Thursday, November 1, 2012

Exxon seeks to quit Iraq’s West Qurna-1

ExxonMobil is poised to walk away from its technical services agreement for southern Iraq’s West Qurna-1 oilfield. Well-placed sources familiar with the US supermajor’s Iraq operations told Petroleum Economist that the US supermajor was preparing to focus its efforts on upstream projects in Kurdistan instead. 
A source said an exit could be announced as early as this month, although it is understood that the company’s departure from Iraq’s south could take six months to a year. 

“The decision has been taken. It has been communicated to the Iraqi oil ministry,” said the source. It is understood that ExxonMobil and Shell, its partner in the West Qurna-1 technical service agreement, had a meeting at the Ministry of Oil in Baghdad today. 

Irak oil fields

A second Baghdad-based source, close to the Iraqi government, said ExxonMobil, under pressure from the central government, had requested some time to find a buyer for its stake. The company hoped to make a profit on its share in West Qurna-1, he said. The US firm has opened negotiations with Asian and Russian firms. 

The move will end a dispute that has been rumbling since news surfaced last year that the supermajor, defying the central government’s rules, had agreed to develop six blocks in Kurdistan. The Iraqi central government considers Kurdistan’s production-sharing contracts, judged by investors to be more generous than the technical service contracts on offer in the south, to be illegitimate, and has banned companies operating in the region from participating in future upstream licensing rounds in Iraq. It previously threatened to strip ExxonMobil of its West Qurna-1 contract in response the supermajor’s decision to invest in Kurdistan. 

The Baghdad source said ExxonMobil may be walking from its West Qurna-1 contract before it is pushed. 
Pressure has been building on the central government to punish ExxonMobil for its investment in Kurdistan, he said. The government knows it could not win a court case if it stripped the US firm of its contract, he said, but could make operations intolerably difficult. 
“The government can give them a nightmare,” he said. ExxonMobil’s response was “OK we will leave but give us time.” nExxonMobil refused to comment when contacted by Petroleum Economist</EM>. The Iraqi oil ministry also refused any official comment. 
But ExxonMobil’s withdrawal, if confirmed, will throw renewed doubt on Iraq’s ability to maintain upstream momentum. It also suggests life is growing more difficult for Western international oil companies in the south. Earlier this week, the UK government closed down its Basra consulate. A UK government source told Petroleum Economist that the move was a cost-cutting exercise, saying maintaining three diplomats at a price of £6.5 million ($10.49 million) a year was too great. But sources in Baghdad said the move showed a retreat from the south, where BP and Shell, among other international oil companies (IOCs), have taken large stakes in the upstream.

Hussein Al-Shahristani, the country’s deputy prime minister with oversight of the energy sector, said earlier this week that output had reached 3.4 million barrels a day (b/d), setting another three-decade high. 
The International Energy Agency (IEA) has pinpointed Iraq’s four mega-projects – West Qurna is one of them – as critical to global production growth. Iraq will account for 45% of the rise in world output in the coming decades, the agency said. 

The West Qurna oilfield, which with reserves of 43 billion barrels is the world’s second largest field, will be developed in two phases. The first phase, West Qurna-1, is operated by an ExxonMobil-Shell joint venture that is contracted to deliver output of 2.25 million b/d. West Qurna-2 is under development by Lukoil, with a 75% stake, and the Iraqi government. It will eventually deliver 1.8 million b/d. 

In a briefing to diplomats and selected guests at the UK’s Foreign Office on 15 October, Fatih Birol, the IEA’s chief economist, reiterated that such production growth depended on “consensus” emerging between the Iraq central government and the Kurdistan Regional Government (KRG). A recent agreement between the two, allowing for the central government to pay companies operating in Kurdistan for oil exports, were “encouraging signs” that agreement was possible, Birol said. However, ExxonMobil’s withdrawal from southern Iraq may reignite the situation– raising questions about the central government’s willingness to compromise with the KRG and its ability to retain the blue-chip investors it needs to increase output significantly. The IEA predicts production will rise to more than 8 million b/d by 2035. By 2015, it will rise to 4.2 million b/d. 

Earlier this week, a report in Nefte Compass, a Russia-focused oil-industry newsletter, said that Iraq was considering replacing ExxonMobil at the West Qurna-1 oilfield with Russian firms. Lukoil is already operating the West Qurna-2 project. It was unavailable for comment on 15 October, although a spokesman previously said the company had not been asked to take ExxonMobil’s stake in West Qurna-1. 
Rosneft is also considered a potential buyer of ExxonMobil’s stake, according to sources. A deal in the works between BP and Rosneft could see the Russian firm buy all or part of TNK-BP, making it the world’s largest oil company. 

Rumours of greater Russian oil involvement in Iraq’s south, home to the country’s largest oilfields, followed a trip to Moscow earlier this month by Iraq’s prime minister, Nuri Al-Maliki. His trip sealed a $4.2 billion arms deal that will see Russia supply the country with attack helicopters and surface-to-air missile systems. Another agreement over the supply of MiG-29 is also in the works. GazpromNeft, another Russian company with a presence in Iraq, denied reports last week that it had frozen its assets in Kurdistan. 

ExxonMobil’s departure from Iraq’s south, if confirmed, may also reinforce perceptions that Kurdistan is a more prospective play for IOCs, said the Baghdad source. Its six blocks in the autonomous region would likely be just the base for further expansion through takeovers of smaller operators in Kurdistan, he said. 
The move will also have political ramifications, amid persistent divisions between independence-minded Kurds and the Iraqi central government. 

A diplomatic source said ExxonMobil had sought to coordinate its departure from Iraq’s south with the US State Department. Last year, the company’s move into Kurdistan happened without such political due diligence, the source said. The US’ stance remains that it backs a united, federal Iraq. 

Wednesday, October 10, 2012

East China Sea Energy Report

Although the East China Sea may have abundant oil and natural gas resources, unresolved territorial disputes continue to hinder exploration and development in the area.

The East China Sea is a semi-closed sea bordered by the Yellow Sea to the north, the South China Sea and Taiwan to the South, Japan's Ryukyu and Kyushu islands to the East and the Chinese mainland to the West. Evidence pointing to potentially abundant oil and natural gas deposits has made the sea a source of contention between Japan and China, the two largest energy consumers in Asia.

The sea has a total area of approximately 482,000 square miles, consisting mostly of the continental shelf and the Xihu/Okinawa (Chinese name/Japanese name) trough, a back-arc basin formed about 300 miles southeast of Shanghai between the two countries. The disputed eight Daioyu/Senkaku (Chinese/Japanese name) islands lie to the northeast of Taiwan, with the largest of them two miles long and less than a mile wide. Though barren, the islands are important for strategic and political reasons, as ownership can be used to bolster claims to the surrounding sea and its resources under the United Nations Convention on the Law of the Sea. To date, China and Japan have not resolved their ownership dispute, preventing wide-scale exploration and development of East China Sea hydrocarbons.

East China sea map

Oil & Natural Gas

The East China Sea basin, particularly the Xihu/Okinawa Trough, is a potentially rich source of natural gas that could help meet Chinese and Japanese domestic demand.

China recently became the second largest net oil importer in the world behind the United States and the world's largest global energy consumer. Gas imports have also risen in recent years, and China became a net natural gas importer for the first time in almost two decades in 2007. EIA forecasts that China's oil and natural gas consumption will continue to grow in coming years, putting additional pressure on the Chinese government to seek out new supplies to meet domestic demand (See China country analysis brief). Japan is the third largest net importer of crude oil behind the United States and China, as well as the world's largest importer of liquefied natural gas (LNG), owing to few domestic energy resources. Although EIA projects oil consumption in Japan to decline in coming years, Japan will continue to rely heavily on imports to meet consumption needs (See Japan country analysis brief). Therefore, both China and Japan are interested in extracting hydrocarbon resources from the East China Sea to help meet domestic demand.


Hydrocarbon reserves in the East China Sea are difficult to determine. The area is underexplored and the territorial disputes surrounding ownership of potentially rich oil and natural gas deposits have precluded further development. The EIA estimates that the East China Sea has between 60 and 100 million barrels of oil (mmbbl) in proven and probable reserves. Chinese sources claim that undiscovered resources can run as high as 70 to 160 billion barrels of oil for the entire East China Sea, mostly in the Xihu/Okinawa trough. However, "undiscovered resources" do not take into account economic factors relevant to bring them into production, unlike "proven and probable reserves."

