OMAN - Oil Producers.
Petroleum Development Oman: PDO is owned 60% by the Omani government, 34% by Shell which is the technical manager, 4% by Total and 2% by Partex. The Shell-led foreign partners in PDO in 2002 began negotiations with the government to renew their concession. 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.
In mid-2009 PDO announced on its website four projects worth a total of up to $7bn for its oilfields. It said of the four contracts on offer, two each were on fields in the country's north and south. One contract in each area was to cover engineering and maintenance at fields, each with annual turnover of up to $200m. Two other contracts worth up to $150m a year were to cover work offsite from the oilfields, such as hooking up pipelines, again one in the north and one in the south. The deals have a duration of seven years, with an option to extend for three more.
Innovation has been key to PDO's success. But PDO has not been restricted to field development. Its automated procurement systems have meant a near trouble-free relationship.
Shell Development Oman Chairman Andrew Wood in June 2009 was quoted as saying: "The history of oil production in Oman is unique. It is not like the North Sea, where there were oil discoveries, massive production levels and then fast declines. There had been a steady increase in oil production until the turn of the millennium. It is a reflection of the country's complex geology, where exploration is far less efficient than normal. But technology is evolving and enabling a steady increase in recovery, up to 20% in some fields". He added: "The easy oil has all been found and developed and now all that is left is the difficult stuff".
Shell Development Oman remains optimistic about the future of Oman's oil sector. The relationship with the government, according to Wood, is one of mutual partnership and the "maximum exchange of knowledge". In 2006, Shell launched Shell Technology Oman, an EOR research and development centre in Muscat. The centre works closely with Sultan Qaboos University's Oil & Gas Research Department and PDO.
The geology of Oman's petroleum fields reflects its harsh topography, with most of them deep and tight, making extraction extremely difficult. The new projects rely on expensive EOR systems to extract what remains in the oilfields. PDO has more than 20 EOR projects.
PDO in early February 2009 announced discovery of three new oilfields. Two of the new fields - Taliah and Malaan West - are among PDO's Lekhwair cluster of fields in the north-west. They are part of the Upper Shu'aiba formation (Fm), which contains many of the reservoirs of PDO's main fields. The third - Rabab South-East - confirmed the preliminary results of well tests PDO mentioned in 2008. Oil production from Rabab South-East began later in 2009, through the existing facilities at Harweel field in the south.
Drilling and studies in 2008 enabled PDO to better estimate the extent of petroleum volumes at the Burhaan West and Fahud SW gas fields, as well as at the Budour NE oilfield found in in previous years. The reservoirs of Burhaan West and Fahud SW have low permeability. As a consequence, the reservoir rocks first had to be cracked with extreme hydraulic pressure.
PDO's first EOR projects were in fields near Nimr, around Harweel, in Qarn Alam, at Marmul, and at Fahud. Near Nimr, PDO has pilot steam injection systems in Amal West, Amal East and Thayfut fields. It injects miscible sour gas into a cluster of fields near Harweel. At Qarn Alam, PDO has a thermally assisted gas-oil gravity drainage (TAGOGD) system in a heavy-oil fractured carbonate reservoir. It is injecting polymer in a heavy oil reservoir at Marmul. At Fahud, the EOR system, also TAGOGD, injects steam to accelerate recovery of light oil from a fractured carbonate. PDO is to complete full field steam-injection facilities in 2010 and in 2013 add a power plant to provide additional heat for steam generation.
The Amal fields produce heavy oil from beam pumped wells with depths varying from 500 to 1,000 m. PDO built an 800 CM/d water treatment plant for Amal West and Amal East. Two skid-mounted 200 t/d portable gas-fired steam generators provide the steam.
In the south, PDO has the facilities for the Harweel Phase-2AB miscible sour-gas injection system to be completed in in 2010. PDO found Harweel in 1997 and since has found seven similar fields containing intra-salt carbonate stringers in a large 1,000 sq km area. It estimated the cluster contained an initial 1.8bn barrels in place of light sour oil and retrograde condensate. The cluster includes Shujirat, Sakhiya, Harweel Deep, Sarmad, Ghafeer, Dafiq, Dhahaban South, and Zalzala. PDO has drilled more than 60 wells in these fields and in Phase-1 has produced oil from four fields and injected gas in Zalzala to confirm the viability of miscible sour gas injection. During Phase-1, PDO produced about 18,000 b/d from the Harweel cluster.
