The sultanate’s geographic position on the Arabian Peninsula, in close proximity to the Arabian Gulf and the Gulf of Oman, but outside the Strait of Hormuz, has given it the region’s best access to one of the world’s most important energy corridors. Following several years of declining output in the 2000s, plans are under way to increase crude oil production, and the sultanate’s comparatively liberalised market has seen a host of new partnerships with the private sector lead to some of the most advanced enhanced oil recovery (EOR) projects in the world. At the same time, Oman is expected to substantially increase its supply of natural gas via Iranian imports, as well as domestic production at the Khazzan tight gas reserves, which offer the most significant new opportunities for stakeholders.
Downstream, new refinery and petrochemical developments at Duqm and Sohar will see Oman capitalise on its geographic location. Although falling world oil prices have created a stormier forecast for the future growth of hydrocarbon export revenues, rising domestic demand within the sultanate, coupled with value chain enhancements and targeted economic diversification policies, should see the sultanate avoid the worst of global market shocks over the longer term.
Sector Overview
The Ministry of Oil and Gas (MoG) is responsible for overseeing Oman’s hydrocarbon sector, including coordinating projects in partnership with the private sector. The Oman Oil Company (OOC), operating under the MoG, is responsible for energy investments, undertaken by subsidiaries including Takamul and Oman Oil Company Exploration and Production, while the Oman Oil Refineries and Petroleum Industries (ORPIC) controls the sultanate’s refining sector, and owns both operating refineries: Mina Al Fahal Refinery, in Muscat, and the Sohar Refinery, located in proximity to ORPIC-owned aromatics and polypropylene plants.
Petroleum Development Oman (PDO), which is 60% owned by the government, 34% by Royal Dutch Shell, 4% by Total and 2% by Portuguese firm Partex, holds the vast majority of Omani oil reserves, and oversees approximately 70% of total crude production in the sultanate. The company also represents the driving force in natural gas production, accounting for nearly 100% of total supply, outside of contributions from Occidental Petroleum and Thailand’s PTTEP.
Gas transmission and distribution is directed by the Oman Gas Company (OGC), an 80:20 joint venture (JV) between the MoG and OOC, while Oman Liquefied Natural Gas (OLNG) – owned by a consortium including the government, Shell and Total – operates all liquefied natural gas (LNG) activities in Oman through its three liquefaction trains in Qalhat near Sur.
International Interest
International oil companies (IOCs) play a prominent role in Oman’s oil industry, and the government frequently enlists IOCs to undertake new exploration and production projects, particularly those utilising EOR and natural gas extraction projects. Oman’s vast, rocky and mountainous terrain has produced some of the most technically challenging fields in the region, and contract terms for IOCs have become more favourable in the sultanate than anywhere else in the GCC. “Oman is different in that the country’s hydrocarbon resources are spread over a large area and hard to extract. Because of this, the country has been more receptive to IOC involvement in the sector,” Shahrokh Etebar, CEO of CC Energy Development, told OBG. IOC Occidental Petroleum, for example, is the second-largest oil producer in Oman through Oxy Oman, while other major players include Shell, BP, Total, CNPC, KoGas, Partex and Repsol.
As in the rest of the GCC region, Oman is highly dependent on oil revenues, although the sultanate’s Vision 2020 economic development plan aims to reduce oil’s share of GDP to 9% by 2020. This ambitious goal is unlikely to be achieved within five years; Oman is dependent on oil export revenues, while rising domestic consumption and a growing petrochemical sector that is heavily reliant on liquefied petroleum gas (LPG) and natural gas liquids (NGL) means the sultanate will find it challenging to reduce oil dependency, at least in the short term. Indeed, the hydrocarbons sector accounted for 85.7% of government revenues in 2013, according to the Central Bank of Oman (CBO), while oil and gas revenues comprised 39% of GDP, and 66% of total merchandise exports, including re-exports.
