OGJ Newsletter

July 6, 2009

General InterestQuick Takes

BP reports fastest oil demand fall since 1982

Worldwide oil demand has fallen at its fastest rate since 1982, according to BP PLC’s statistical review of world energy.

Tony Hayward, chief executive officer of the company, said global oil production will fall because of dwindling demand and improvements in energy efficiency. Last year, oil consumption in the developed world fell by 1.6%—the largest decline since 1982. This trend is expected to continue.

For the first time, the developing world led by China consumed more energy than OECD countries: China represented nearly three quarters of global growth and its energy usage was 17.7%. This was the slowest rate for 5 years.

“This is not a temporary phenomenon but one that I believe will only increase still more over time,” Hayward said. “It will continue to affect prices and bring with it new challenges over economic growth, energy security, and climate change.”

Oil demand dropped by 1.5 million b/d in the developed world, spurred first by record oil prices and the global economy collapsing. Non-OECD countries also registered slower growth in demand at just 1.1 million b/d.

Hayward said he believes oil prices will hit $60-90/bbl in the future, arguing that oil producers need at least $60/bbl to underpin investment and consumers appeared comfortable with prices beneath $90.

“In the OPEC world, most OPEC countries need prices north of $60-70/bbl to be able to invest in today’s capacity, to invest in their social government programs and to invest in tomorrow’s capacity. If that price isn’t realized, then the first thing that gets cut is tomorrow’s capacity.”

According to the energy review, worldwide oil production climbed by 0.4% last year.

In 2008, gas consumption crept along, below the decade average at 2.5%. China experienced the fastest rise in gas consumption, reaching a level of 15.8% while US gas consumption rose 0.6% and the UK 3%.

BP said: “Globally, gas production rose 3.8%, above the 10-year trend of 3%. This was driven strongly by the US, which recorded its highest ever annual increase in gas production as strong activity in the development of unconventional gas resources raised output by 7.5%.”

Coal continued for the sixth year as the fastest-growing fuel.

“Our data confirms that the world has enough proved reserves of oil, natural gas, and coal to meet the world’s needs for decades to come,” Hayward said. “The challenges the world faces in growing supplies to meet future demand are not below ground; they are above ground. They are human, not geological.”

Enterprise, TEPPCO reach merger agreement

Enterprise Products Partners LP and TEPPCO Partners LP have agreed to a major merger of US pipeline, storage, and gas processing systems.

The combined entity will retain the Enterprise Products Partners name. It will own more than 22,000 miles of NGL, oil product, and petrochemical pipelines; 20,000 miles of natural gas pipelines; and 5,000 miles of crude oil pipelines.

Combined storage capacities will be 200 million bbl of NGL, products, and crude oil and 27 bcf of natural gas. The partnership will own one of the largest NGL terminals in the US, on the Houston Ship Channel; 60 NGL, product, and petrochemical terminals throughout the US; and crude oil terminals on the Texas Gulf Coast.

The postmerger partnership will own interests in 17 fractionation plants with more than 600,000 b/d of net capacity, 25 gas processing plants with net capacity of about 9 bcfd, and 3 butane isomerization facilities with capacity of 116,000 b/d.

Enterprise and TEPPCO have entered into definitive agreements to enact the merger. The new partnership will have an enterprise value exceeding $26 billion.

TEPPCO and its general partner, Texas Eastern Products Pipeline Co. LLC, are to become subsidiaries of Enterprise.

Parties to the agreement agreed to settle lawsuits filed after Enterprise made its initial offer in March.

EU group prepares for possible Ukraine gas shortage

At a meeting scheduled for July 2, the European Union’s Gas Coordination Group is to prepare for the possibility of another gas shortage in case Russia again shuts down the flow of its gas through Ukraine to the EU.

Ukraine is still looking for a $4.2 billion loan to pay for Russian gas deliveries. About 80% of Russia’s gas supplies to Europe pass through Ukraine and accounts for one third of the EU’s gas imports.

The directive that established the Gas Coordination Group in 2006 includes a three-step approach in dealing with a supply crisis. The first calls for the industry to take measures to resolve the emergency. If that fails, national programs are activated. If those fail and 20% of gas imports are curtailed, the coordination group provides assistance to countries in difficulty.

The January crisis showed a more coordinated approach is needed at EU level, and the commission suggested emergency plans be activated automatically in the event of supply disruption. It suggested the commission should have the authority to force member states to provide gas from their strategic stocks. These new measures should be proposed to the council and parliament before the end of summer.