Production could rise to more than 100,000 b/d once the Phase 2AB project is completed. The crude oil found there cluster is some of the oldest on earth. PDO estimates a 10% ultimate recovery without miscible sour-gas injection which may increase to more than 30% with injection. The Harweel facilities will process very corrosive fluids, so that much of the installed equipment and piping is made from corrosion-resistant alloys.
PDO found Qarn Alam in 1972 and estimates that initial oil in place in the field's fractured carbonate reservoir was 1bn barrels. Without the thermal project, only a 4% of the oil can be recovered from the field. But with its TAGOGD project, ultimate recoveries may exceed 32%. PDO says Harweel and Qarn Alam later in 2010 will each add 40,000 b/d.
In April 2007, PDO began work on a shake-up of its engineering operations by employing an in-house front-end engineering and design (FEED) office for the first time. Under the terms of the initial five-year cost-plus contract, the successful design firm was to assign up to 30 staff to PDO, working with existing staff and employees assigned from Shell (see the background in omt6OmanFieldsFeb4-08).
PDO has more than 120 oil and gas are on stream connected to its production system in onshore Oman's four main oil fairways, which are as follows: (1) 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; (2) the north-central groups in the Infracambrian Salt Basin, which include the main producing fields like Yibal and fields centred on Natih-Shibkah; (3) the central and west-central groups, also in the Salt Basin, which include the gas-rich Saih Nihaydah; and (4) 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 find in excess of expectations. These wells stretch 500m to 1.5 km along a reservoir, giving higher production with less water, and help in the search for or identification of additional reserves. Below are brief profiles of PDO's main fields:
Nimr, and oil and gas field in the south found in 1980, produces 21? API oil from a Devonian Fm. A group of connected fields found later, including West Nimr, raised this system's output to 180,000 b/d. But since late 1997 they have declined and now their output is averaging 100,000 b/d. Their oil is heavy with high viscosity, as in the case of the Rima/Jalmud group.
Nimr oil comes out of 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. In early 2008, al-Hassan Engineering got a $65m job to drill 89 water production wells and 19 injection wells by 2010. Nimr is having a gas compressor station contracted in 2009 and a sewage treatment system to pump effluent water from the wellhead which will be used grow biofuel crops in the desert. PDO has opted for the contractor to use "desert greening" technology to grow reed beds for effluent treatment at the field. The treated water can then be used for irrigation.
A biological solution was preferred to mechanical treatment as it is more environmentally friendly and does not require expensive gas feedstock. The system will take 45,000 CM/d of water from the field, treat it and use it to grow the crops for biodiesel production. It is the first time such a project has been launched in the Middle East.
The treatment and disposal of water is a major issue for PDO. At some of its mature fields, PDO produces five barrels of water for every barrel of oil, compared with the industry standard of three to one.
The Nimr-Karim cluster of 18 small fields in the south are developed by MedcoEnergy under a PDO service contract (SC) won in January 2005. MedcoEnergi is Indonesia's largest publicly quoted E&P company. The fields in early 2005 were producing about 18,000 b/d of crude oil. A PDO press release on Jan. 24, 2005, 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 final SC was signed in March 2006. A new firm was then floated by MedcoEnergi and the state-owned Oman Oil Co. (OOC) to execute the SC. OOC has 25% in the new firm.
Fahud, found in 1963, is an oil and gas field in the north-central trend of the Arabian Basin like Yibal and Lekhwair. Fahud and Lekhwair have a joint oil production system with a capacity of 100,000 b/d, down from 140,000 b/d in early 2004 and 180,000 b/d in 1997. A fractured field, Fahud has Lower and Middle Cretaceous Fms. The area includes West Fahud to the north-west and its oil is of 32-33.6? API with 1.4-1.8% sulphur.
Lekhwair, in the north found in 1968, is PDO's second largest field with its oils mostly of 37.8? 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 Shu'aiba Fm, which supplies the national grid with about 1.5 MCM/d. The rest of its gas output is used for re-injection.
Yibal, once the largest oilfield in Oman found in 1962, produces 100,000 b/d of 38-40? API oil, 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 ft. 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 Shu'aiba Fm being the main feature. Most of Yibal expansions have involved the second phase of the Shu'aiba 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 government gas system (GGS); and Shu'aiba, which provides the GGS with about 1 MCM/d.