Crude Reserves
Oman is the largest non-Organisation of Petroleum Exporting Countries (OPEC) oil producer in the Middle East. According to Nasser bin Khamis Al Jashmi, former undersecretary of the MoG, Oman held an estimated 50bn barrels of total oil reserves as of August 2013, while BP’s 2014 Statistical Review of World Energy reported that Oman held 5.5bn barrels of proved reserves, representing the seventh-largest reserves in the Middle East, and 23rd-largest worldwide. The majority of oil production is extracted from the Oman Basin, with PDO’s Block 6 comprising 70% of total production. The Yibal, Al Ghubar, Qarn Alam, Marmal and Harweel fields represent the mainstay of Oman’s oil production, although they began to decline in the early 2000s. Yibal, for example, began production in 1968, reaching peak production of 250,000 barrels per day (bpd) during the late 1990s, before declining to 80,000 bpd by 2003. PDO has since drilled 500 horizontal wells and introduced EOR to the field, which is expected to boost recovery rates to 55%, from 42% in 2004. Oman has two offshore producing fields adjacent to the Musandam peninsula, Bukha and West Bukha, which are operated by RAK Petroleum and DNO Oman. The Bukha field has produced since 1994, and the West Bukha field began production in 2008.
New discoveries have helped bolster supply. According to an August 2014 article in Oil Review Middle East, as many as 16 local and international companies are currently exploring for hydrocarbons under production sharing agreements signed with the MoG. New exploration has been driven in large part by PDO, which in 2009 discovered an estimated 1bn barrels of crude reserves in the Al Ghubar South field, located near the Al Ghubar and Qarn Alam fields. Local media reported in 2009 that the Al Ghubar South field represents one of Oman’s most significant oil discoveries ever made. In 2009 PDO also discovered new reserves at Malaan West, and Taliah in the north-western cluster of Lekhwair, part of the Upper Shuaiba geological formation, which contains many of PDO’s main reservoirs.
The South Oman Salt Basin could hold significant resources as well. A 2012 report published by the US Geological Survey found that undiscovered reserves in the basin totalled 370m barrels of oil and 315bn cu feet of natural gas, as well as over 40m barrels of NGL.
In October 2013 PDO announced plans to invest $11bn in 16 new projects over the next 10 years, which will add an estimated 1bn barrels of oil to the sultanate’s total reserves, and in August 2014, the Omani government asked PDO to boost its production to 600,000 bpd in 2015, following nine months of successful expansion in which the company increased production from a plateau of 500,000-550,000 bpd to 570,000 bpd. The company’s production maintenance and expansion is supported by three distinct pillars: exploration, well, reservoir and facility management (WRFM), and EOR activities. As Raoul Restucci, managing director of PDO, explained to OBG, “Over the last few years we’ve been very successful on the exploration front, adding more and more barrels every year. WRFM enables us to make the most of what we have, and entails a work programme of around 15,000 well interventions to optimise existing production. This is an area where PDO has been recognised as a global leader; decline rates at mature fields averaged in excess of 20% per annum 10 years ago, and today are down to 8-9%, with some fields as low as 1-2%, thanks to continuous restoration and optimisation. For our third pillar, the vast majority of our EOR activities have been exceeding expectations, often enhancing production beyond initial primary or secondary recovery phases. The Marmul field, for example, has increased production more in the past few years than during the previous 30, thanks to the successful polymer EOR and WRFM well-by-well and sector-by-sector optimisation.”
EOR
Oil and gas production in Oman relies heavily on EOR, which has helped production improve from 710,000 bpd in 2007 to current levels of around 945,000 bpd. PDO is already working to boost production at Yibal, a mainstay of Omani production, through traditional water and steam flooding, while a number of up-and-coming EOR techniques, including polymer and miscible techniques, are already employed at fields in Oman. Growing natural gas consumption has led the government to pursue new solar-generated EOR projects, following a successful pilot project in 2013.
PDO’s Block 6, which spans the Marmal, Harweel and Qarn Alam fields, is at the centre of current EOR activities. Block 6’s fields employ EOR techniques including polymer EOR, which uses polymer fluids rather than water injection to access heavier crude reserves, and is employed at Marmal, miscible gas EOR in the Harweel field, and thermal/steam injection EOR at Mukhaizna, Marmul, Amal-East, Amal-West and Qarn Alam fields.
