OMAN - Oil Production Costs.

That there should be more than 3,160 wells, in almost 160 oil and gas fields in Oman, to produce about 770,000 b/d shows to what extent oil production costs in this country have risen in recent years. To compare, Saudi Arabia has less than 1,850 producing wells with at combined output currently averaging 9.5m b/d. Most of Oman's oil comes from geological formations (Fms) about 500m years old, with only a few giants. In Saudi Arabia, most of the oil comes from super-giants and giants with Fms being 100m years old (see geological profile of Oman in gmt5OmanGeoJan30-06). Oil production costs at PDO range from $4/barrel in few fields still producing oil without EOR help, to $7/b in fields where EOR operations are the least costly and $10/b in fields requiring most advanced steam and gas injection systems.

The main challenge relating to production costs in Oman is a rising water content in the reservoirs. At the Nimr group of fields, for example, about 1.2m b/d of water had in May 2003 to be dealt with in the production of 140,000 b/d of oil. Bringing water to the surface is not only costly to PDO but also raises environmental issues of what should be done with it. But now Nimr is only producing 120,000 b/d of oil.

On May 2, 2003 MEED quoted PDO's team leader for water management, Anto Sluijterman, as saying: "We are engaged in the water industry as much as we are in the business of producing oil. Oil almost appears to be a by-product of our core activity, which increasingly is processing and disposing of excess water". On EOR operations based on water injection, he said: "For every 10 barrels of water we inject into a well, we expect to get a return of one extra barrel of oil".

PDO has been embarked on a programme called Target 50 (T50), which is aimed at boosting its recovery factor from 12% to 50% of oil reserves in place. The programme consists of three main categories of EOR operations: (1) using steam injection for the recovery of heavy oil, mostly in fields in the south, which is costly; (2) gas injection, based on gas gravity technology, which is also costly; and (3) water flooding, which is the traditional EOR method and is the simplest and less costly of the three.

PDO, for example, had 2 bn barrels of oil in place at the Mukhaizna field. Before losing it to Oxy-Liwa in 2005, PDO was considering T50 project there. But the government found PDO's budget for this field too expensive and invited other companies to bid for it. As Oxy-Liwa's costs and terms were better than those offered by Shell, the government transferred the field to the US-Abu Dhabi JV under an agreement signed in June 2005 (see Gas Market Trends of this week.

At Yibal, PDO in 2001 completed a successful trial of downhole oil-water separation. The technology used separates the water from the oil in the well through a hydroclone. With the device, the separated oil heads to the surface, while the water is reinjected into the reservoir, thus maintaining pressure. It has since been indicated that the technique achieves significantly higher oil production than a gas lift.

PDO has focused on reed-beds, which absorb the hydrocarbons and heavy metals contained in saline water produced from the well. Thus PDO has come to look at water as a resource rather than a nuisance. In 2000, a six-hectare pilot project was established to treat 3,000 CM/d. Further tests were done at Sultan Qaboos University to see if the water can be used for salt-tolerant crops.

In PDO's carbonate-bearing structures, oil is generally heavy, making both extraction and recovery problematic. This is the case at Qarn Alam in central Oman, where the compact, dome-shaped reservoir is mostly submerged in water. The reservoir contains oil of high viscosity and low permeability. A pilot steam injection programme at the field was launched in 1996 with the aim of reducing the oil's viscosity through heat. Steam was injected into a secondary gas cap. Monitoring wells were drilled nearby to assess its impact. The results showed that oil production increased by about 600 CM/d based on that performance. Since then, PDO has embarked on a $250m project for a commercial plant to produce and inject up to 12,000 t/d of steam into Qarn Alam. PDO is to apply the same technique in other fields (see background in Vol. 62, OMT No. 6).

The following are the oil producing operators in Oman:

Petroleum Development Oman (PDO). The main concessionaire, PDO produces the bulk of Oman's oil and gas. Its oil production capacity at present is about 609,000 b/d, down from 846,000 b/d in 1997. In addition, PDO produces 61,000 b/d of condensate. PDO is owned 60% by the Omani government, 34% by Shell which is the technical manager, 4% by Total and 2% by Partex. PDO is aiming to bring production back up to 820,000 b/d by 2009, through water flooding in the short term and EOR techniques over the medium and long term. EOR requires heavy capital expenditure and systems take several years to bring to fruition.

