OGJ Newsletter

Feb. 16, 2009
General Interest — Quick Takes

IEA again cuts 2009 oil demand forecast

In its latest monthly Oil Market Report, the International Energy Agency has revised downward its outlook for 2009 worldwide oil demand.

The Paris-based agency now sees worldwide demand averaging 84.7 million b/d, down 570,000 b/d from its previous projection. The new forecast would mean that demand will decline 1 million b/d from 2008.

The revised outlook puts average 2009 oil demand in the Organization for Economic Cooperation and Development at 46 million b/d, which is 340,000 b/d lower than in IEA’s previous forecast. Meanwhile, non-OECD demand is cut 230,000 b/d to 38.7 million b/d.

These demand outlook reductions follow a bleaker economic outlook from the International Monetary Fund, which now forecasts that global growth in gross domestic product will be a measly 0.5% this year. IEA says that widespread financial and economic collapse are now the key brakes on global oil demand.

With 2009 non-OECD oil demand now expected to climb only 500,000 b/d from last year, IEA sees the outlook for Asia and the former Soviet Union as particularly grim.

“Oil demand growth in China is thus expected to be less than a fifth of what was recorded in recent years, while in the rest of Asia and the FSU growth will probably be nil. Only Latin America and the Middle East, partly insulated by price subsidies and, in the case of the Middle East, a strong fiscal position, will be able to sustain relatively strong growth—but at about half the pace of previous years,” IEA said.

EIA raises global oil demand decline forecast

Global petroleum demand, according to the US Energy Information Administration, will fall by another 400,000 b/d during 2009 as economic conditions worsen. EIA reported Feb. 10 in its latest short-term energy outlook that it now projects worldwide oil consumption will drop by 1.2 million b/d this year as a deteriorating world economy and a weak oil consumption outlook keep the market well supplied—despite two downward revisions in the last 2 months by the Organization of Petroleum Exporting Countries.

Reduced demand and rising surplus production capacity through at least mid-2009 reduce the possibility for a strong and sustained oil price rebound over that period, the federal energy analysis and forecasting service said.

“OPEC is scheduled to meet in Vienna on Mar. 15, which could lead to another production cut to mitigate some of the slack in the world oil market. However, near-month oil prices will likely be driven primarily by the global economy,” it noted.

EIA now assumes that global gross domestic product, weighted according to shares of world oil consumption, will decline by 0.1% in 2009 and rise by 3% in 2010. January’s short-term energy outlook assumed 0.6% growth in real GDP in 2009 and 3% growth in 2010.

In the US, EIA expects GDP to fall by 2.7% this year, triggering consumption declines for all major fuels. Retail regular gasoline prices are projected to average $1.95/gal nationwide in 2009 and $2.19/gal in 2010.

Study sees pause in oil sands output growth

The oil price slump will stall for several years but not reverse growth of production from Alberta’s deposits of oil sand and heavy oil, says the Canadian Energy Research Institute (CERI).

A report by David McColl, CERI chief economist, forecasts oil sands production of 1.9-2.9 million b/d in 2015 and 3.7-5.4 million b/d in 2030.

Oil sands production in 2007, the last full year for which an annual average is available, was 1.2 million b/d, according to the Canadian Association of Petroleum Producers.

The new CERI projection updates estimates published last June, before crude oil prices fell.

The reference-case forecast at that time was for steady growth of oil sands production to 3.4 million b/d by 2015 and 5 million b/d by 2030.

The new outlook assumes the price of West Texas Intermediate crude stays below $60/bbl for most of 2009 and credit markets continue to lack liquidity. It assumes economic recovery begins in early 2010, with liquidity slowing returning to the economy.

Growth in oil sands output will not resume until 2 years after the economy recovers, McColl says. It initially will be limited to established oil sands projects and others with financing in place before the credit collapse of last year.

The new forecast cuts the estimate for investment in new oil sands production to $218 billion (Can.) from $315 billion in the reference-case outlook last year.

The study assumes that expansion of the oil sands industry requires a WTI price above $70/bbl.