Industry Scoreboard

Exploration & DevelopmentQuick Takes

Norwegian parliament approves Goliat field plan

The Norwegian parliament has given the go ahead for Eni Norge AS to develop Goliat field in the Barents Sea with a circular floating production platform.

Sevan Marine ASA has designed the Sevan 1000 floating production, storage, and offloading vessel and has signed an engineering contract and a technology license with Eni (OGJ Online, Apr. 24, 2009). Production from the field, which lies in 400 m of water, is scheduled to start in fourth quarter 2013.

“Use of the circular FPSO makes it possible to utilize electricity supplied from shore combined with a gas turbine for power and heat on the offshore facility. This will result in significantly lower levels of [carbon dioxide] emissions,” said Eni.

Meanwhile, a consortium led by Aker Solutions AS pulled out of competition for the engineering, procurement, and construction contract for the Goliat FPSO.

Aker Solutions said Eni Norge would not prequalify the group for the field development.

Aker and its partners, Aibel and Samsung Heavy Industries, had suggested a floating production platform with production capacities of 100,000 b/d and 3.9 million cu m/day gas and storage capacity of 950,000 bbl.

The Sevan Marine Services circular floating production platform design calls for those production capacities and 1 million bbl of oil storage.

The field, which holds reserves of 180 million boe, is the first oil development in its area. Environmentalists are worried about its impact.

Total Goliat investments are estimated at 28 billion kroner ($4.4 billion) in 2008 money.

Goliat field, on Blocks 7122/7,8,9,10 and 7123/7, was discovered in 2000.

Eni is operator of Goliat with a 65% stake. StatoilHydro holds 35%.

StatoilHydro discovers oil in Titan prospect

StatoilHydro is considering tying in its discovery of 5.6-12.5 million boe of recoverable oil in the Tampen area of the Norwegian North Sea to its Visund project.

Exploration wells 34/8-13 A and 34/8-13 S, drilled to test Brent group targets, made the discovery on the Titan prospect directly east of northern Visund.

“Although it’s only a small find, the volumes proven could be very significant for realizing a Visund North development,” said Visund operations head Tom Karsten Gustavsen.

Visund field produces oil and gas from subsea wells tied to a floating production, storage, and quarters platform. North Visund is a separate subsea development about 10 km north of the platform.

While 13 A on the Titan prospect found a small oil column in Upper Jurassic sands, the underlying Brent group proved to be an aquifer. Well 13 S, drilled 2.7 km to the southeast, found oil in the Brent group.

The oil zones in the two wells are likely to be in communication, and both have been subject to extensive data gathering and coring, the company said.

Well 13 A reached a TVD of 3,108 m subsea and terminated in the Statfjord formation. Well 13 S reached a TVD of 3,258 m subsea and ended in the Hegre group.

StatoilHydro used the Scarabeo 5 semisubmersible rig to drill the wells in 381 m of water. The rig has moved to PL 199 for a workover of production well 6406/2-S-4 H.

Both wells have been plugged and abandoned.

Operator StatoilHydro has 59.06% of PL 120, where its partners are Petoro with 16.94%, ConocoPhillips 13%, and Total E&P Norge 11%.

Seychelles prepares for offshore licensing round

Seychelles Petroleum Co. (Seypec) completed an oil-slick mapping and interpretation project off Seychelles in partnership with Infoterra Ltd. to prepare for a licensing round later this year.

The companies have gathered more than 150 radar satellite scenes across 500,000 sq km—making it the largest slick-mapping project ever done off Seychelles.

The data will be used to identify mature source rocks and a petroleum system. “We will use this data to support the planning of seismic projects and subsequent geochemical programs,” said Patrick Joseph, Seypec exploration manager.

Infoterra ranked all oil slicks as probable natural seepage or manmade pollution and mapped the location and movement of all shipping visible in the area to give a more complete picture.

According to reports, the Seychelles will offer 70,000 sq km of offshore acreage in the licensing round.

One operating company in the nation is East African Exploration Ltd., which signed a production-sharing agreement last year with the government covering 15,000 sq km.

The two larger tranches, Area A (7,510 sq km) and Area B (6,808 sq km) lie in shallow water in the northern half of the Seychelles plateau. Area C (680 km) is in the south.

EAX is required to shoot 2,000 line-km of seismic and drill one well by October 2012, according to its work program.