The Shell-led foreign partners in PDO in 2002 began negotiations with the government to renew the company's concession in block 6. This occurred in December 2004 when PDO's concession in block 6, covering most of the country, was extended until 2044. Originally signed in 1937, the agreement had been due to expire on June 24, 2012. But in 2005 PDO had to relinquish 10% of its acreage and thus its area was reduced from 114,000 sq km to 102,600 sq km, and lost Mukhaizna as Shell was outbid by Oxy/Liwa (see Gas Market Trends).

PDO has more than 140 oil and gas fields. Of these, about 115 are on stream connected to its production system in onshore Oman's four main oil fairways, which are as follows:

The north, along the border with the UAE and Saudi Arabia, which is an extension of the Arabian Basin, including Thamama-related fields like the Fahud-Lekhwair-Daleel group.

The north-central groups in the Infracambrian Salt Basin, which include the main producing fields like Yibal and fields centred on Natih-Shibkah.

The central and west-central groups, also in the Salt Basin, which include the gas-rich Saih Nihaydah.

The south, in a Lower Salt Basin with fields of both very heavy and medium/light oils centred on the Marmul-Nimr-Rima-Jalmud trend.

All of PDO's wells now are horizontal. These and the use of 3D seismic have resulted in oil and gas discoveries far in excess of expectations. These wells stretch 500 metres to 1.5 km along a reservoir, giving higher production with less water, and help in the search for or identification of additional reserves.

PDO functions like a national oil company, although it is 40% owned by foreign firms. With the concession limited to oil, all the gas being discovered or produced by PDO belongs to the government. PDO operates the gas reservoirs and all related facilities and pipelines as a contractor on behalf of the government. Thus PDO has developed and is operating the upstream elements of Oman's two LNG export ventures on behalf of the Oil and Gas Ministry (see Gas Market Trends No. 7). Shell is also the leading offtaker of Oman's crude oils (see Part 3).

PDO Managing Director John Malcolm on Dec. 5 announced that the company's crude oil production will steady within the range of 580,000-600,000 b/d over the next three years, down from an average of 633,000 b/d in 2005. However, he forecast that EOR projects due to come on stream would increase production from 2008. He said: "If the shareholders had so wished, we could have put together a programme that would have had us exceed an average production of 600,000 b/d in the short term. But how we treat our reservoirs today...affects what they do for us tomorrow. We do no favours to Oman in going all out in one year to get a feast of oil, only to be followed by a year of famine".

PDO recently awarded the main engineering, procurement and construction (EPC) contract on Harweel Phases 2a and 2b, and the front-end engineering and design (FEED) contract on the Qarn Alam steam injection project for which shareholder approval was given last month.

EOR techniques will subsequently be extended to other fields. Malcolm said: "The first few of these EOR projects, such as the one at Harweel, will be major. But thereafter, we must treat EOR projects as a normal part of business at several of our other fields. We also have to devote some resources to search for hydrocarbons. We are confident that there are still some oil and gas fields out there that remain to be discovered".

Other major projects under way include water-flooding systems at Dhulaima and Marmul and the al-Kawther gas-gathering scheme. Several other water-flooding projects are on the agenda.

Halliburton in 2004 was awarded three major contracts by PDO worth $400-500m over five years, with optional extensions of two years. The contracts cover the provision of cementing services, stimulation services, directional drilling services, logging-while-drilling services and mudlogging services. Joe Rainey, Halliburton, vice president for the Middle East was in October 2004 quoted as saying: "Halliburton has worked with PDO from the time the first wells were drilled in Oman in 1962. Since this time Halliburton has built a relationship based on the provision of fit for purpose technology and superior service quality, delivered in close alignment with PDO's goals. The award of this...[set of contracts] furthers our commitment to Oman and the Middle East..." Halliburton said it was confident these contract awards were to allow the company to make a significant contribution towards the achievement of PDO's future production and business improvement targets.

The following are brief profiles of PDO's main fields:

Nimr, in the south found in 1980, has produced 70,000 b/d of 21[degrees] API oil from a Devonian Fm. A group of connected fields found in later years, including West Nimr, raised this system's production to 180,000 b/d. But since late 1997 they have declined and now their total output is averaging about 120,000 b/d. Their oil is heavy with high viscosity, as in the case of the Rima/Jalmud group of fields. Nimr oil from the group comes out of about 1.2m b/d of water.