One of the most commonly used EOR processes in Oman is thermal, or steam injection, which involves injecting gas or solar-heated steam into producing fields to facilitate the flow of heavier oil. Steam injection at Qarn Alam could enable the field to increase production by an additional 40,000 bpd by 2015, using a process in which steam drains oil to lower producer wells, while the EIA reports that thermal EOR could add 23,000 bpd of production at the Amal east and west fields by 2018. Steam injection EOR is also being deployed at the Mukhaizna, Marmul, Amal-East, Amal-West and Qarn Alam fields. Outside of water and steam injection, miscible EOR is one of the most commonly used EOR techniques in Oman. Miscible EOR entails pumping oil-dissolving gases into heavy reserves, facilitating higher flow rates. As a result of this, at Harweel developers were able to produce an additional 40,000 bpd, according to the EIA. EOR has also been introduced at the Karim cluster, comprised of 18 small fields flowing to the Nimr production facility, and expected to boost production from 18,000 bpd to 35,000 bpd, and the Harweel cluster, where production is expected to expand to 100,000 bpd from 44,000 bpd.
However, miscible gas and gas-powered thermal EOR processes are adding pressure to the sultanate’s already-limited natural gas resources. According to the MoG, gas injection into oilfields stood at 319.6mcf per day in 2013, a 5% increase over 2012, and expected to further grow as the share of production from EOR rises from 3% in 2012, to 25% by 2020. Miscible and steam injection schemes consume sizeable quantities of natural gas, and the sultanate has recently moved forward on innovative new solar-powered EOR schemes in an effort to reduce EOR-driven gas consumption, in partnership with American firm GlassPoint (see analysis.) PRODUCTION: Average daily production of oil has rebounded in Oman over the past seven years, despite earlier declines at major fields, due in large part to the introduction of EOR techniques. The National Centre for Statistics and Information (NCSI) reported that oil production stood at 852,000 bpd in 1995, expanding to a peak of 955,000 bpd in 2000, before dropping to 710,000 bpd in 2007, as mature fields began to decline. The government was able to halt that decline with the introduction of EOR, although recent discoveries of new reserves have also helped bolster production, which reached 918,500 bpd of crude oil in 2012. Production rebounded further in 2013; according to the CBO, Oman’s daily average increased to 941,900 bpd, while total annual crude oil production grew by 2.3% in 2013 to 348.3m barrels, from 336.2m barrels in 2012. The EIA expects the government to maintain average production of 940,000 bpd until 2018.
Production growth slowed in 2014, expanding by 1.1% during the first seven months of the year to reach 200m barrels, compared to 198m barrels during the same period in 2013, according to the NCSI. The increase in oil production was attributed to growth in crude production, which expanded by 2.5% to reach 182.3m barrels, compared to 177.8m barrels between January and July 2013, although condensate production declined by 11.8% to reach 18.1m barrels during the same period. Average crude production stood at 945,600 bpd, against 935,700 bpd during the same period in 2013.
Prices
Although production has seen a remarkable resurgence in the previous seven years, falling oil prices are a concern for the economy, as indeed they are to all GCC economies. Oman’s sole export stream is its Oman blend, a medium-light, high-sulphur crude product whose price averaged $105.50 per barrel in 2013, compared to $109.60 in 2012.
The NCSI reported that oil prices per barrel declined by 0.3% during the first half of 2014, dropping to $105.40 per barrel, compared to $105.70 in 2013, and CPI financial reported in October 2014 that prices averaged $103.43 per barrel between January and mid-October 2014. The IMF also forecast world oil prices to average $104.17 a barrel in 2014, and $97.92 a barrel in 2015, although these projections were made in May 2014; between June and mid-October, the global oil benchmark shrank more than 20% to reach an average of $92 a barrel, from a 2014 high in June of $115 per barrel. OPEC supply has remained high, with Saudi Arabia moving to maintain its market share by dropping prices and maintaining export levels, while demand in the US and Europe has dropped off.
Oman’s fiscal breakeven price for oil in 2013 was set at $104 per barrel for the 2013 budget, slightly below 2012’s $109 per barrel, but considerably higher than in Saudi Arabia ($92), UAE ($90), and Kuwait ($59.) In July 2014, the Economist Intelligence Unit warned that Oman’s national account faces a serious deficit if the price of oil drops, and remains, at a price substantially lower than $106 per barrel, while ratings agency Standard and Poor’s (S&P’s) reported in June 2014 that of all the GCC nations, Oman and Bahrain are the most vulnerable to declining oil prices. Prices have fallen substantially lower than $104-$106 per barrel; on October 15, Oman blend prices hit a four-year low, falling to $83.06 per barrel. Then, in mid-December 2014 Oman blend price dropped to a low of $60 per barrel.