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Exploration & Development — Quick Takes

Potential of Israel’s Tamar hiked to 5 tcf

Gross mean resource potential at the Tamar gas discovery in the Mediterranean off Israel is a “clearly commercial” 5 tcf, said operator Noble Energy Inc., Houston, after analyzing postdrill and production test data.

Performance modeling indicates that the discovery well, in 5,500 ft of water 55 miles off Haifa, can be completed at a producing rate of more than 150 MMcfd, Noble Energy said. The company’s predrill estimate of resource potential was 3.1 tcf.

The well tested at 30 MMcfd limited by equipment capacity from a 59-ft interval in the lowermost reservoir. Drilled to 16,076 ft, it cut more than 460 ft of net pay in three high-quality reservoirs.

The group led by Noble Energy will move the Atwood Hunter semisubmersible to drill the Dalit prospect in 4,500 ft of water on the Michal license 28 miles off Haifa. Proposed total depth is 12,500 ft. The rig will then return to the Matan license to drill an appraisal well at Tamar (see map, OGJ, Feb. 2, 2009, p. 39).

Dalit, covered by 3D seismic, has a predrill gross mean resource of 700 bcf with a 40% chance of success, the company said.

California blocks state waters oil project

The California State Lands Commission voted not to approve an extended reach drilling project that would have recovered nearly 100 million bbl of oil and brought as much as $5 billion to the financially insolvent state.

Plains Exploration & Production Co., Houston, had proposed in 2005 to drill 17 wells from shore and from existing Platform Irene to develop the Tranquillon Ridge prospect. Drilling was to start in 2009 and continue 5-6 years, and production would last 14 years.

Lt. Gov. John Garamendi, commission chairman and a former deputy Interior secretary under former US President Bill Clinton, said the plan “would signal that California wants to open offshore drilling.” Garamendi also said US House Speaker Nancy Pelosi (D-Calif.) and other members of the California congressional delegation had concerns the lease would have undercut their attempts to reintroduce a federal moratorium on offshore drilling.

In return for being allowed to tap oil in the fractured Miocene Monterey formation 4-6 miles off the northern Santa Barbara County coast, Plains had offered to stop offshore oil drilling by 2022 and shut its oil and gas handling plant at Lompoc. Tranquillon Ridge would have been the first new lease granted in state waters since the 1969 oil spill.

Tom Bjorklund of the University of Houston wrote that the US Minerals Management Service estimates that discovered and undiscovered conventionally recoverable oil and gas resources of the Pacific OCS federal waters range from 14 to 19 billion bbl of oil equivalent. Potential in state waters may reach 3.4 billion boe, he said.

Eni builds energy partnership with Sonangol

Eni SPA will evaluate setting up an onshore electric power plant in Angola that will use associated gas under a new agreement signed with Sonangol to boost that country’s energy facilities and industrial activities.

Sonangol and Eni also will conduct a joint study to evaluate highly prospective Angolan onshore basins and their production potential.

According to their third agreement, the companies will focus on educational projects and training of Angolan professionals, Eni said.

These agreements build upon a memorandum of understanding signed in August 2008 when the companies pledged to strengthen their strategic cooperation and for Eni to contribute to Angola’s energy, social, industrial, and educational spheres.

Eni has been in Angola since 1980, has equity production of 140,000 boe/d, and operates deepwater Block 15/06.

Drilling & Production — Quick Takes

OPEC delays 35 projects due to falling prices

Members of the Organization of Petroleum Exporting Countries, their economies battered by falling oil prices, have delayed 35 of 150 planned oil drilling projects by at least 4 years.

“Current prices threaten the very sustainability of planned investment,” said OPEC Sec. Gen. Abdalla Salem El-Badri in a speech at London’s Royal Institute for International Affairs (RIIA).

“These projects are on hold…and will continue to be until the [oil] price recovers,” El-Badri said, adding that of the 150 projects due to come on line in the next few years, 35 had been set back to after 2013.