China began exploration activities in the Each China Sea in the 1980's, discovering the Pinghu oil and gas field in 1983. Japan co-financed two oil and gas pipelines running from the Pinghu field to Shanghai and the Ningbo onshore terminal on the Chinese mainland through the Asian Development Bank and its own Japanese Bank of International Cooperation (JBIC).

More recently, both China and Japan have concentrated their oil and gas extraction efforts in the contested Xihu/Okinawa trough. Most fields are operated as a joint venture between the Chinese National Offshore Oil Corporation (CNOOC) and the China Petroleum & Chemical Corporation (Sinopec) with support from foreign firms and other partners, such as the Shanghai government. CNOOC listed its East China Sea proved oil reserves at 18 million barrels in 2011, according to an annual report, while other partners have not publicly released their reserve figures.

Only the Pinghu field, operational since 1998, has produced oil in significant quantities to date. Pinghu's production peaked at around 8,000 to 10,000 barrels per day (bbl/d) of oil and condensate in the late 1990's, and leveled off to around 400 bbl/d in recent years. In the medium-term, the East China Sea is not expected to become a significant supplier of oil.

Natural gas

EIA estimates that the East China Sea has between 1 and 2 trillion cubic feet (Tcf) in proven and probable natural gas reserves. The region may also have significant upside potential in terms of natural gas. Chinese sources point to as much as 250 Tcf in undiscovered gas resources, mostly in the Xihu/Okinawa trough.

CNOOC listed its East China Sea proved gas reserves at 300 billion cubic feet (Bcf) in 2011, according to an annual report. In 2012, an independent evaluation estimated probable reserves of 119 Bcf of natural gas in LS 36-1, a promising gas field north of Taiwan currently being developed as a joint venture between CNOOC and U.K. firm Primeline Petroleum Corp.

The uncontested Pinghu field began producing in 1998, reaching a peak of approximately 40 to 60 million cubic feet per day (Mmcf/d) in the mid-2000's and declining in recent years. Chinese companies discovered a large oil and gas field group in 1995 in the Xihu/Okinawa trough. Chunxiao/Shirabaka is the largest gas field in this group and is used on occasion to reference all fields in the area. China began producing at the contested Tianwaitian/Kashi field in 2006, claiming it as part of its Exclusive Economic Zone. According to industry sources, Tianwaitian/Kashi produced between 10 and 18 Mmcf/d in the past several years. China has not released production data from the Chunxiao/Shirabaka field, citing concerns about the regional dispute.

The Chinese government prioritizes boosting the share of natural gas as part of total energy consumption to alleviate high pollution from the country's heavy coal use. To that end, Chinese authorities intend to ramp up production and increase East China Sea gas to flow into the Yangtze River delta region, which includes Shanghai and Hangzhou, two large cities with growing gas demand. According to an industry source, gas from the East China Sea supplied approximately 12 percent of Zhejiang Province natural gas needs in the first half of 2012, though natural gas remains a small part of the region's total energy mix.

natural gas undiscovered recoverable resources 2012

Foreign ventures

Foreign energy companies have had mixed success in the East China Sea. In the 1990's, several foreign companies drilled a series of dry holes in uncontested waters. In 2003, Unocal and Royal Dutch Shell announced a joint venture (JV) with CNOOC and Sinopec to explore gas reserves in the Xihu/Okinawa trough. However, Unocal and Shell withdrew from exploration projects in late 2004, citing doubts over the commercial viability of developing energy resources in the disputed area.

Husky Oil China, a subsidiary of Canadian Husky Energy, holds an exploration block in East China Sea but has had more success in the South China Sea. Primeline Petroleum Corp. and CNOOC started joint development in the promising LS 36-1 gas field near Taiwan, with Primeline's subsidiaries assuming all exploration costs. The companies plan to build pipelines and a 42 Mmcf/d onshore processing terminal at Wenzhou to accept the future gas supplies from the LS 36-1 field.

In August 2012, CNOOC opened up three new offshore blocks for joint-development with foreign companies in the East China Sea but has not awarded any contracts to date.

East China Sea discoveries structures

Territorial issues

China and Japan have two separate, but interlinked disputes: where to demarcate the sea boundary between each country and how to assign sovereignty over the Daioyu/Senkaku Islands.
Despite multiple rounds of high-level negotiations between China and Japan, the two countries have thus far been unable to resolve territorial issues related to the East China Sea. Taiwan's claim parallels China's with regard to the islands, although Taiwan has not actively pursued resources in the region. Until these disputes are resolved, it is likely that the East China Sea will remain underexplored and its energy resources will not be fully developed.

Daioyu/Senkaku Islands

The Daioyu/Senkaku Islands consist of five uninhabited islets and three barren rocks. Approximately 120 nautical miles southwest of Okinawa, the islands are situated on a continental shelf with the Xihu/Okinawa trough to the south separating them from the nearby Ryukyu Islands.

Japan assumed control of Taiwan and the Daioyu/Senkaku islands after the Sino-Japanese War in 1895. Upon Japan's defeat in World War II, Japan returned Taiwan to China, but made no specific mention of the disputed islands in any subsequent document.

For several decades after 1945, the United States administered the islands as part of the post-war occupation of Okinawa. The islands generated little attention during this time, though U.S. oil companies conducted minimal exploration in the area. In 1969, a report by the UN Committee for Coordination of Joint Prospecting for Mineral Resources in Asian Offshore Areas (CCOP) indicated possible large hydrocarbon deposits in the waters around the Daioyu/Senkaku islands, reigniting interest in the area. Although China had not previously disputed Japanese claims, the PRC claimed the islands in May 1970 after Japan and Taiwan held talks on joint exploration of energy resources in the East China Sea. When the United States and Japan signed the Okinawa Reversion Treaty returning the disputed islands to Japanese control as part of the Okinawa islands, both the PRC and Taiwan challenged the treaty.

China claims the disputed land based on historic use of the islands as navigational aids. In addition, the government links the territory to the 1895 Shimonoseki Peace Treaty that removed Japanese claims to Taiwan and Chinese lands after World War II.

Japan claims that it incorporated the islands as vacant territory (terra nullius) in 1895 and points to continuous administration of the islands since that time as part of the Nansei Shoto island group. According to the Japanese, this makes ownership of the islands a separate issue from Taiwan and the Shimonoseki treaty. Japan cites the lack of Chinese demands on the area prior to 1970 as further validation for its claim.

Daioyu Senkaku Islands dispute map

Disputed maritime boundary in East China Sea

China and Japan apply two different approaches to demarcating the sea boundary in the East China Sea, both based on the UN Convention on the Law of the Sea (UNCLOS). Japan defines its boundary as the UNCLOS Exclusive Economic Zone (EEZ) extending westward from its southern Kyushyu island and Ryukyu islands. China defines its boundary using the UNCLOS principle of the natural extension of its continental shelf. The overlapping claims amount to nearly 81,000 square miles, an area slightly less than the state of Kansas. Japan has proposed a median line (a line drawn equidistant between both countries uncontested EEZs) as a means to resolve the issue, but China rejected that proposal.

Under UNCLOS, Article 121 (3), "Rocks which cannot sustain human habitation or economic life of their own shall have no exclusive economic zone or continental shelf". The Japanese have claimed that the disputed islands generate an EEZ and continental shelf. China has not taken an official position on the status of the Daioyu/Senkakus as rocks or islands.
Mediation efforts

China and Japan began holding bilateral talks over the East China Sea issues in October 2004, although Taiwan did not participate. Japan has repeatedly requested seismic data from China on Xihu/Okinawa trough fields and asked China to desist production until both sides reached an agreement. China has consistently rejected this claim, insisting that the trough and its associated fields are within its territorial sovereignty.

The two sides have considered joint development of the resources as a means of moving forward with energy exploration but have not yet agreed on what territory such a contract would cover. China has offered joint development of the gas fields north of the disputed islands, sidestepping the sovereignty issue. Japan offered joint development of the Chunxiao/Shirakaba gas field, sidestepping the sea boundary dispute. To date, neither side has accepted the other's offer.

In 2008, China and Japan agreed to explore jointly four gas fields in the East China Sea and halt development in other contested parts of the regions. Both sides agreed to conduct joint surveys, with equal investment in an area north of the Chunxiao/Shirakaba gas field and south of the Longjing/Asunaro gas field. However, China began to develop the Tianwaitian/Kashi gas field unilaterally, launching a protest from Japan in January 2009. In early 2010, Japan threatened to take China to the International Tribunal for the Law of the Sea if China began producing from the Chunxiao/Shirakaba gas field.