Yibal provides most of the gas which PDO re-injects into its oilfields. The other major gas producers feeding this system is Lekhwair. Yibal has a 16.5 MCM/d gas processing plant and LPG units. 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 fields in the south produce 80,000 b/d, from 120,000 b/d in early 2004. Bahja is one of the latest fields in the south to be developed for this system. Rima-Jalmud, found in 1979, had long been PDO's second largest oil producer with a capacity of 90,000 b/d of 21-32.8? API viscous oils from a Paleozoic Fm at depths of 3,247 and 4,250m. But its output has fallen since 1997. The group includes North Jalmud found in 1980. To boost capacity and reduce costs, PDO has installed a computerised beam pump control on their wells. This is part of PDO's computer-assisted operations.
Most PDO wells have some form of artificial lift system. As a result, they need constant operator intervention. But operations are done by remote control. The CAO system 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 Marmul and al-Huwaisah fields, near Yibal.
Qarn Alam, a central Omani field, is one of PDO's most difficult oil structures. Its capacity by 1997 had reached 100,000 b/d. But its output by end-2007 had dropped below 1,000 b/d. Now PDV is re-developing the field with the hope of producing 40,000 b/d later in 2010. The field has a Lower Cretaceous Fm yielding highly viscous oils of 14.8-16? API (see above & omt6OmanFieldsFeb4-08).
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? 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 uses polymer flooding. Near Marmul a major oil and gas field was developed at al-Noor. Together, Marmul and Athel produce 55,000 b/d, from 60,000 b/d in early 2004.
Phase-3 of Marmul's development will raise water handling capacity from 25,000 CM/d to 60,000 CM/d, to improve reservoir recovery, raise water injection capacity to 30,000 CM/d and increase oil export capacity to 15,000 CM/d. Phase-3 will include water tanks, bulk separators, water booster and injection pumps, an automation and control system, a water treatment unit and associated infrastructure.
Athel, a very complex structure in the south near Mukhaizna, has been developed gradually. Phase-1 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 4,500m 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 was said to contain almost 100m barrels of gas liquids and a major gas reserve. Athel's al-Shomou Fm was said to contain over 3bn barrels of heavy oil in place.
Together, Athel, Mukhaizna, al-Noor and al-Shomou Fms were 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/b. 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? 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 80m 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 about 20,000 b/d of very heavy, 19-22.5? 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 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? API oil from a Permian Fm. Its output is small.
Birba, another field in the south found in 1978, produces a small quantity of 33.4? 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 in central Oman, is a small field producing 39.6? API oil from a Permian Fm. But this has huge reserves of non-associated gas developed for LNG export, together with the non-associated gas reserves of Saih Rawl and Barik. Saih Nihayda's oil output 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 put at 5m barrels. Saih Nihayda also produces condensate from the field's gas reservoir.
PDO in late 2009 gave a $250m EPC contract for the field's massive gas compression project to GS Engineering & Construction of South Korea. This covers installation of gas compressor units supplied by GE Oil & Gas of the US, and subsidiary work including construction of gas sub-stations at the field. GS will debottleneck existing facilities, raising the volume of gas they can handle to 25 MCF/day, from about 20 MCM/d. The project will enable PDO to maintain reservoir pressure at the field for several years beyond its forecast start of declining in 2015. PDO says the project is the first to have been designed in-house by the company's front-end engineering and design (FEED) team, set up in February 2008.
Saih Nihayda's gas reservoir has been producing since it was commissioned in early 2005. Gas from the field is treated at a local processing plant from where it enters the government gas grid. Based on current demand patterns.
Harweel and Sarmad field clusters 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 found in mid-1999 in an adjacent area. Its well tested over 6,500 b/d. All of these structures are complex and at a depth of about 4,500m. The cluster of Harweel fields is being developed by PDO which says its reserves will contribute significantly to its output.
The combined EOR and development job for Harweel 2a and 2b phases was given 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 to boost the cluster's output to 100,000 b/d in 2010. The main element of this contract is a major EOR facility based on a miscible gas system (see OMT6).
The Harweel cluster, in the far south, has nine fields containing sweet oil. The first 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. Harweel's Phase-I EOR is based on water flooding.
Among PDO's projects under construction are the installation, testing and pre-commissioning of a pipeline between the Hubara compressor station to the Marmul oilfield, and another pipeline between Harweel and Marmul. The work involves construction of an 18-inch pipeline by converting a existing 84-km oil pipeline between Marmul and Nimr fields, adding a new 75-km section between Nimr and Hubara, installing a 16-inch gas export pipeline between Harweel and Marmul, two block valve stations between Harbura and Amal field, receivers and launchers, tie-ins, and pressure reduction stations.
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.