“The start-up dates of many other projects are still expected to slip,” said El-Badri, who noted that that oil has fallen to $40/bbl from a record near $150/bbl in July, resulting in a loss to OPEC of some $356 billion.

“This year our income will be cut by 50%,” he said.

UAE Oil Minister Mohammed al-Hamli, underlining El-Badri’s view, said at $40/bbl, the price of crude now is about half that required to attract enough investment in new supply.

“It is clear that if oil prices remain low for much longer, the negative investment trend will increase to such an extent that large supply shortages will develop when the present economic woes are over,” al-Hamli told listeners at RIIA.

The UAE oil minister expressed OPEC’s worry that low prices could lead to lower future supplies, potentially causing prices to surge when demand eventually does recover.

OPEC’s view was met with skepticism from industry analysts.

“They’re only hurting themselves,” said Phil Flynn, an analyst at Alaron Trading Corp., one of several who warned that taking production projects off line represented short-term thinking on the part of OPEC members.

According to Flynn, any spike in crude prices because of production declines from OPEC members will make it harder for economies to recover and for demand to pick up naturally. Then, he said, when demand does pick up, OPEC members won’t have the production capacity to meet it.

Eni to use FPSO concept in Goliat field

Eni Norge AS has chosen to develop its deepwater Goliat oil and gas field in the Barents Sea using Sevan Marine ASA’s circular floating production, storage, and offloading vessel.

Sevan Marine’s proprietary technology to be used on its 1000 FPSO will include an oil production capacity of 100,000 b/d, gas production of 3.9 MM cu m/day, and oil storage capacity of 1 million bbl. It will grant Eni a license to use the FPSO in the field, which is to start production in 2013 and produce for 15-20 years.

It is estimated that the engineering phase, following the front-end engineering and design phase, will be completed during 2009. The estimated value for the contract is 150 million kroner. The plan was for Eni to submit its final plan to the Norwegian authorities by yearend 2008, followed by a Parliament review in the spring session of 2009.

Subsea wells will be linked to the FPSO, with flowlines and risers scheduled to be installed in June-July 2010 and May-August 2011.

Potential bidders, including Sevan Marine’s main competitor Aker Kvaerner AS, will have the opportunity to bid on the engineering, procurement, and construction contract for the Goliat FPSO, an Eni Norge spokesman told OGJ.

The company will issue a new tender for the EPC, but it has not yet decided the timetable. “Originally we were going to choose the concept and award the EPC at the same time, but now there is a change in the market as costs are coming down and we could benefit from waiting [to] select the contractor,” he explained.

Aker Kvaerner said it would present a competitive delivery model and tender for the EPC contract and will aim to construct the topside and processing modules, as well as the hook up, in Norway.

Eni said it chose the FPSO production concept because it was cheaper, could tie-in future discoveries, and had better environmental advantages than landfall solutions.

Florida’s Jay field idle in cost-price squeeze

Quantum Resources Management LLC, Denver, informed interest owners that it had suspended production from giant Jay oil and gas field in the Florida Panhandle on Dec. 22, 2008.

The dramatic decline in oil prices and high operating expenses led to the action, Quantum said, adding that it maintains the capability to reestablish production and is “analyzing alternative production scenarios that might result in improved economics.”

Quantum informed royalty owners, including LL&E Royalty Trust, Austin, that it is analyzing all options to reduce operating costs.

Discovered in 1970, Jay field in Santa Rosa County was estimated to have 763 million bbl of original oil in place, of which 458 million bbl was judged recoverable. Jay had produced 369 million bbl through 1990 and was down to about 4,000 b/d of oil and large volumes of water in recent years.

Shell lets contract for Gumusut-Kakap work

Sabah Shell Petroleum Co. Ltd. Sdn. Bhd. awarded JP Kenny Wood Group a contract for subsea integration and follow-up engineering work for the Gumusut-Kakap deepwater development in 1,300 m of water, 120 km off Sabah, Malaysia, on Blocks J and K.

The 4-year contract provides for specialist subsea engineers, engineering studies, design, and follow-up engineering support through the project’s fabrication and commissioning phases.