The Japanese government began to lease the islands from their private Japanese owners in 2002, sparking protest from China. In April 2012, Tokyo's governor proposed a plan to buy three of the five uninhabited islets from the owners, to the chagrin of the Chinese. The Japanese government officially announced a deal to purchase the islands in September 2012, prompting a wave of protests throughout China and further escalating tensions in the sea.
Other regional actors

The PRC and Taiwan have strengthened their energy relationship in the East China Sea through a joint venture (JV) between Taiwan's CPC and China's CNOOC. In September 2009, the JV drilled a second well in what was previously a contested area between China and Taiwan. Both sides have been contributing to exploration and production activities in the Taiwan Strait, although no major fields have been discovered in the Tainan Basin.

South Korea has signed a provisional agreement with Japan outlining the Korean/Japanese border but has not reached a similar agreement with China. South Korea makes no claims on the disputed area of the East China Sea.

In early September 2012, U.S. Secretary of State Hillary Clinton visited China to meet with Chinese leaders on the issues of disputed territory in the East and South China Seas. The United States has not taken an official position on the issue and has urged both sides to reach a peaceful settlement.

Thursday, October 4, 2012

Oil millionaires of North Dakota

Take Robert Western, a farmer who was dressed in rumpled overalls and a baseball cap as he sipped coffee and discussed the oil boom that has transformed this once sleepy town.

"Some of the younger people buy a lot more - machinery, vehicles, things like that," said the 75-year-old Western. "The rest of us, I guess it doesn't alter our lifestyle a great deal. I don't have a lot of needs."

After he left, his friend Earl Rogstad remarked to a visitor: "It's too bad Robert didn't have his airplane ready... He offered last summer to fly me over and see (the oil wells) from the air."

Western did not mention that he is co-owner of a Piper single engine propeller plane, according to FAA records. He did admit to receiving oil royalties from wells on his farm but locals said he is far from the richest man in town. It is not clear whether Western is a millionaire or merely wealthy.

"You can't tell the average Joe farmer from the average Joe millionaire," said Ward Heidbreder, Stanley city coordinator.

Average income in Mountrail County, the hub of the North Dakota oil production boom, roughly doubled in five years to $52,027 per person in 2010, ranking it in the richest 100 U.S. counties on that basis including New York City, and Marin, California.

The boom could be creating up to 2,000 millionaires a year in North Dakota, said Bruce Gjovig, founder of the Center for Innovation at the University of North Dakota.

Many oil region residents receive $50,000 or $60,000 a month in oil royalties and some more than $100,000, said David Unkenholz, a senior trust officer at First International Bank & Trust in Watford City, the seat of McKenzie County, which is the No. 2 oil producing county in the state behind Mountrail.

The oil is so plentiful that in Stanley, where the population has about doubled to 3,200 in the last five years, a well drilled under the town means that many homeowners could receive a small oil royalty check.

A lot of North Dakota's new wealthy simply stash the cash in savings and checking accounts with "ridiculously large" balances, banker Unkenholz said.

The monster homes, ostentatious diamond rings or luxury sports cars of California and New York are virtually nonexistent in North Dakota. Looking for wealth here is a subtle exercise.

Locals point to pickup trucks. The boom has boosted truck sales decked out with extras at Stanley's Ford dealer, Prairie Motors Inc, co-owner Gary Evans said.

"They are a lot more elaborate, a lot more loaded up than what they used to be, even the accessories," Evans said. "There is a big demand for accessorizing a pickup truck - everything from running boards to grill guards to chrome wheels."

Evans, 66, a part owner of the dealership since 1970 and manager of the services business, said most residents have not changed their buying habits, especially those over 50.

"Some of these people you could look at and you don't even know if they have an oil well or not, and they may have several," said Evans, who grew up on a family farm west of Stanley and also has some mineral acres.


One reason rich locals do not brag about their money is because some residents do not own precious mineral rights to the land and have missed out on the boom. Land and mineral rights can be separated and sold in North Dakota and often are.

Royalties are paid based on oil produced and sold mainly in sections of land of one or two square miles in size. The owner of the mineral rights receives the royalties. It can be a complex exercise to divide rights among multiple land heirs.

In simple terms, a well producing 100 barrels of oil per day sold at $80 a barrel would generate $248,000 in a 31-day month. The state collects taxes on extraction and production of about 11.5 percent. From there, if the rights holders have one-fifth royalties, they would receive $43,896 a month.

In July, North Dakota wells produced an average of 92 barrels per day but some produced more than 10,000 barrels in a month, a windfall for the royalty owners.

Some of that money has gone to area churches in the form of anonymous donations and some to the schools for technology, said Heidbreder, the city coordinator.

It's not just land owners who are benefiting from the boom. Oil has also brought high-paying jobs, and some of that money filters through to local businesses.

So-called man camps have sprung up in North Dakota, where oil workers live in makeshift dormitories.

At a man camp in Williston run by workforce housing provider Target Logistics, the 26 kitchen staff, all from outside the state, work 84 hours a week for six straight weeks, then take two weeks off, executive chef Jason Freeman said.

Target Logistics has several man camps in western North Dakota, including a hotel and cabins at Stanley, mainly for energy employees. Its camp in Williston, the largest area town, looks like a military base with room for about 800 workers, a huge cafeteria, weight room, lounge and other facilities.

"This is a thriving economy. This doesn't exist anywhere else," said Freeman, who lives in central Minnesota.

There are downsides to the oil rush. Crime reports are up in Stanley, even if not as much as the population. Aggravated assault reports rose 55 percent last year in the oil producing counties, according to state figures.

Gayleen Grote, who lives on a family farm north of Tioga in the oil patch, said she has a permit to carry a concealed weapon and sometimes puts a semiautomatic pistol in a bra holster.

"There is a lot of testosterone," said Grote, adding that though she has never had to get aggressive, male drivers have stopped several times while she was walking by herself on area roads. "There is nothing to do but drink," she said.

Tuesday, September 25, 2012

Why Gas prices so high?

Driving gasoline is 50% higher today than in 2008 – relative to the price of oil.In other words, gas prices are nearly what they were in 2008... but at that point oil was priced at $147 a barrel.Today the oil price is $50 less than that.That's why driving gasoline is 50% higher. And drivers in North America are now competing for cheap American crude – with gasoline drivers everywhere.

In the first chart you'll notice there is a low amount of middle distillates globally—these are the refined oil products that are used to power and transport the world: diesel, jet fuel, home heating oil, etc.

global middle distillates inventories

This means demand is low, or supply is low – one or the other.

Look at the chart below, and it can been that supply is high and rising—so I conclude demand must be higher. I have to think that is a bullish sign. US refineries are dramatically increasing their exports of light/middle distillates from the Gulf refinery complex out into the rest of the world. And yet global distillate levels are still low. That intimates a bullish world demand case to me, and tells me we won’t see a dramatic drop in the price of oil.

export of light products from the Gulf

Refineries export into a global market for their refined products, which are all priced on Brent Crude, while their input costs—North American crude oil—is priced on cheaper WTI, or West Texas Intermediate.That $15/barrel price difference between the Brent and WTI is pure profit for refineries. The WTI price is so much cheaper because of the HUGE supply of new oil created by the U.S. in the fast-growing Shale Revolution.It allows refineries to choose whatever global product has the best price for export—and that’s not always driving gasoline for North Americans.

Several North American refineries are trying their best to move their processing over to other products besides driving gasoline.But even with lots of gasoline, domestic drivers are now up against everyone else around the world for cheap North American crude products. And that should keep retail gasoline prices high.

Friday, September 21, 2012

Iran’s oil production fell to 2.5 million b/d

Western-led sanctions against Iran’s oil exports aiming to push Tehran to return to negotiations on uranium enrichment have displaced from the market more than 1 million b/d of crude oil, distorting market fundamentals and affecting prices, according to the Centre for Global Economic Studies (CGES), London.

While additions to oil output by Saudi Arabia, Iraq, the US, and Canada have helped to mitigate the Iranian oil shortfall, regional refining centers—especially the Mediterranean—have been affected. And some Asian buyers have been forced to reduce their imports of Iranian crude to avoid US penalties.