This and other groups of PDO fields have a downhole oil-water system which separates the water from the oil in the well through a hydroclone (as explained earlier on).

The Nimr-Karim cluster of 18 small fields are to be developed by MedcoEnergy under a service contract awarded last month by PDO. MedcoEnergi is Indonesia's largest publicly quoted oil and gas company. The fields now produce 18,000 b/d of crude oil. A PDO press release on Jan. 24 said: "The contract was awarded on the basis of a highly competitive tender in which suitable companies from Oman and across the globe participated". The contract is aimed at raising the production levels of the fields in a cost-effective way by granting MedcoEnergy a high degree of freedom in its operations.

The contract will "thus allow PDO to dedicate its resources to the development of its larger fields, which currently account for 95% of its oil production". In 2005, the cluster accounted for about 3% of PDO's total production. At a media briefing PDO Managing Director Malcolm cited the contract as "another good example of how we have radically transformed our working relationship with contractors". He said the contract would give the service provider "a high degree of autonomy, coupled with clearly defined financial incentives, so as to improve the delivery of oil from fields that are too small and too remote to merit PDO's undivided attention".

As part of the contract, MedcoEnergi will submit a work programme for the cluster covering all aspects of its development from exploratory appraisal and sub-surface studies to well engineering and facilities construction through to operations and maintenance. MedcoEnergi will submit an annual budget for the financing of that programme. PDO, which retains full accountability for what happens in its concession area, will review and approve the work programme and budget. No sharing of the equity in the field is involved.

Fahud, found in 1963, is an oil and gas field connected to north-central trend of the Arabian Basin as in the case of Yibal and Lekhwair. Fahud and Lekhwair have a joint oil production system with a capacity of 110,000 b/d, down from 140,000 b/d in early 2004 and 180,000 b/d in 1997.

A naturally fractured field, Fahud has Lower and Middle Cretaceous Fms. The area includes a West Fahud structure to the north-west and its oil is of 32-33.6[degrees] API with 1.4-1.8% sulphur.

Lekhwair, in the north found in 1968, is PDO's second largest oil producer with its oils mostly of 37.8[degrees] API from Lower Cretaceous Fms. The field's development was completed in mid-1993, raising its capacity to 90,000 b/d, from about 26,000 b/d. But its current output is much lower.

Lekhwair produces non-associated gas from a Shuaiba Fm, which supplies the national gas grid with about 1.5 MCM/day. The rest of its gas output is used for re-injection.

Yibal, once the largest oilfield in Oman found in 1962, is producing 110,000 b/d of 38-40[degrees] API oil, down from 135,000 b/d in early 2004 and 170,000 b/d in 1997. Yibal, Shell's first discovery in Oman, also produces most of the country's needs of natural gas. The field has Lower and Middle Cretaceous Fms at depths of 8,465 feet. An expansion of Yibal to 200,000 b/d, from 120,000 b/d, was started in 1991 and completed in 1995 (see background in Vol. 58, No. 6 & Vol. 62, No. 6).

Yibal includes several satellite oil and gas fields found in recent years. Together with Yibal, these form a single geological structure with the Shuaiba Fm being the main feature. Most of Yibal expansions have involved the second phase of the Shuaiba Fm's development, tapping newly found reserves. Yibal has four gathering stations.

Yibal has two major reservoirs of non-associated gas deep beneath the oil Fms. From this most of Oman's gas is produced from two reservoirs: Natih, supplying most of the gas being fed to the domestic market through the government gas system (GGS); and Shuaiba, which provides the GGS with about 1 MCM/day. Yibal also provides most of the gas which PDO re-injects into its oilfields. The other major gas producing fields feeding this system is Lekhwair, which has a Shuaiba Fm as well. Yibal has a big gas processing plant with a capacity of 16.5 MCM/day and units producing LPG.

PDO's downhole oil-water separation system through a hydroclone was tried successfully at Yibal in 2001. The oil reaches the surface, while the water is reinjected into the reservoir. The system achieves significantly higher oil production than a gas lift.

