "We're finding more than we produce each year, but it's getting tougher."

The Omani government intends to encourage frontier exploration to "increase the size of the cake" in terms of reserves. PDO has its own target of increasing the amount of oil it recovers to 34% from 27% currently.

"New technology is what we're going after now," said Ward. "We are at the limit of our production capacity and expect to be on plateau for 10 years."

Exploration

As part of its drive to increase reserves, Ward said the Omani government has licensed a number of other blocks, and these are all at the exploration phase.

"The next drive for government will be to interest people in Gulf of Oman offshore acreage," said Ward. "They have already approached Shell.

"Any Shell operation there would involve a different financial arrangement from PDO. Private investment is required because it is a high-risk area."

The offshore area to the north of Oman is not expected to be prolific. There is a narrow continental shelf, after which the seabed drops away to more than 300 m deep.

Matthias Bichsel, PDO exploration director, explained that Oman has small oil and gas fields compared with Saudi Arabia and Kuwait because it is not on the stable continental platform where the large accumulations are, but on a highly faulted oceanic crust.

"Exploration here is very high risk," said Bichsel. "We've hit many brick walls with past exploration, but we've got over them. To do this, we developed state-of-the-art technology in-house.

"Much of the technological developments came through Shell. Some world-class exploration talent has been posted to Oman."

Bichsel said more than 800 exploration wells have been drilled by PDO, with 35 wells aimed at oil targets and six wells at gas prospects in an average year.

PDO currently has four rigs exploring for oil and two for gas, and five onshore seismic crews are operational throughout the year. Exploration spending was expected to amount to $220 million in 1997.

Bichsel said $120 million was spent on exploration drilling-$80 million on oil and $40 million on gas-with $80 million due for seismic surveying. In 1997, PDO acquired 4,500 line-km of 2D seismic and 4,000 sq km of 3D data.

"PDO has a dedicated in-house seismic processing center," said Bichsel. "It has the largest exploration operation within the Shell group in terms of activity, but not the most expensive, because it involves land exploration."

Bichsel said Oman is maturing as an oil province, but new techniques offer opportunities in existing plays, while frontier plays have not yet received much attention.

"For instance," said Bichsel, "we believe there are plenty of opportunities in southern Oman. The main oil play in Saudi Arabia is Mesozoic, but in Oman, we are looking at Cambrian plays, which are complicated to unravel."

PDO has recently been discovering about 90 million bbl of oil/year, with 1.6 billion bbl being added to reserves over the last 10 years, including condensate.

Bichsel said that within its exploration portfolio, PDO has defined 1.4 billion bbl of oil prospects and 9 tcf of gas prospects, while it has identified geological potential for a further 1 billion bbl in oil prospects and 15 tcf of gas.

"PDO is portfolio rather than opportunity-driven," said Bichsel. "We have such a large database that we can follow themes in our exploration. We aim to develop three plays at a time, with a 12-month cycle time."

Identified plays

Among recent fruitful plays, Bichsel cites the Ghaba salt basin in central Oman, source of the three fields-Saih Nihayda, Barik, and Saih Rawl-that will provide feedstock for the country's LNG export scheme.

Here, improving seismic techniques enabled PDO to build on an initial wildcat drilled into an ill-defined shallow anticline. As the seismic data improved the picture of deeper structures, a major gas play unfolded.

"The Saih Rawl structure grew through seismic," said Bichsel. "This led to the creaming of a trend over 3 years, and the creation of an LNG business on the back of three major discoveries."

PDO has identified other deeper gas structures in northern Oman, and further prospects have been identified in western Oman for drilling in 1998 and beyond. Southern Oman is also increasingly revealing gas potential.

Another successful recent trend is the Athel play in southern Oman, which Bichsel said comprises porous silicilyte that is 550 million years old: "A world-class source rock."

By the end of 1997 PDO had drilled six exploration wells in the play and was drilling ahead on a seventh. These had resulted in two finds: Al Noor, where 100 million bbl oil reserves have been booked out of an estimated 1.3 billion bbl of oil in place; and Al Shomou, where oil in place is reckoned to be 600 million bbl and reserves have not yet been estimated, although 42 million bbl is expected to be booked initially.

Bichsel said PDO has completed frac jobs on one well each in Al Noor and Al Shomou, with a view to proving they can produce at high rates economically.

PDO expects initial drilling in the Athel play to identify reserves of 340 million bbl of oil, while there is potential for anticipated drilling programs to increase reserves here to 1.8 billion bbl by 2003 and 2.7 billion bbl by 2011.

Data collection

Three-dimensional seismic data is seen as key to exploration in Oman. Collection of it began in earnest in 1986.

Since 1991, PDO has operated two data acquisition groups, each comprising seven vibrator trucks (one spare) and a data processing truck.