As a result, CGES reports, Iran’s oil production fell to little more than 2.5 million b/d in July and August from 3.5 million b/d at the start of 2012.

iran oil production 

The country’s exports have declined due to the ceasing of imports by European Union customers and lower liftings by China, India, South Korea, Japan, and other traditional customers of Iranian medium sour crude. Some estimates put crude oil exports from Iran below the 1 million b/d threshold in August, the lowest level since at least the end of the Iran-Iraq war 24 years ago, according to CGES.

A drop of this magnitude would turn the Islamic Republic from the second largest exporter in the Organization of Petroleum Exporting Countries to one of its smallest, ahead of only Algeria, Qatar, and Ecuador, the consultancy reported while positing that the drop could be temporary, caused by the difficulties arranging insurance for tanker deliveries from Iran.

“South Korea has said it will officially ‘resume’ oil purchases in September, while Turkey may lift oil directly from Iran in the near future. Japan, too, may resume purchases of Iranian oil after taking no deliveries in either July or August. According to the CGES’s latest assessment, Iranian oil production inched up in August, driven by a slight rebound in exports. Japan and India have implemented state-backed insurance programs to cover cargoes of Iranian oil, while Tehran itself has started providing insurance cover for oil tankers entering its waters,” the report said.

CGES said the EU embargo on Iranian crude oil imports has caused a shortfall of medium sour crude in the Mediterranean market, leaving refiners to scramble for other supplies. Meanwhile, some refiners in the region claim that the sanctions have depressed refining margins by driving up the price.

Thursday, September 20, 2012

Crude oil discovery in Ghana’s Offshore block

Eni SpA (ENI), Italy’s largest oil company, made the first crude discovery in Ghana’s Offshore Cape Three Points block, opening the prospect of increased production in the West African country.

The company found oil 50 kilometers (31 miles) off Ghana at a well drilled to a depth of 3,650 meters (12,000 feet). The Sankofa East-1X well produced about 5,000 barrels of oil per day, Eni said in a statement today.

“Eni plans for the immediate drilling of other wells to delineate the size of the discovery and confirm the feasibility of commercial development,” said the Rome-based company, which has operated in Ghana since 2009.

Eni is also working on its plans to commercialize the block’s gas reserves on the domestic gas market, in accordance with the shareholders’ agreement with Ghana’s ministry of energy.

After the December 2010 start of oil production for export at the Jubilee field, operated by Tullow Oil Plc (TLW), Ghana’s economy grew 14.4 percent in 2011, the fastest pace in Africa, according to the International Monetary Fund. Growth is forecast at 9.4 percent this year according to the Finance Ministry.

Ghana Offshore Blocks

The country’s revenue from oil climbed 43 percent to $326.6 million in the first half of the year, with output averaging 62,985 barrels a day, according to a Bank of Ghana report from August. Output is expected to rise “in excess of” 90,000 barrels by the end of the year.

The OCTP block is operated by Eni, with a 47 percent stake in the project, Vitol Upstream Ghana Ltd., which has 38 percent, and state company GNPC, which has 15 percent.

Norway Energy Report

Norway is Europe's largest oil producer, the world's second largest natural gas exporter, and is an important supplier of both oil and natural gas to other European countries.

Norway, the largest holder of natural gas and oil reserves in Europe, provides much of the oil and gas consumed on the continent. In fact, Norway was the second largest exporter of natural gas in the world after Russia, and the seventh largest exporter of oil.

In 2010, crude oil, natural gas, and pipeline transport services accounted for almost 50 percent of Norway's exports revenues, 21 percent of GDP, and 26 percent of government revenues according to the Norwegian Petroleum Directorate (NPD). Although Norway's oil production peaked in 2001 at 3.4 million barrels per day (bbl/d) and declined to 2.0 million bbl/d in 2011, natural gas production has been steadily increasing since 1993, reaching 3.6 trillion cubic feet (Tcf) in 2011.

Hydropower is the principal source of Norway's electricity supply at 95 percent, while only 4 percent comes from conventional thermal sources, followed by 1 percent from other renewables, namely biomass and waste and wind. In June 2012, government officials from Norway, Germany, and the United Kingdom (UK) confirmed their plans for subsea electric power interconnects between their countries. The Norway-UK cable connection is slated for completion in 2020 while the Norway-Germany cable is to be completed in 2018; their purpose is to strengthen the northern European electricity grid and increase supply security.

The historic agreement between Norway and Russia, which defined their maritime boundaries in the Barents and Arctic Seas and resolved their 40-year old dispute, was fully ratified by both governments in early 2011 and went into effect in July 2011. As a result of the agreement, Norway gained an additional 54,000 square miles of continental shelf, according to the NPD. The agreement requires the two countries to develop jointly oil and gas deposits which cross over their boundaries, a 109,360 square mile maritime area which straddles their economic zones in the Barents and Arctic Seas.

Norway map


Norway is the largest oil producer and exporter in Western Europe.

According to The Oil and Gas Journal (OGJ), Norway had 5.32 billion barrels of proven oil reserves as of January 1, 2012, the largest oil reserves in Western Europe. All of Norway's oil reserves are located offshore on the Norwegian Continental Shelf (NCS), which is divided into three sections: the North Sea, the Norwegian Sea and the Barents Sea. The bulk of Norway's oil production occurs in the North Sea, with smaller amounts in the Norwegian Sea and new exploration and production activity occurring in the Barents Sea.

In June 2012, Norway's oil and gas production faced being completely shut-in when an offshore workers strike began over employers' plans to increase the retirement age from 62 to 67. Government intervention stopped the strike, during which cutbacks to the country's production affected 15 percent of oil and 7 percent of gas production, according to Statoil.

top oil exporters 2011

Sector organization

Norway's Ministry of Petroleum and Energy (MPE) is responsible for overseeing the country's petroleum resources. The Norwegian Petroleum Directorate (NPD) works under MPE as manager and advisor. Statoil ASA was created by the merger of Statoil and Norsk Hydro in October 2007. It is an international energy company that is 67-percent-owned by the Norwegian government and is the largest operator in Norway, controlling 80 percent of Norway's oil and gas production. It also has interests in more than 30 other countries. State-owned Petoro manages the commercial aspects of the government's financial interests in petroleum operations and associated activities. It acts as the licensee for production licenses and companies.

International oil majors have a sizable presence in Norway. The Norwegian government's subsidy of oil and gas exploration, introduced in 2005, refunds 78 percent of the exploration costs to the companies. In addition, taxes from onshore oil activities and from liquefied natural gas (LNG) shipped overseas were reduced, which has attracted additional international investment. The Norwegian government is focused on increasing recovery in producing fields, further exploring producing areas, opening new areas to exploration, as well as developing new subsea technology, in which Norway is a global leader.
Exploration and production

In 2011, Norway produced 2.0 million bbl/d of petroleum and other fuels, of which about 87 percent was crude oil. Norway's petroleum production has been gradually declining since 2001 as oil fields have matured. The NPD expects that production will continue to decline slowly over the next few years, and that in the longer term the number and size of new discoveries will be a critical factor in maintaining production levels. Currently, seventy fields are in production on the NCS. The three largest producing oil fields are Ekofisk, which produced 162,000 bbl/d in 2010; Grane, which produced 166,000 bbl/d; and Troll, which produced 118,000 bbl/d.

Investment of US$29 billion in oil and gas activity is planned for 2012. Norway's national statistics bureau reported investments of US$21 billion in 2011, when 45 exploration wells were drilled and 16 discoveries were made.

Four new fields began production in the first six months of 2012: BG-Norge's Gaupe oil and gas field, Total's Islay gas field, Eni's Marulk gas and condensate field, and Dong's Oselvar oil and gas field. These four fields are each averaging daily production of 15,000 to 20,000 barrels of oil equivalent.

Goliat is the first oil field to be developed in the Barents Sea. Discovered in 2000, it is about 40 miles offshore the town of Hammerfest, which will be its land base. Goliat's reserves are estimated at 240 million barrels in two separate reservoirs, both with an overlying natural gas cap, and low pressures in the reservoirs require that the gas be reinjected. In May 2009, the Norwegian government approved the plan for development and operation of the Goliat oil field by licensees Eni (65 percent) and Statoil (35 percent), and construction is currently in full swing. The field is expected to reach peak production of about 100,000 bbl/d in November 2013, and 45.9 billion cubic feet (Bcf) of natural gas is expected to be produced and reinjected annually starting in 2014.