The Bahja-Rima-Jalmud group of fields in the south produce 100,000 b/d, down from 120,000 b/d in early 2004. Bahja is one of the latest fields in the south to be developed for this system. The Rima-Jalmud structure, discovered in 1979, has long been PDO's second largest oil producer with a capacity of 90,000 b/d of 21-32.8[degrees] API viscous oils from a Paleozoic Fm at depths of 3,247 and 4,250 metres. But its output has fallen since 1997. The group includes North Jalmud found in 1980. To boost these fields' capacity and reduce costs, PDO has installed a computerised beam pump control on their wells. This is part of PDO's computer-assisted operations (CAO).

Most PDO wells have some form of artificial lift system. As a result, they need constant operator intervention. But operations are carried out by remote control. The CAO system also reduces safety risks, with personnel not needing to travel to the field, and improves the reliability of facilities. Fit to purpose, adjustments have resulted in a 5% improvement in the performance of gas-lift facilities.

PDO provides access to any remotely controlled field operation from a desktop, through the application of Fieldware. The first fieldware modules were installed at the Marmul and al-Huwaisah fields, near Yibal.

PDO late 2005 awarded the main engineering, procurement and construction (EPC) contract on the Harweel fields' Phases 2a and 2b which will use the miscible gas injection method, and the front-end engineering and design (FEED) contract on the Qarn Alam steam injection project for which shareholder approval was given last month.

These two major projects and other EOR systems are expected to raise PDO's output by 150,000 b/d to about 820,000 b/d for oil and condensate by late 2008 or early 2009.

Qarn Alam, a central Omani field found in 1972, is one of PDO's difficult oil structures. Its production capacity by 1997 had reached about 100,000 b/d but its current output is averaging about 80,000 b/d, down from 90,000 b/d in early 2004. The field has a Lower Cretaceous Fm yielding highly viscous oils of 14.8-16[degrees] API. Because of the oil's high viscosity and low permeability, the recovery rate at first was less than 2% of the reserves in place.

The oil is mostly submerged in water. In late 1995, a two-well pilot system was installed for thermally-assisted gas/oil gravity drainage (GOGD) to raise the recovery rate to 20%, 40 MCM of oil, by means of crestal steam injection. The aim was to reduce the oil's viscosity through heat. But the project failed. Installations included a 450,000 gallons/day desalination plant for brackish water (water distilled by a 29-metre high brine concentrator tower), a gas-fired steam generator and steam injection pumps. Initial results showed that oil production increased by about 600 cubic metres a day; but later this fell considerably.

PDO then embarked on a $250m project, one of the largest to be undertaken by the company, for a commercial plant to be built. This will deliver 12,000 tons/day of steam to be injected into the Qarn Alam reservoir, which is a compact and dome-shaped structure. The new project will include a steam plant, steam injection and water treatment facilities, and a heavy oil handling system. Power will come from a captive 140 MW plant. PDO has revised its recovery forecast for the field to 39.2m cubic metres from 4.4m cubic metres.

Marmul, part of the southern trend, was found in 1956 as the first oil discovery in Oman. It was found by Cities Service Co. and Richfield Oil of the US, which later relinquished the area to PDO. A connected structure at Marmul was found in 1977 by PDO. Marmul produces viscous 22[degrees] API oil from Paleozoic and Permian Fms.

To boost production and reduce costs, PDO in 1991 installed a computerised beam pump control system on 100 of its wells. It has also installed a system using polymer flooding. Near Marmul a major oil and gas field has been discovered and developed at al-Noor (see below). Together, Marmul and Athel now produce 55,000 b/d, down from 60,000 b/d in early 2004.

Athel, a very complex structure in the south near Mukhaizna, has been developed gradually. Phase 1 has involved a $165m pilot project for the Athel reservoir to produce 10,000 b/d from six multilateral and high-reach horizontal wells from mid-2000. The Athel Fms, containing both very heavy and sweet oils, are about 4,500 metres deep.

Athel had been penetrated many times before in the course of drilling in the south but had never proven to be productive. Apart from its oils, Athel is said to contain almost 100m barrels of gas liquids and a major gas reserve. Athel's al-Shomou fm is said to contain over 3 bn barrels of heavy oil in place. Together, Athel, Mukhaizna, al-Noor and Al Shomou fms are said to have 4.4 bn barrels of oil in place. They are all complex and require high technology which Shell is developing. The fms have high pressure.