Sabah Shell will operate the development that includes the first deepwater semisubmersible floating production facility off Malaysia. The facility has a design capacity for processing 150,000 bo/d.

Gumusut-Kakap will produce from 19 subsea wells with oil exported via a pipeline to a new oil and gas terminal, planned at Kimanis, Sabah. The project will reinject associated gas into the reservoir to help improve oil recovery. Development drilling commenced in January 2008.

A 2006 unitization and unit operating agreement combined the Gumusut and Kakap fields into a single development.

The semisubmersible is under construction at the Malaysia Marine & Heavy Engineering’s fabrication yard in Pasir Gudang, Johor, Malaysia.

Sabah Shell completed the Gumusut discovery well in December 2003 on Block J. The well included a vertical well and two sidetracks. The field extends into Block K on which Murphy operates the Kikeh field.

Processing — Quick Takes

Senate urged to deny higher ethanol blending cap

A coalition of associations and organizations asked the US Senate on Feb. 6 not to approve a provision in the economic stimulus bill it is debating that would increase the current ethanol blending cap.

The National Petrochemical & Refiners Association and 18 other groups said that adopting such a provision would short-circuit the Clean Air Act regulatory structure for approving the introduction of new fuels or fuel blends, and would lead to increased air emissions from gasoline-powered engines and potentially endanger consumers.

“In our collective opinion, a decision on whether to permit the use of ethanol concentration in excess of 10% in gasoline (so-called ‘midlevel ethanol blends’) in motor vehicle and equipment engines must be guided solely by sound, unbiased, and comprehensive science and must hold true to the fundamental purposes of protecting the environment and consumers,” they said in a letter to Senate Majority Leader Harry M. Reid (D-Nev.) and Minority Leader Mitch McConnell (R-Ky.)

In addition to NPRA, the coalition included the Alliance of Automobile Manufacturers, American Lung Association, Engine Manufacturers Association, Friends of the Earth, International Snowmobile Manufacturers Association, Natural Resources Defense Council, Outdoor Power Equipment Institute, and Union of Concerned Scientists.

“Collectively, our organizations strongly believe that this issue should not be part of the economic stimulus package currently under consideration by the United States Senate,” the letter continued. Before midlevel ethanol blends are allowed, testing by the US Environmental Protection Agency and the Department of Energy should be allowed to continue, and the results must indicate that higher ethanol blends in gasoline-powered engines do not pose a threat to air quality or consumers, it urged.

South Korean refiners eye profits, reduce closures

South Korean refiners, eyeing the possibility of increased overseas sales due to improved margins for fuel products, plan to shut down less capacity during the peak maintenance season this year.

Asian refiners generally perform maintenance and safety checks twice a year: between April and June, ahead of the peak summer driving season, and again in October and November, before a surge in heating fuel demand during winter.

But this year, according to a report by Bloomberg News, South Korean refiners will close just two crude distillation units—totaling 410,000 b/d, or 15% of capacity—in the first half of June. That compares with the closure of 24% of capacity during the same period in 2008.

Jason Lee, a petroleum trading manager at SK Networks Co., explained that profits from exports are better than expected because of reduced run rates among Asian refiners such as Nippon Oil which last month said it would reduce crude throughput by 12% from a year earlier in February.

Bloomberg cited a report by the Bank of America that said the margin for refined products in Singapore was $8.34 in the week ending Jan. 16, a 9% increase over the $7.65 recorded during the same period in 2008.

The plans for closures include:

  • SK Energy will close the 240,000 b/d No. 4 crude distillation unit at its Ulsan refinery between Mar. 27 and Apr. 29; the 110,000 b/d No. 2 crude distillation unit June 3-30; and the 60,000 b/d No. 1 crude distillation unit June 19-23.
  • GS Caltex Corp. will shut the country’s largest crude distillation unit, the 300,000 b/d No. 4 unit at the Yosu refinery, between May 7 and June 8.
  • S-Oil Corp. will shut the 93,000 b/d No. 1 crude distillation unit at the Onsan refinery Apr. 1-19.
  • Hyundai Oilbank Co. doesn’t plan to halt any crude distillation units at its Daesan refinery.