The Norwegian Parliament approved joint development and operating plans in June 2012 for Lundin's Edvard Grieg (formerly called Luno) oil and gas field and Det Norske's Draupne field. Estimated to hold 186 million barrels of oil equivalent, Edvard Grieg is scheduled to come onstream by late 2015 at 100,000 bbl/d of oil and 53 million cubic feet of gas (MMcf). The nearby Draupne field will be tied into Edvard Grieg, producing 52,000 bbl/d by October 2016, rising to 75,000 bbl/d the following year. Draupne's reserves are estimated at 143 million barrels of recoverable oil.

The Johan Sverdrup oil field was the largest oil discovery in the world in 2011, with reserves estimated at between 1.7 and 3.3 billion barrels of recoverable oil. It is located 140 km west of Stavanger in the North Sea. Johan Sverdrup was initially believed to consist of two fields four miles apart: Avaldnes, discovered by Lundin in 2010, and Aldous, discovered by Statoil in 2011. Further exploration activities revealed they constitute one giant field, renamed Johan Sverdrup in 2012, when a cooperation agreement was signed between the field partners naming Statoil operator. Partners also include Maersk, Petoro, and Det Norske. The field is expected to be a new stand-alone processing and transport hub, producing 120,000-200,000 bbl/d beginning in 2018, and accounting for half of Norway's oil production by 2040.

In April 2011, it was reported that Statoil and its partners Eni Norge and Petoro struck oil and gas at the Skrugard prospect in the Barents Sea, and it is one of Norway's biggest discoveries in ten years. In January 2012, Havis field was discovered in the same license block. Skrugard and Havis together are believed to hold as much as 500 million barrels of recoverable reserves. Statoil announced that it hopes to begin Skrugard production in 5 to 10 years. Skrugard is located 120 miles from the coast and well north of the Goliat and Snovit fields. Statoil plans to make it a production hub for other potential discoveries in the area as more exploration wells are planned to be drilled through mid-2013.

Exploration interest in the NCS remains strong on the part of major international oil companies. The most recent licensing round was announced in June 2012 and will include 86 blocks - 72 in the Barents Sea and 14 in the Norwegian Sea. The application deadline is December 4, 2012 and new production licenses are to be awarded before summer 2013. Several of the blocks in the Barents Sea are in immediate proximity to the Russian border and both Rosneft and Lukoil are expected to take part in the licensing round in accordance with the terms of the Norway-Russia Delimitation Agreement.

Norway Oil production and Consumption

Oil exports

According to the International Energy Agency (IEA), Norway exported an estimated 1.45 million bbl/d of crude oil in 2011, of which 90 percent went to OECD European countries. The top five importers of Norwegian oil (crude plus products) in 2011 were the United Kingdom (52 percent), the Netherlands (18 percent), the United States (10 percent), France (8 percent), and Germany (5 percent).

Norway has an extensive network of subsea oil pipelines, including 8 major domestic oil pipelines with a total capacity of more than 2.2 million barrels per day which connect offshore oilfields with onshore processing terminals. There are numerous smaller pipelines that connect North Sea fields to either the Oseberg Transport System or the Troll I and II pipeline systems, with the remaining offshore production brought ashore via shuttle tanker.
International oil pipeline

ConocoPhillips operates the 900,000-bbl/d-capacity subsea Norpipe, which connects Norwegian oil fields in the Ekofisk system, as well as associated fields in both Norwegian and UK waters, to the oil terminal and refinery at Teesside, England. The pipeline is a 50-50 joint venture between ConocoPhillips and Statoil.

According to OGJ, Norway had 319,000 bbl/d of crude oil refining capacity in January 2012. The country has two major refining facilities: the 116,000-bbl/d Slagen plant, operated by ExxonMobil, and the 203,000-bbl/d Mongstad plant, operated by Statoil. Norway is an important supplier of gasoline and diesel fuel to the European Union, as the production of these fuels at the Mongstad plant complies with stringent EU environmental rules. Statoil dominates the retail products market in Norway and the company has also expanded aggressively into other European markets. The port of Mongstad is the largest in Norway measured by tonnage, and second only to Rotterdam for shipping crude oil and refined products in Europe.
Natural gas

Norway is the second largest exporter of natural gas after Russia, and ranks fourth in world natural gas production.

According to OGJ, Norway had 71 trillion cubic feet (Tcf) of proven natural gas reserves as of January 2012. Despite the maturation of its major natural gas fields in the North Sea, Norway has been able to sustain annual increases in total natural gas production by continuing to develop new fields.
Sector organization

As is the case with the oil sector, Statoil dominates natural gas production in Norway. A number of international oil and gas companies, including ExxonMobil, ConocoPhillips, Total, Shell, and Eni have a sizable presence in the natural gas and oil sectors in partnership with Statoil. State-owned Gassco is responsible for administering the natural gas pipeline network. The company also manages Gassled, the network of international pipelines and receiving terminals that exports Norway's natural gas production to the United Kingdom and continental Europe.
Production and development

Norway produced 3.64 Tcf of dry natural gas in 2011, down slightly from the 3.76 Tcf produced in 2010. The dip in production level was assessed by NPD to have been largely market-driven. Production has been generally increasing since 1993 and NPD forecasts it will reach 3.96 Tcf in 2015. Total gross natural gas production was 5.25 Tcf in 2011, of which 1.38 Tcf (26 percent) was reinjected to enhance oil production.

Norway's single largest natural gas field is Troll, which produced 0.9 Tcf in 2010, according to NPD, representing about one-quarter of Norway's total natural gas production. The three other largest producing fields in 2010 were Ormen Lange (0.7 Tcf), Asgard (0.4 Tcf), and Sleipner Ost (0.3 Tcf). These 4 fields accounted for about 60 percent of Norway's total natural gas production.

The Gjoa oil and gas field, developed by Statoil and GDF Suez, began production in January 2011. Located in the North Sea, Gjoa daily production is expected to peak at 600 million cubic feet of gas and 87,000 barrels of oil. The gas is transported directly via pipeline to St. Fergus, Scotland, while the oil is transported to the Mongstad refinery through the Troll II pipeline. For the first time in the offshore oil and gas industry, the floating platform is fully powered by electricity from the mainland. The Gjoa platform opens a new area in the North Sea for production, and its infrastructure will be a hub for future developments.

Statoil is a partner with Total in Gazprom's development of the Shtokman natural gas and condensate field in the Barents Sea, 342 miles offshore Russia. Reserves have been estimated at nearly 140 trillion cubic feet and Phase 1 of field development is projected to provide annual production of 837 Bcf/year. However, the project has been repeatedly delayed due largely to the immense technical and cost challenges. Reportedly, under current consideration is a switch to all liquefied natural gas (LNG) production to improve its economic feasibility, as well as a change of partners. A new agreement is now expected in autumn 2012 following the expiration of the original partners' agreement in June.

Norway Natural Gas production and Consumption


Norway exported an estimated 3.5 Tcf of natural gas in 2011, 96 percent of its production, according to NPD. Most of it was transported to Europe via its extensive export pipeline infrastructure and a smaller amount (4.3 percent) via LNG tanker. The country is the second-largest supplier of natural gas to the European Union, behind Russia, supplying about 18 percent of Europe's total gas demand in 2010. The largest outlets for Norway's natural gas pipeline exports in 2010 were Germany, the United Kingdom, France, the Netherlands, and Belgium.
International gas pipelines

Norway operates several important natural gas pipelines which connect directly with other European countries, specifically France, the United Kingdom, Belgium, and Germany. Franpipe, with a capacity of 692 billion cubic feet per year (Bcf/y), exports gas to Dunkirk, France. Zeepipe I, IIA, and IIB have a total capacity of 2,384 Bcf/y and transport gas to Zeebrugge, Belgium. Europipe I and II, with a total capacity of 1,423 Bcf/y, export to Dornum, Germany, while Norpipe, with a total capacity of 572 Bcf/y, runs to Emden, Germany. Vesterled, capacity 463 Bcf/y, links to St. Fergus, Scotland, while Langeled, capacity 893 Bcf/y, links to Easington on the east coast of England. These pipelines are all operated by Gassco. Some pipelines run directly from Norway's major North Sea production facilities to Gassco-owned processing facilities in the receiving country, while other pipelines connect Norway's onshore processing facilities to other European markets.

Norway pipeline exports

Liquefied natural gas (LNG)

According to NPD estimates, 2011 shipments of Norwegian LNG totaled an estimated 150 Bcf, up from 138 Bcf in 2010. OECD European countries in 2010 received about 74 percent of the total, with Spain importing almost half of that. The United States imported about 5 percent or 26.8 Bcf. Norway has long-term contracts with Spain's Iberderola and the U.S.'s El Paso.