Exports
With prices forecasted to remain weak into 2015, Oman is facing diminished oil revenues, highlighting the need to enhance downstream value addition. “Oman is at the mercy of the global energy market. As an oil producer, volatility on the global scene causes waves and stalls and developments here at home,” said Reinhart Samhaber, general manager of DNO Oman, a Norwegian exploration and production company focused on the Middle East and North Africa.
In 2013 oil exports showed strong growth, rising by 8.7% to reach 304.3m barrels, compared to 279.8m barrels in 2012, but have since slid in the wake of declining world prices. The NCSI reported that oil exports declined by 3.5% during the first seven months of 2014, falling to 171.9m barrels, compared to 178.2m barrels during the same period in 2013. China represents Oman’s largest export market, buying 382.8m barrels, or 50% of Oman’s total production in 2013, followed by Japan (104.4m barrels), Taiwan (91.3m barrels), Singapore (54.4m barrels), Thailand (51.9m barrels), South Korea (29.8m barrels), New Zealand (16.4m barrels), India (14.2m barrels), and the US (5.5m barrels.) In 2014 most of these countries reduced their imports; Although imports to China expanded by 16.9% to reach 117.1m barrels between January and July, Taiwanese imports declined by 6.9% to 20m barrels, while Japanese imports recorded a 29.5% decrease, reaching 11.6m barrels compared to 16.5m during the same period in 2013.
Natural Gas
The CBO reported that Oman contained 24.91trn cu feet of aggregate gas reserves as of 2013, with 35 producing gas fields currently in operation. In 2011, the sultanate was the fifth-largest dry natural gas producer in the Middle East, and 26thlargest worldwide, with a significant portion of production stemming from oil extraction, leading to heavy new demand on gas supply as EOR projects ramp up.
The sultanate inaugurated two new LNG facilities, in 2000 and 2005, boosting LNG production, which had averaged 154bn cu feet annually between 1990 and 1999, according to the EIA. The NCSI reported that non-associated production, including imports, declined by 6% between January and July 2014, reaching 641bn cu feet, compared to 681.82bn cu feet during the same period in 2013, while associated production shrank by 0.4% to 120.18bn cu feet, compared to 120.67bn cu feet between January and June 2013.
Domestic consumption has expanded considerably over the past decade. The EIA reports that natural gas consumption rose by 168% between 2002 and 2011, with total production reaching 1.31trn cu feet in 2013, including 242.04bn cu feet of associated gas, and 1.07trn cu feet of non-associated gas, a 3.2% increase over 1.27trn cu feet in 2012. The use of natural gas in power generation grew by 9.5% to reach 135.08bn cu feet between January and end-June 2014, from 123.35bn cu feet in the first half of 2013. Growth was driven almost entirely by residential demands; consumption by industrial areas declined to 11.3bn cu feet by the end of June 2014, and consumption by the industrial sector also declined by 5.1% to 362.04bn cu feet, while oilfield consumption declined by 19.4%, to reach 132.57bn cu feet, according to the NCSI. Oman’s leadership has recognised the need to shore up Oman’s gas reserves, and Salim Al Aufi, newly-appointed undersecretary of the MoG, said in March 2014 the ministry plans to expand gas production by an additional 17.65% between 2014 and 2018, to reach 4.24bn cu feet per day.
Iran & Khazan
In a move expected to further bolster supply, the government signed a memorandum of understanding with Iran for a natural gas import contract, which could see a $60bn, 25-year supply deal commence in the next several years, via a pipeline running under the Gulf of Oman. Iran is expected to supply Oman with 706.3m cu feet of gas per day. More significantly, the sultanate is home to the Khazzan tight gas fields, which could offer an additional 1bn cu feet per day of capacity of natural gas. BP Oman is currently developing the fields, announcing plans to begin production in 2017, while the offshore Abu Butabul field in Block 60 became the first producer of tight natural gas in October 2014, with full operations expected to deliver an additional 70m cu feet per day (see analysis.) GAS EXPORTS: As a member of the Gas Exporting Countries Forum, the sultanate exports natural gas as LNG through two liquefaction facilities near Sur, around 200 km south of Muscat. Almost all LNG exports are sold to Japan and South Korea, and export volumes have risen in recent years. The MoG reported that total LNG exports expanded by 7.9% to reach 8.93m tonnes in 2013, from 8.37 tonnes in 2012, nearly a three-fold rise over 2.32m tonnes in 2003. In September 2013, OLNG and the government-owned Qalhat LNG began a merger in an effort to streamline the sultanate’s LNG sector. The new company is also called Oman LNG, and today it controls all three of the sultanate’s LNG trains, which offer a combined capacity of some 500bn cu feet.