Bichsel said the cost of PDO's seismic surveying has fallen eight-fold during 1986-96 through introduction of vibroseis teams. Now PDO is looking to introduce wide-line geometry data acquisition.

With wide-line data acquisition PDO plans to have a 9,000 m spread between lines, compared with the conventional 600 m spread, to target deeper horizons.

Trial surveys have shown a 35-44% cost saving over conventional methods, said Bichsel, while the data quality at depth is the same as for shallow seismic in other fields.

"In a year or so," said Bichsel, "we expect to be able to shoot 3D seismic for the same price as 2D, so we will be able to drop our 2D crews. This is expected to cut costs by 25%."

Another new technique to be introduced is slip-sweep surveying, which enables simultaneous acquisition of data from vibrators by two lines of three trucks, with data being separated out later in processing.

"With slip-sweep we can halve data acquisition costs," said Bichsel. "Slip-sweep was developed by PDO and will ultimately have application offshore."

Oil production

Ward said PDO's corporate production objective for the period 1998-2002 is to maintain oil production at 850,000 b/d and to keep unit exploration and development costs below $3.56/bbl.

In 1986, PDO set out to cut E&D costs from $6.22/bbl, at real-term 1997 levels, to $3.74/bbl now, with a target to achieve $3.46/bbl by 2001.

"We want, each year, to replenish through exploration the amount we have produced," said Ward, "and we want to inventorize gas reserves rapidly.

"Government set us a target to ensure that this production level can be maintained for 10 years without exceeding more than 6.5% of reserves depletion in any year."

Ward said the major cost driver for PDO is the need for water injection. The company is looking at new technologies to separate out water in the well before it is brought to the surface.

In total PDO produces 2.2 million b/d of water now and expects to be producing 4 million b/d of water in 2000.

Reducing per-unit water production is part of a drive to reduce operating expenditures from $1.33/bbl now, said Ward, to a target level of $1.04/bbl in 2002.

In 1996, PDO spent a total $1.156 billion, of which $267 million was for development drilling, $129 million was for development engineering, $411 million was operating expenditure, and $204 million was for exploration.

Abdulla Lamki, PDO oil and gas director, said the company considers Block 6 as comprising three sections-northern, central, and southern-which have been opened up at different times.

From 1967 to 1977, PDO opened up northern carbonate structures, with Fahud oil field one of the first brought into production. By 1975, oil production in the central area had begun, while discoveries were made in the late 1970s and first brought on stream in 1981.

"By the end of 1997," said Lamki, "PDO had 93 fields on stream, compared with 33 at the end of 1985 and 89 at the end of 1996. PDO is very much a drilling-driven company, with 50% of capital expenditure on drilling.

Including the six exploration rigs, Lamki said PDO normally has 24 drilling rigs running at any time to maintain production: "One in every 4 bbl of oil exported through the terminal is produced from wells drilled in the past year, and about 230,000 b/d is produced from wells drilled in 1997."

Lamki said that, with 50 billion bbl of oil in place in Oman, there is scope for additional recovery, and that the anticipated cut-off point for production is $15/bbl: "Of course we'll try to get as much as possible for less than $10/bbl."

He said PDO's developed fields have total reserves of 2.1 billion bbl of oil, while undeveloped reserves amount to 3 billion bbl, including 640 million bbl of condensate.

The production portfolio includes almost 400 projects, from field developments to enhanced oil recovery schemes, to exploit undeveloped oil and gas.

"In the next 5 years," said Lamki, "PDO is planning 226 individual projects involving a total of 953 wells; hence our need to have 24 drilling rigs. We expect to be using more than 20 rigs for the next 5 years and beyond.

Solid producers

Yibal field accounts for about 25% of Oman's developed reserves and delivers about 217,000 b/d of oil. Lamki said the field is mature and its production needs to be replaced with new developments.

Typical of these is a thin carbonate oil reservoir in Saih Rawl field, where gas production began in 1995. PDO is drilling horizontal wells in the oil zone, and recently completed a dual producer and a triple injector. Here, full field development is under way, with a further 19 producers and 17 water injectors slated to be drilled in the near term.

In a similar project in Amin field in southern Oman, PDO has boosted production of heavy oil by water injection through multilateral wells.

At Qarn Alam in central Oman, the recovery factor would be 2% unaided because of the 16° gravity oil and fractured reservoir. Here,PDO has built a steam injection plant to heat the oil to 240° C. to increase recovery.

"There have been teething problems with the plant," said Lamki, "but we expected that, if the process is effective, nearly 200 million bbl of extra reserves will be accessed."

Lamki said PDO's main oil production challenge is to increase overall recovery rates to 30% from 21%, but in order to achieve this economically drilling costs must be reduced.