Norway became an LNG exporter in 2007 with the beginning of commercial production from the Snohvit gas field, Norway's first natural gas development in the Barents Sea. Statoil operates an LNG export terminal and liquefaction facility at Melkoya, near Hammerfest. The Melkoya facility, the first large-scale LNG export terminal in Europe, has a capacity of about 200 Bcf/y and is connected by pipeline with the Snohvit gas field. The Snohvit field produced 0.2 Tcf in 2010. The Melkoya facility is producing at full capacity and Statoil is currently studying the expansion possibilities of adding a second train. Field development plans may be decided by the end of 2013, and additional LNG production could begin in 2018. The project's expansion would likely be fed by the nearby Askeladd field, which is due onstream in 2014 or 2015, and other new projects in the area.

Wednesday, September 19, 2012

New record for North Dakota Oil production

Oil production in North Dakota hit another record high above 674,067 barrels per day in July as oil companies successfully tapped the region's shale bounty, data from the state's Industrial Commission showed on Wednesday.

North Dakota Historical Monthly Oil Production 2012

Oil output in the Bakken, Sanish and Three Forks prospects also rose, to a record high just under 610,000 bpd in that month, the data showed.

North Dakota Monthly oil production 2012
In July 2012 the World Bank published new satellite data showing the U.S. provided the single largest addition to world natural gas flaring in 2011. Flaring is the combustion of produced natural gas that often occurs in the early stages of oil and gas development before adequate natural gas pipelines and processing infrastructure are available to take the gas to market. A significant amount of the increase in U.S. flaring has been concentrated in North Dakota, which is now the second largest oil producing state after Texas. As North Dakota expands oil production, substantial volumes of associated natural are being produced and flared.

natural gas flaring

The EPRINC report concluded the following:
1.    A prohibition on flaring would preserve currently burned natural gas and NGLs for future sale into the U.S. pipeline and product network. However, the financial penalties associated with delaying oil production outweigh the benefits of the gas savings for two reasons: 1) Crude oil is more valuable than gas, and 2) The economic penalty from delayed oil production exceeds the net gain of any savings in future production of natural gas. If a prohibition on natural gas flaring delayed oil production by just three years or five years, the economic loss would be $36 billion and $50 billion, respectively, for North Dakota alone.
2.    Deploying the infrastructure to capture and sell produced natural gas may actually yield a short-term increase in flaring as new high productive wells come online. Existing wells connected to gathering systems already selling gas may need to temporarily flare again as newer wells with higher production volumes come online.
3.    Flaring will likely decline in the near future as the infrastructure to capture associated gas production catches up with expanded oil production. 
When the author of the report, Trisha Curtis, a senior research analyst at EPRINC, was asked about initiatives to prohibit flaring, she said:
“Without the necessary infrastructure, you cannot safely produce the oil unless you are allowed to flare the associated gas. In addition, $4 billion of infrastructure investment is taking place for natural gas processing equipment and should contribute to continual declines in natural gas flaring in North Dakota. Policy prohibitions on flaring would slow down development of oil production, which is of enormous economic and energy security value to North Dakota and the United States. No one wants to waste this natural gas and we should implement prudent policy strategies which promote gas capturing infrastructure development as well as short term solutions to capture this gas.”

Friday, August 24, 2012

Oman Energy Report

Oman is the leading regional non-OPEC oil exporter.

Like most of its neighbors, Oman is dependent upon its oil sector for the majority of its export revenues and government spending. Oman possesses the largest oil reserves of any non-OPEC country in the Middle East and significant reserves of natural gas, of which it is a leading exporter regionally. While crude oil remains a significant yet declining part of its economy, Oman has made a concerted effort to diversify its economic base in face of its declining output. Under Sultan Qaboos bin Said's "Vision 2020" policy, Oman has made considerable investments and progress into developing gas resources, increasing gas production, and developing current and new oil fields.

Map of Oman


Oman has thus far implemented a successful program to reverse the decline in production, deploying some of the most sophisticated methods of oil extraction.

According to Oil & Gas Journal (OGJ), Oman has total proven reserves of 5.5 billion barrels of oil as of January 2012. Oman's reserves are found mainly in the north and central onshore areas, comprised of disparate clusters of smaller fields. This geological composition makes production costs some of the highest in the region. The transition into secondary and tertiary extraction techniques will only increase these costs further. Oman has thus far implemented a successful program to reverse the decline in production experienced for most of the past decade, deploying some of the most sophisticated methods of enhanced oil extraction.

middle eastern proven oil reserves 2012

Sector Organization

Oman's Ministry of Oil and Gas coordinates the state's role in the country's hydrocarbon sectors. Final approval on policy and investment, however, rests with the sultan of Oman, Qaboos bin Said, who also holds the office of prime minister. The implementation of oil policy is done through an integrated company in which the Sultanate of Oman owns the majority stake. Petroleum Development Oman (PDO) holds more than 90 percent of Oman's oil reserves and is responsible for 85 percent of its production. Aside from the government's 60 percent ownership, Shell (34 percent), Total (4 percent), and Portugal's Partex 2 percent) all own stakes in PDO.

Given the technical difficulties involved in production, the contract terms for international oil companies (IOCs) have become more favorable than elsewhere in the region, some allowing significant equity stakes in certain projects. Occidental Petroleum has the largest presence of any foreign firm and is the second largest oil-producer in Oman. Other major players with interests in Oman include: Shell, Total, Partex, BP, CNPC, KoGas, and Repsol.

Oman produced 889,000 barrels per day (bbl/d) of total petroleum liquids in 2011, 886,000 bbl/d of which was crude oil. Oman is expected to produce 915,000 bbl/d for 2012 after its Harweel Enhanced Oil Recovery project adds approximately 30,000 bbl/d to that total. Oil production in Oman has increased by more than 24 percent over the past four years, from a low of 714,000 bbl/d in 2007. PDO owns a concession which previously encompassed most of the country (Block-6), which has since been broken up and parceled out in successive bidding rounds. Much of the production growth has come from the success of international firms in developing former portions of Block-6.

In 2002, PDO initiated a review of its mature oil fields to determine the feasibility of enhanced oil recovery (EOR) techniques. On the determination of its review, PDO implemented a comprehensive and large scale EOR program using varied techniques on a field-by-field basis. Oman's oil sector is dependent upon these EOR techniques.

Oman's EOR program consists of three different general methods of extracting oil, some of which have never been used previously on a commercial scale. Miscible gas injection, steam (thermal) injection, and polymer flooding are the cornerstone of Oman's efforts to step up production. Miscible gas injection involves pumping gas, often toxic, that dissolves in the oil, facilitating higher flow rates, which is applied currently at its operations in the Harweel oil field cluster. As a result, Harweel will produce an additional 40,000 bbl/d. Thermal EOR methods are being deployed at Mukhaizna, Marmul, Amal-East, Amal-West and Qarn Alam fields. Thermal EOR entails the injection of steam in various ways and durations so as to facilitate the flow of heavier oil to the well. Mukhaizna has already increased production to 50,000 bbl/d, with Occidental expecting that to rise to 150,000 bbl/d by 2012. Thermal EOR is expected to increase production at both Amal-East and Amal-West to 23,000 bbl/d by 2018. Furthermore, the steam injection at Qarn Alam is projected to further production by 40,000 bbl/d by 2015 through a novel process in which the steam drains oil to lower producer wells. When reservoirs contain heavier grades of crude, the viscosity of the oil restricts its flow to the well. With such a heavy grade of crude, water injection might not prove effective, as the disparity in viscosity causes the water to pass the oil, instead of pushing it to the well. At projects such as Marmul, with its heavy oil, injecting polymer fluid is more effective when injected into a well.

Production growth will range across the entire spectrum of oil development in Oman. PDO wants to increase recovery rates at Yibal, a mainstay of Omani production, to 55 percent through traditional water-flooding. The discovery of al-Ghubar South in 2009 is the most promising discovery for Oman in years. According to the Ministry of Oil and Gas, al-Ghubar South could add as much as 1 billion barrels to reserves. Two significant discoveries were also made at Malaan West and Taliah in the Lekhwair cluster in northwest Oman, which will broaden baseline production in the future.