Oman’s sole natural gas pipeline, the Dolphin pipeline, runs from Qatar to Oman via the UAE, and the sultanate imports an estimated 51bn cu feet of natural gas from Qatar annually. Imports are becoming increasingly necessary to meet rising domestic consumption, which expanded by nearly 390bn cu feet between 2000 and 2011, according to the EIA. As a result of rising consumption, OLNG plans to divert all currently exported volumes of LNG into the domestic market by 2024.
The decision can be partially attributed to challenges in securing the best prices for long-term gas supply contracts. As Interfax Energy reported in August 2014, many of Oman’s LNG export contracts were signed over a decade ago, while changes to the gas market have seen production and import prices soar since then. Although, as Harib Al Kitani, the CEO of OLNG, has reported, Oman’s LNG is among the highest-priced LNG exported to South Korea, with South Korean imports regularly selling for more than $18 per million British thermal units (BTU), prices to Japan average $10 per million BTU, compared to average import prices of $16.20 per million BTU, making Oman Japan’s cheapest source of LNG imports.
The sultanate earned an estimated $4.5bn from LNG exports in 2013, a $150m increase over 2012, but OLNG is under pressure to renegotiate terms of its contracts with long-term buyers, on the back of rising domestic demand that led the government to increase LNG prices for select industrial users in April 2012. Average prices for gas supplied to the Oman India Fertiliser Company in Sur were raised to $1.50 per mBTU, with incremental annual increases expected to bring the rate to $3 per mBTU by 2016.
Although the government is also moving to reduce gas demand in the power sector, aggregate consumption is expected to grow between 10% and 15% in 2014, according to Interfax Energy. If Oman is to meet its long-term export commitments, it may be forced to use gas produced at the Khazzan tight gas reserves, which carry a much higher production price tag, meaning the sultanate will be forced to renegotiate its contract rates, or risk subsidising its LNG customers. Unfortunately, none of Oman’s LNG contracts will be up for renewal in the near term, with most set to expire in 2024 or 2025, which could pose a significant challenge for negotiators attempting to retain valuable gas revenues.
Refining
In 2013 ORPIC processed 56m barrels of Oman’s export blend, or 17% of total production, while the remainder was exported. Mina Al Fahal recorded a an increase in crude processing, which reached 36.4m barrels, compared to 30.8m barrels in 2012, while Sohar’s production declined to 19.4m barrels from 27.7m barrels in 2012 due to a planned shutdown.
Oman’s downstream segment is in the midst of a strong expansionary period, as the sultanate moves forward on billions in new refinery upgrade and construction projects, and the development of new petrochemical facilities. There are two operating refineries: Mina Al Fahal, in Muscat, with annual refining capacity of 106,000 bpd, and the Sohar Refinery, which offers a capacity of 116,000 bpd, although Sohar’s expansion will see its refining capacity rise to nearly 200,000 bpd.
As part of its plans to boost downstream capacity and enhance the oil sector’s value chain, ORPIC announced in March 2014 that it has invested $7bn in new downstream projects, including the Liwa Plastics Project (see Industry chapter), the Sohar Refinery Improvement Project (SRIP) and the Muscat-Sohar Product Pipeline. Plans are also under way to construct a new 230,000-bpd refinery at the fast-growing Port of Duqm. The Sohar Refinery Improvement Project (SRIP) and Duqm Refinery and Petrochemicals Complex represent billions of dollars in new investments, and significant growth channels for a host of stakeholders, from industrial producers and construction contractors to residents in the refinery’s surrounding cities.