PDO's total production capital spending in 1996 was $600 million, but this total is expected to be reduced in the future through efficiency improvements. Lamki said key technologies to achieve this are multilateral wells and coiled tubing drilling.

Improved reservoir understanding is also vital. For example, 3D seismic surveys in Fahud field, developed 30 years ago with more than 300 wells drilled so far, revealed small pockets of oil that can be drained with local water injection.

Gas production

Jan Alkemade, PDO gas manager, said one third of Oman's domestic gas use-4 bcfd in winter and 11.8 bcfd in summer, mainly from Yibal field-is required for power generation to meet the need for air conditioning.

Of the 21 tcf of gas reserves earmarked for development: 8 tcf has been dedicated to the LNG project; about 7 tcf is anticipated to be required by planned fertilizer, aluminum, and petrochemical projects; and the remainder will supply domestic needs, expected to triple in the next 25 years.

From Yibal field a dual pipeline takes gas to Muscat and on to power plants at Sohar. This is mainly nonassociated gas, produced from 13 wells. PDO intends to have 45 wells on stream here by 2000.

Besides Yibal, Oman's gas reserves are mainly in the three deep fields in the center of Oman: Saih Nihayda, Barik, and Saih Rawl, where other significant gas finds are anticipated.

Ward said these three fields are "the engines of Oman's LNG development" and the main contributors to Oman's total of 19.1 tcf of proven gas reserves and 28.3 tcf of proven plus probable reserves.

PDO says Oman has potential total gas reserves of about 40 tcf, including associated gas in oil fields, but that new reserves need to be proved to meet total LNG scheme and domestic industry requirements.

Ward said Oman's nonassociated proven gas reserves amount to 17.8 tcf. The expectation is that proven nonassociated gas reserves will reach 25.4 tcf, while 20.6 tcf of gas is needed to meet all LNG, industry, and domestic commitments.

In all Ward said $9.6 billion has been earmarked for capital investment to exploit Oman's gas reserves. Of this, $4-5 billion will be spent on the Oman LNG export scheme.

A 6.6 million metric ton/year LNG export plant is under construction at Sur on the coast of northeast Oman. The plant is due to deliver its first cargo in 2000.

A 220-mile, 48-in. gas pipeline is being built to deliver gas from Saih Nihayda, Barik, and Saih Rawl to the project.

Among other plans for Omani gas is a proposed 850-km South Oman Gas line from Saih Nihayda field to the southwestern port of Salalah, where PDO intends to build a power generation plant and the government has plans for a refinery. This line is slated for completion by 2000.

At Sohar in northwest Oman, the government plans to build an industrial complex that will include a polyolefins plant and an aluminum smelter. This would be supplied through a new gas pipeline from Fahud field.

The government also plans to build a fertilizer plant alongside the LNG project at Sur.

LNG project

Alkemade said the LNG scheme is the most advanced of Oman's nondomestic gas schemes, as it is nearly halfway complete. The first train is scheduled to begin commercial operation Jan. 1, 2000, and the second train will start 3 months later.

Two 120,000 cu m aboveground storage tanks are being built, along with a short loading jetty.

Shareholders in Oman LNG LLC, established to build and operate the project, are: operator Shell 30%, Omani government 51%, Total 5.54%, Partex 2%, Mitsubishi Corp. 2.77%, Mitsui & Co. 2.77%, Itochu Corp. 0.92%, and Korean LNG (a consortium led by Korea Gas Corp.) 5%.

Total capital outlay for the LNG scheme is expected to be $6 billion, including construction of nine LNG carriers by customers. Korea Gas Corp. (KGC) will own six and Osaka Gas one, while two more are anticipated to be built for further buyers.

Alkemade said most of the plant's 6.6 million tons/year of output is already contracted: 4.1 million tons/year will go to KGC, and 700,000 tons/year to Japanese utility Osaka Gas Corp.

A further 1.8 million tons/year had been contracted to Petroleum Authority of Thailand (PTT), but PTT canceled the contract in 1997 as Thailand's currency collapsed.

Alkemade said this 1.8 million tons/year is being marketed, with negotiations under way with potential customers. PTT can negotiate to buy LNG from Oman at a later date. Deliveries to KGC will begin in early 2000, while the Osaka Gas contract begins later that year.

Ian Coult, marketing manager at Oman LNG, said PTT's withdrawal has not crippled the project, since 4.1 million tons/year of sales was the critical mass required to justify a two-train LNG project.

Coult said Oman LNG is negotiating with six potential customers for the unsold LNG. The six are in Japan, India, China, Taiwan, and Turkey, and are mainly planned power generation plants.

Oman LNG is prepared to break down the surplus into smaller contracts. Coult said: "The number of spot LNG cargoes worldwide is also likely to increase. We expect some of Oman LNG's output to be sold this way."