Other large EOR projects include:

Karim Cluster
- a cluster of 18 small oil fields all flowing to the Nimr production facility, which is operated by Medco (Indonesia). Currently producing 18,000 bbl/d, PDO is aiming to boost production to around 35,000 bbl/d in the short-term.
Harweel Cluster - PDO estimates a capacity of 100,000 bbl/d from the current 44,000 bbl/d in the next five years.
Growth of up to 70,000-80,000 bbl/d from five clusters, such as the Rima Cluster, is expected through various efficiency gains and EOR applications.

Oman has also opened tenders for exploration and production in new oil fields in blocks Baqlah, Karawan, Kahil, Qatbeet, and Block 65 to be awarded in 2012. Additionally, Oman is exploring unconventional resources of light tight oil and shale plays.

2012 crude production Oman

Consumption and Exports

In 2011, Oman consumed approximately 98,000 bbl/d of petroleum products. Consumption has increased over the last decade, nearly doubling from a level of 52,000 bbl/d in 2000. This has largely been attributable to Oman's industrialization and expanding petrochemical sector, along with improved roadways and an expanding vehicle fleet.

Though Oman is a significant net exporter of petroleum, it is not a member of OPEC. As is the case with other exports from the Gulf, Asia provides the main onsumer markets for Omani crude; led by China, Thailand, South Korea, and Japan.
Pipelines and Export Terminals

Oman's pipeline system is mostly focused on delivering crude oil to the country's only oil export terminal at Mina al-Fahal. Located near the capital, Muscat, both the export terminal at Mina al-Fahal and the Main Oil Line feeding the facilities are run by PDO. Pipelines also feed industrial complexes and petrochemical plants, which form an integral part of economic diversification and Oman's expansion into downstream activities. PDO operates over 1,000 miles of oil pipelines which run throughout the country. Additionally, the government has commissioned an export terminal at Sohar along with its plans to expand the Sohar refinery.
Downstream Activities

In 2012, Oman has a refining capacity of 222,000 bbl/d, split between two refineries. The Mina al-Fahal refinery was Oman's first, opened in 1982, and has a capacity of 106,000 bbl/d of crude distillation after an expansion in 2007. The Sohar refinery was brought on-stream in 2006, with a refinery capacity of 116,000 bbl/d. The refineries are operated by the Oman Refineries and Petrochemicals Company (ORPC), the result of a 2007 merger between the Oman Refinery Company and the Sohar Refinery Company. ORPC is owned by the Omani Ministry of Finance (75 percent) and Oman Oil Company (OOC) (25 percent). The Sohar refinery concluded a front-end engineering and design(FEED) study for an expansion project, which will expand crude distillation capacity by 50,000 to 60,000 bbl/d by 2015-16.

Oman continues to pursue the building of a large refinery and petrochemical complex at al-Duqm in southern Oman, which would be geared toward export markets, ultimately making Oman a net exporter. Under a memorandum of understanding (MoU) signed in July 2009 and Royal Decree in 2011 establishing the Special Economic Zone at Duqm, a joint venture between the Omani government and international investors would build a 230,000 bbl/d refinery, a crude oil export terminal, and several large petrochemical facilities, among other commercial ventures.
Natural Gas

Oman requires increased natural gas supplies to meet the growth in its domestic consumption as well as its enhanced oil recovery projects and LNG export obligations

Oman has proven reserves of natural gas of 30 trillion cubic feet (Tcf) as of January 2012, according to OGJ. Due to increasing EOR applications, rising domestic demand, and export obligations, Oman's gas demand has outpaced its production. The Ministry of Oil and Gas are aggressively seeking to increase exploration and production from its reserves. The ministry announced plans to reassess natural gas reserves, planning to increase reserves by a trillion cubic feet per year for the next 20 years and producing more through developing new gas fields, building more plants and through programs akin to the EOR projects implemented in the oil sector.

Given its overwhelming domestic demand and the long-term liquefied natural gas (LNG) export contracts, the country has insufficient feedstock for electricity generation at seasonal peak times. This shortfall has resulted in service interruptions that have slowed industrialization and economic diversification programs, as well as economic growth generally. A regional power grid is being constructed between all Gulf Cooperation Council (GCC) members, of which Oman is one. This will create the possibility to import electricity, especially from neighboring UAE and its planned nuclear plants, and lessen the strain on domestic natural gas supplies used as feedstock. This prospect will only emerge in the medium-term however, largely after 2017 when UAE's nuclear plants begin to come on-line.
Sector Organization

PDO has an even greater presence in the natural gas sector than in the oil sector, accounting for nearly all of its natural gas supply along with smaller contributions from Occidental Petroleum and Thailand's PTTEP. The government enlists foreign companies in new exploration and production projects, offering generous terms for developing fields that require the sophisticated technology and expertise of the private sector. Developing gas projects with foreign firms such as Occidental, BP, PTTEP, and Petronas will determine Oman's future production. The Oman Gas Company (OGC) directs the country's natural gas transmission and distribution systems. The OGC is a joint venture between the Omani Ministry of Oil and Gas (80 percent) and OOC (20 percent). Oman Liquefied Natural Gas (OLNG)- owned by a consortium including the government, Shell and Total- operates all LNG activities in the ultanate through its three liquefaction trains in Qalhat near Sur.

2011 top middle east natural gas exporters


Oman produced over one trillion cubic feet (Tcf) of natural gas, equal to about 2.75 billion cubic feet per day (Bcf/d) in 2011. Natural gas production has more than doubled in the past decade and ramped up considerably in the years subsequent to Oman's nadir of oil production. Production will likely continue to grow as companies are in various stages of licensing, exploring, producing, and expanding fields; especially BP's Khazzan-Makarem tight gas project with gas reserves of an astounding 100 Tcf and expected production of one Bcf/d by 2016-17. In addition, the PDO has approved the building of a greenfield gas project, including gas processing plants, and pipelines, in central Oman. The project will produce approximately 42 Mcf/d of gas from Hasirah and Hawqa oil fields. WorleyParsons will conclude the FEED study in 2015. Oman has also launched the Depletion Compression Project, which will boost inlet pressure to bring up production, for its declining gas field at Saih Rawl. Despite Oman's prodigious efforts to diversify its base into gas production, it may face an added internal obstacle. Following protests in 2011, Sultan Qaboos bin Said granted the Majlis al-Shura, Oman's elected legislature, oversight and legislative authorities, allowing the Majlis to question projects and contracts. While the sultan has ultimate authority, the Majlis may have an effect on future energy developments.

Oman natural gas production and consumption


Natural gas consumption rose rapidly over the past decade, seeing a 180 percent increase from 2000 to a total of 619 Bcf in 2010. This increase is largely attributable to economic expansion and population growth, while re-injection of natural gas to increase oil production takes up just over 20 percent but continues to rise. A lack of additional natural gas resources has impeded progress in economic diversification, especially in the industrial sector. Although Oman is a net exporter of oil and natural gas, it also imports small volumes of natural gas from Qatar via UAE. The Dolphin Pipeline provides Oman's only natural gas imports, providing approximately 200 million cubic feet per day (Mcf/d).

Oman's natural gas pipeline system is operated by the Oman Gas Company (OGC), a joint venture between the Sultanate of Oman, with an 80 percent equity holding, and Oman Oil Company (OOC) which owns the remaining 20 percent. The pipeline system consists of 1,250 miles of pipeline, transporting natural gas supplies from production facilities primarily to gas-powered electric plants, participants in the petrochemical and industrial sectors, as well as to the Oman and Qalhat LNG projects. In 2015-16, OGC will add a 143-mile, 36-inch gas pipeline from Saih Nihayda field in Central Oman to service the special economic zone in Duqm on the east coast.

The Oman and Qalhat LNG projects are the sole source of natural gas exports from Oman, with a nameplate capacity of 506 Bcf per year, a daily average of 1.4 Bcf/d. In 2010, Oman exported a total of 406 Bcf, a decline of 2 Bcf from the previous year. Despite facing a gas shortage and increasing domestic demand, Oman exports 55 percent of its gas because of term contracts, the first of which expires in 2020. Aside from the majority stake held by the government of Oman (51 percent), shareholders of Oman LNG include Shell (30 percent), Total (5.54 percent), Korea LNG (5 percent), with Partex and other Japanese investors comprising the rest. Qalhat LNG, operator of one of the three trains, is primarily owned by the government (47 percent) and Oman LNG (37 percent). The gas is sourced from the Saih Rawl and Saih Nihayda gas fields in central Oman. The LNG exported from these projects is destined for Asian markets, principally South Korea and Japan.