PDO, which brought al-Noor and al-Shomou on stream in 2000, has aimed to reduce costs at these fields below $10/barrel. Al-Noor's development has included a 1,500 CM/d pilot processing plant for oil and associated gas.

Al-Huwaisah, found in 1968, is part of the northern trend which includes Yibal, Natih and Fahud. Its oil comes from a Lower Cretaceous Fm at a depth of 5,320 ft but the output is small. Natih, a fractured oil and gas field on the same trend as Fahud, was found in 1963. It has similar Lower and Middle Cretaceous (L&MC) fms. It has been developed for a capacity of 30,000 b/d of 31.3-33.4[degrees] API oils with 1-1.5% sulphur, but production has declined considerably in recent years.

PDO has drilled new wells at Natih and Fahud which, by injecting gas into them, lowered the oil rim in both structures. The oil rim at Natih was lowered by 80 metres to expose more reservoir matrix to a new drainage process applied. An increase in reserves, with the recovery rate improved from 16% to 20% of the oil in place, resulted from a downdip production of water from below the fracture oil rim, together with an aquifer influx.

The Amal group of fields in the south have been developed for a capacity of about 20,000 b/d of very heavy, 19-22.5[degrees] API oil with high viscosity, but their actual output has declined considerably. Amal was discovered in 1973. East Amal was found in 1977. South Amal was found in 1982. All have Devonian and Oligocene Fms. The production cost at this group is high.

To improve the recovery rate, PDO in 1991 installed a steam-soak system. This involved the drilling of five additional wells at East Amal which contained about 400m barrels of very heavy oil and only minor quantities could be recovered through primary means. In mid-1992, another four steam-soak wells were completed at the same structure, together with a sixth well to provide an electromagnetic heating of the reservoir.

Sayyala, found in 1982 in the south, produces 49.7[degrees] API oil from a Permian Fm. It's output is very small. Birba, another field in the south found in 1978, produces a small quantity of 33.4[degrees] API oil with a high sulphur content. The field also produces gas, which is partly re-injected into the reservoir to maintain pressure and partly piped north to Saih Nihayda.

A $35m gas injection project for Birba was completed in 1993 to double the field's oil production capacity from 4,200 b/d but output has since fallen sharply.

Saih Nihayda, found in 1972, is a small field producing 39.6[degrees] API oil from a Permian Fm. But it has huge reserves of non-associated gas which have been developed for LNG export, together with the non-associated gas reserves of Saih Rawl and Barik (see below). Saih Nihayda's oil production averages less than 5,000 b/d, compared to almost 9,000 b/d in early 1998 and over 15,000 b/d a few years earlier.

In 1998, PDO added to the oil stream small Saih Nihayda extensions with their proven reserves then totalling about 5m barrels.

Harweel and Sarmad clusters of oilfields in the south were found in late 1998 and early 1999 by PDO, among 33 structures identified by the company in that region. Ghafeer was discovered in mid-1999 in an adjacent area. Its well flowed at more than 6,500 b/d. All of these structures are complex and at depth of about 4,500 metres.

The cluster of Harweel fields is being developed by PDO which says its reserves will contribute significantly to the company's oil production potential. The combined EOR and development project, involving the Harweel 2a and 2b phases, was awarded in November 2005 to Petrofac Int'l, along with Oman's Galfar Engineering & Contracting. Worth $960m, this was a project management consulting (PMC) and detailed EPC contract aimed at boosting the cluster's output to 100,000 b/d by late 2008 so that total PDO production by then has been stabilised at 820,000 b/d. The main element of this contract is an extensive EOR facility based on a miscible gas system.

The Harweel cluster, in the far south, comprises nine fields containing sweet oil. The first development phase in 2004 enabled the cluster to produce 15,000 b/d, though the output now is much lower. Its installations include a pilot gas injection plant and infield pipelines. But Harweel's Phase-I EOR system is based on water flooding.

A group of small fields, Maurid, Maurid North-East, Wazar, Amab and Tuqaa went on stream in 1998 with a combined capacity of 4,560 b/d and total proven reserves of over 18.4m barrels. But their output has since fallen considerably.