Sudan to launch its first ethanol mill in March

Sudan’s state-owned Kenana Sugar Co.’s (KSC) first ethanol mill, built by Brazil’s Dedini Industrias de Base, which builds facilities for the sugar and ethanol industries, is set to begin operations at the end of March. Situated within the KSC complex, 250 km south of Khartoum, the mill is expected to produce about 61 million l./year of alcohol from molasses made in the country.

Sudan’s ambassador to Brazil, Omer Salih Abubakr, said KSC is contracted to supply 5 million l./year of ethanol to the UK.

Abubakr said about $800 million has been invested in the overall KSC project—largely sugar plantations and sugar mills—with funds coming from several governments, including Sudan, Saudi Arabia, the UAE, Kuwait, and Japan.

Sudan is one of the leading sugar cane growers on the African continent, producing slightly more than a million tonnes/year. KSC exports most of it to the Middle East.

In July 2008, aiming to diversify its output and export potential, the Sudanese government invited Brazilian ethanol facility contractors such as Dedini SA to build as many as 18 sugarcane ethanol plants in the African country. “We have plans to expand the production of sugar and want Brazil to help us with this,” Sudan’s vice-secretary for foreign affairs, Mutrif Saddig, told Brazil’s state news agency. “We are after Brazilian (ethanol) technology,” Saddig said.

At the time, Dedini said it was retrofitting an existing KSC sugar cane milling unit with equipment necessary to make ethanol.

Until recently, about 80% of Dedini’s business has been confined to the Brazilian market, where sales have grown steadily at 20-30%/year for the past 5 years. But export markets are beginning to open. In August 2008, Indonesia’s Medco Group said it would form a joint venture with Dedini to set up a bioethanol plant in Papua, with production scheduled to begin in 2011.

“The plant will have a production capacity of 30,000 b/d and will require an investment of $200 million,” said Arifin Panigoro, Medco’s founder.

Transportation — Quick Takes

Alaska Gas Pipeline lets gas plant contract

Alaska Gas Pipeline LLC has let a contract to Fluor WorleyParsons Arctic Solutions for the design of the gas treatment plant that will process gas delivered from Alaska through its proposed 4 bcfd pipeline to the Lower 48, Alaskan, and Canadian markets.

Fluor WorleyParsons will do the work under a multimillion preliminary front-end engineering and design (pre-FEED) contract, and this will be the world’s largest gas treatment plant with process modules weighing up to 9,000 tons.

The 5 bcfd plant on the North Slope will remove carbon dioxide, water, hydrogen sulfide, and other impurities from the gas. “It will also provide initial gas chilling and compression,” Fluor said.

The 2,000-mile, 48-in. Alaskan pipeline is expected to start operations in 2018 and is budgeted to cost $30 billion.

Baraka Petroleum proposes Mauritanian pipeline

Mauritania is considering a proposal submitted by Baraka Petroleum Ltd., Perth, to assist in the development of a proposed Mauritanian oil and gas pipeline system. Such a transportation system would accelerate the development of the country’s oil and gas reserves, Baraka said.

The pipeline system envisaged includes a pipeline link from the Taoudeni region in the east to the town of Zouerate in the northwest and another link extending south to Nema and from there, west to the capital Nouakschott on the coast. Spurs could be built to feed other settlements along the route. Nema also could become a hub for a southern link to neighboring Mali.

The proposal was first presented to Mauritanian authorities in 2006 and 2007 and was most recently presented to the current government last November. The proposal is a memorandum of understanding to develop regulations for transporting hydrocarbons in Mauritania and for the development of the oil and gas pipeline system in the country.

The MOU proposes that a new company, sponsored by Baraka in conjunction with the government, would plan and manage suitable regulatory laws and regulations to make it possible for Mauritania to develop the Taoudeni reserves (still to be delineated) through the construction of a pipeline system.