Given shortfalls in natural gas production, in 2007 Oman began to import natural gas. The Dolphin Pipeline system, which transports 2 billion cubic feet per day (Bcf/d) of natural gas from Qatar to neighboring UAE and eventually to Oman by way of the Fujairah - al-Ain pipeline, provides increasing natural gas supplies, around 200 Mcf/d, for use in electricity generation.

Additionally, with a MoU signed in 2007, Iran and Oman plan to build a pipeline to bring 1 Bcf/d from source gas in the shared Hanjam and West Bukha fields in the Strait of Hormuz to Qalhat LNG in Sur. This would free domestic production to be connected to the domestic grid. However, the proposed pipeline's future is in doubt due to U.S.-imposed sanctions on Iran.
dolphin pipeline

Wednesday, July 18, 2012

How dependent is U.S. on foreign oil?

The United States relied on net imports (imports minus exports) for about 45% of the petroleum (crude oil and petroleum products) that we consumed in 2011. Just over half of these imports came from the Western Hemisphere. Our dependence on foreign petroleum has declined since peaking in 2005. 

U.S. imports domestic petroleum shares demand

The United States consumed 18.8 million barrels per day (MMbd) of petroleum products during 2011, making us the world's largest petroleum consumer. The United States was third in crude oil production at 5.7 MMbd. But crude oil alone does not constitute all U.S. petroleum supplies. Significant gains occur, because crude oil expands in the refining process, liquid fuel is captured in the processing of natural gas, and we have other sources of liquid fuel, including biofuels. These additional supplies totaled 4.6 MMbd in 2011.

The United States imported 11.4 MMbd of crude oil and refined petroleum products in 2011. We also exported 2.9 MMbd of crude oil and petroleum products, so our net imports (imports minus exports) equaled 8.4 MMbd.

sources of U.S. NEt Petroleum Imports 2011

In 2011, the United States imported 2.4 MMbd of petroleum products such as gasoline, diesel fuel, heating oil, jet fuel, and other products while exporting 2.9 MMbd of products, making the United States a net exporter of petroleum products.
Over Half of U.S. Petroleum Imports Come from the Western Hemisphere

Some may be surprised to learn that 52% of U.S. crude oil and petroleum products imports came from the Western Hemisphere (North, South, and Central America, and the Caribbean including U.S. territories) during 2011. About 22% of our imports of crude oil and petroleum products came from the Persian Gulf countries of Bahrain, Iraq, Kuwait, Qatar, Saudi Arabia, and United Arab Emirates. Our largest sources of net crude oil and petroleum product imports were Canada and Saudi Arabia.

U.S. net petroleum imports 1949 2011

Top Sources of Net Crude Oil and Petroleum Product Imports:
  • Canada (29%)
  • Saudi Arabia (14%)
  • Venezuela (11%)
  • Nigeria (10%)
  • Mexico (8%)

It is usually impossible to tell whether the petroleum products you use came from domestic or imported sources of oil once they are refined.
Reliance on Petroleum Imports has Declined

U.S. dependence on imported oil has declined since peaking in 2005. This trend is the result of a variety of factors including a decline in consumption and shifts in supply patterns.1 The economic downturn after the financial crisis of 2008, improvements in efficiency, changes in consumer behavior and patterns of economic growth, all contributed to the decline in petroleum consumption. At the same time, increased use of domestic biofuels (ethanol and biodiesel), and strong gains in domestic production of crude oil and natural gas plant liquids expanded domestic supplies and reduced the need for imports.

Friday, July 13, 2012

Bakken formation causes Wti Spread to increase

Since the mid-1980s, benchmark crude oil prices such as West Texas Intermediate (WTI) in the United States and Brent crude oil in Europe have served as reference points that the market uses for pricing other crude oils. Since late 2010, however, WTI has been selling at a large discount to Brent, and has become less useful as an indicator for U.S. petroleum product prices. Beginning with the July 2012 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) will supplement its traditional WTI and average refiner acquisition cost (RAC) forecasts with a forecast of the Brent crude oil spot price that will directly enter into price forecasts for gasoline and other refined products in the STEO (see Brent Crude Oil Spot Price Added to Forecast). EIA currently expects the Brent crude oil price will average $99 per barrel over the second half of 2012 and $98 per barrel in 2013.

Until 2008, all North American crude oil grades broadly tracked fluctuations in the WTI price and were clustered within about $8 per barrel of the WTI spot price (Today in Energy, June 21, 2012). Pricing differences between crude oil grades were explained largely by the different quality characteristics of the crude oil in each location and relative transportation costs. Between January 2004 and late 2010, WTI consistently sold at about a $1 to $2 premium to Brent as the two crude oil prices closely tracked each other 

wti and brent crude oil prices

Starting in late 2010, WTI began to sell at a discount to Brent due to rapid increases in crude oil production from tight oil formations (This Week In Petroleum, March 14, 2012), primarily from the Bakken formation in North Dakota and the Eagle Ford shale in Texas, which led to transportation bottlenecks in and around the Cushing, Oklahoma storage hub where WTI oil is traded (This Week In Petroleum, May 16, 2012). In addition, Brent prices were being positively impacted by supply disruptions in the waterborne light-sweet crude oil markets (e.g., outages in Libya, Nigeria). The WTI discount to Brent continued to widen in 2011, reaching a monthly average high of about $27 per barrel in September 2011, before falling back to around $13 per barrel in June 2012. With limited pipeline capacity, the additional crude oil volumes have been moved out of the region by rail and to a lesser extent by truck. The $6 to $12 per barrel cost of transportation by rail and truck has been cited by some analysts as a floor for the Brent-WTI spread.

With the large gap between Brent and WTI prices, WTI is no longer representative of the marginal crude oil price driving petroleum product prices in the U.S. market. A comparison of Reformulated Gasoline Blendstock for Oxygenate Blending (RBOB) spot prices -- which represent wholesale gasoline prices -- to the Brent, WTI, and RAC crude oil prices in the largest U.S. refining region, the Gulf Coast, illustrates the growing disconnect of gasoline prices from both WTI and RAC prices since late 2010 (Figure 2). The spreads between Gulf Coast RBOB and the Brent, WTI, and RAC crude oil prices tracked each other closely, averaging 27 cents per gallon from 2006 through 2010. Since the end of 2010, only Brent has held near its historical average spread, averaging 18 cents per gallon, while the WTI and RAC spreads have averaged 57 cents per gallon and 42 cents per gallon, respectively. Thus, Brent has become more representative of the marginal cost of crude oil for the majority of refiners in the Atlantic Basin. In the Rocky Mountain region and the Midwest, discounted inland crudes are widely used by refiners. However, because Midwest product markets also rely on products produced outside of that region, product prices still reflect the price of waterborne crudes that are best represented by the Brent benchmark.

U.S. Gulf Coast RBOB- Reference Crude oil Price Spreads

Gasoline and diesel fuel prices both increase after many weeks
The U.S. average retail price of regular gasoline increased six cents this week to $3.41 per gallon, 23 cents per gallon lower than last year at this time. This is the first increase in the U.S. average retail gasoline price since April 2, 2012. Prices decreased in the Rockies and west, while to the east they increased. The largest increase was in the Midwest, where the average price was up 12 cents to $3.44 per gallon. The East Coast price increased six cents from last week and is now $3.35 per gallon. The price on the Gulf Coast is $3.16 per gallon, up four cents from last week. Moving west, the Rocky Mountain average price decreased three cents to $3.55 per gallon, and the West Coast price is $3.67 per gallon, down four cents from last week.

The national average diesel fuel price increased four cents to $3.68 per gallon, 22 cents per gallon lower than last year at this time. Prices increased in all regions of the Nation except the Rocky Mountains, where the price decreased three cents to $3.68 per gallon. The largest increase was in the Midwest, where the price increased six cents to $3.64 per gallon. On the Gulf Coast the price increased 4 cents to $3.61 per gallon. The East Coast price is $3.73 per gallon, an increase of three cents from last week. Rounding out the regions, the West Coast price increased a penny to $3.80 per gallon.

Propane stocks build again
Last week, total U.S. propane inventories continued their seasonal growth, adding 1.0 million barrels of new stocks to end at 63.2 million barrels, 18.6 million barrels (42 percent) higher than a year ago. Most of the build occurred in the Gulf Coast region, which added 0.8 million barrels of propane inventory. The Midwest and East Coast regions grew by 0.2 and 0.1 million barrels respectively, and Rocky Mountain/West Coast stocks dropped 0.2 million barrels. Propylene non-fuel-use inventories represented 6.6 percent of total propane inventories.