SRIP
Work on the SRIP has progressed steadily since November 2013, when a JV between South Korea’s Daelim Industrial Company and UK-based Petrofac, was awarded a $2.1bn EPC contract for the project. In September 2014, OPRIC announced construction work for the SRIP had commenced, with the project expected to add an additional 82,000 bpd of refining capacity when construction is completed. This will result in 70% expansion of existing fuel production, including diesel (90%), gasoline (37%), kerosene (93%), jet fuel (93%), LPG (91%), naphtha (175%) and propylene (44%).
The SRIP will see five new units join the refinery’s existing residue fluid catalytic cracker, enabling the facility to refine heavier crude oil and improving Omani crude utilisation levels. The refinery will be able to handle all primary initial quantities entering its units, allowing for high-quality output and production of high-value petrochemical projects. The project is also expected to improve efficiency and productivity, boosting integration with Sohar’s existing aromatics and polypropylene plants, reducing current import requirements, which reached 50,000 bpd of petroleum products between September 2013 and September 2014, according to GTIS tanker data compiled by the EIA.
Duqm Refinery
Billions in investment has been earmarked for construction and expansion at the Port of Duqm, including a $1.5bn dry dock that started soft operations in 2011. Duqm offers significant geographical advantages, located just outside the Strait of Hormuz, the sole passageway into the Gulf, through which 20% of all oil and 35% of oil traded by sea passes.
The Duqm Refinery and Petrochemicals Complex is one of the largest oil and gas projects under development in Oman, with a $6bn first phase expected to deliver a new merchant export refinery offering capacity of 230,000 bpd. The Duqm Refinery and Petrochemical Industries Company (DRPIC), a 50:50 JV between the OOC and Abu Dhabi’s International Petroleum Investment Company, is responsible for developing the Duqm refinery. The new refinery is expected to use delayed coking technology for “bottom of the barrel” processing, which will improve crude utilisation rates using hydrocracking, hydrotreating and LPG treatments, as well as kerosene treatment and sulphur recovery, according to DRPIC officials. A concurrent project at Ras Markaz near Duqm will also see construction of a mammoth crude storage terminal, offering capacity for 200m barrels, while the project’s second phase, which would include an associated petrochemical complex, could bring the total value of the project to $15bn.
Government entities have already signed on to provide support services for the refinery. OGC will lay a pipeline to supply natural gas for utilities from central Oman’s Saih Nihayda to the Duqm Special Economic Zone, which will host the refinery, while the Central Utilities Company, a JV between Takamul and Sembcorp Utilities, plans to develop and operate seawater intake facilities for the complex. The Duqm Petroleum Terminal Company, a partnership between OOC and the Port of Duqm Company, will invest to develop and operate a liquid jetty, which will handle ships carrying crude oil for processing, as well as refined petrochemical exports.
In June 2014 the DRPIC announced that it would launch a request for proposals for the project’s first phase in the third quarter of 2014, following which it would float a tender for the key EPC package during the second quarter of 2015. A contract award for site preparation works is expected during the first quarter of 2015, while the DRPIC expects to award the EPC contract by the second quarter of 2016, with the refinery expected to begin operations in 2018/19.
Muscat-Sohar Pipeline
The government has been working to expand the sultanate’s domestic pipeline infrastructure, including a line connecting Duqm’s planned storage terminal to existing export infrastructure in central Oman, as well as the Muscat-Sohar pipeline, which would connect Oman’s two current refineries and reduce tanker traffic between the cities’ export terminals. In January 2014, ORPIC and Spanish firm Compañía Logística de Hidrocarburos entered into a joint venture to construct and operate the 280-km Muscat-Sohar pipeline, connecting the Mina Al Fahal refinery to Sohar, as well as a new terminal in Jifnain, near Muscat, and to the Muscat International Airport.
Outlook
Oman’s geographic positioning and government efforts to build its hydrocarbon value chain have allowed it to develop one of the region’s most liberalised and innovative oil and gas sectors. New exploration and employment of EOR techniques has allowed the sultanate to maintain and enhance production, while downstream developments will see its petrochemicals industry flourish over the medium term. Declining global oil prices could pose a significant challenge to the oil and gas industry, although domestic demand and government efforts to build up downstream capacity should keep Oman on a steady growth path, despite the risk of a near-term fiscal deficit.
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