Algeria launches new licensing round

After failing to generate interest in its December offering, Algeria launched a licensing round for 25 blocks it said have “high-potential petroleum resources.”

Energy and Mines Minister Chakib Khelil said Algeria would work with companies that have technology to handle unconventional gas, rather than those who want to swap reserves in other countries.

Khelil said, “It will be for companies with tight sands technology, so there will be some prequalification done in that area.”

Potential operators have selected blocks being offered, said Khelil. They are to submit bids by Dec. 20 and contracts would be signed Jan. 16. The blocks are in basins where previous discoveries were made by Repsol-YPF SA and StatoilHydro.

Algeria will make a technical presentation July 27 and will open data rooms for each project from Aug. 15 to Oct. 22.

Foreign oil companies didn’t show much interest under Algeria’s last bidding round for 11 licenses, complaining poor acreage was offered and of the impact of the financial crisis.

E.On Ruhrgas AG, BG Group PLC, Eni SPA, and OAO Gazprom filed successful applications for the December licensing round.

Drilling & ProductionQuick Takes

BLM signs decision record on Rocktober gas project

The US Bureau of Land Management’s Cody, Wyo., field manager signed a decision record on June 29 for seven proposed natural gas wells in the McCullough Peaks area east of Cody.

The action by Michael P. Stewart followed a 30-day review of a BLM environmental assessment (EA) of a proposal by Denver independent producer Bill Barrett Corp. for the wells and associated facilities in the Rocktober Natural Gas Unit.

The analysis determined that no significant long-term impacts would occur as a result of the project, BLM said. It also addressed issues raised during the EA’s public comment and review periods including impacts on wild horses, sage grouse, and other wildlife; visual intrusions, and air and water quality, BLM said. It received 55 comments on the proposed project.

One of the comments came from the Greater Yellowstone Coalition, an environmental organization based in Bozeman, Mont. It said that Bill Barrett already has drilled two wells on state land in the McCullough Peaks area. It asked BLM to delay its final decision on the company’s application until the federal agency’s new resource management plan for the area is completed.

It also urged BLM to require Bill Barrett to use closed-loop drilling on the project, which the group said “eliminates massive pits filled with contaminates that pose a threat to wildlife and groundwater.”

In an errata to the EA, BLM said that there is no reason to use a closed-loop system in drilling the Rocktober wells because reserve pits would be lined if required by BLM. “Standard drilling techniques (including isolating all water-bearing formations in the well bore with pipe and cement) will adequately protect water aquifers,” it maintained.

All groundwater resources in the area are 600-700 ft deep and there are no water wells near the project area, it continued. The nearest water wells are more than 2 miles away and in a hydraulically up-gradiant direction “and therefore have little to no risk from project operations,” the EA’s errata said.

It also said that the EA follows the existing resource management plan for the area, and that BLM is required to follow that RMP until a new one is signed.

Chevron begins injecting steam in PNZ pilot

Saudi Arabian Chevron initiated steam injection in its large-scale pilot steamflood project at Wafra field, an Eocene heavy-oil carbonate reservoir in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia.

Chevron said the $340 million pilot is the final test phase for steamflooding the reservoir, and it expects the pilot to lead to full-field steamflooding, which would make the project the world’s first commercial conventional steamflood in a carbonate reservoir.

“Full-field deployment of steamflood technology in the PNZ would significantly increase recovery of crude oil reserves, confirm the technology’s potential applicability in other carbonate oil fields and build on Chevron’s steamflood capabilities that date back 5 decades,” said George Kirkland, executive vice-president, Chevron Global Upstream & Gas.

The large-scale pilot is the third in a series of staged tests for validating the feasibility of steamflooding at Wafra. Previous tests included the small-scale test completed in 2008 and simple steam stimulation in the late 1990s.

Steamflooding involves injecting steam into heavy-oil reservoirs to heat the crude oil underground, reducing its viscosity and allowing its extraction through wells. Chevron has employed steamflooding to produce heavy oil from sandstone reservoirs at Kern River, Calif. for more than 40 years and at Duri in Sumatra, Indonesia, for 25 years.

Saudi Arabian Chevron operates on behalf of Saudi Arabia that has a 50% interest in the onshore PNZ petroleum resources. Saudi recently amended and extended Chevron’s operating agreement until February 2039.

The company’s operations in the PNZ include four fields: Wafra, South Umm Gudair, South Fuwaris, and Humma. The fields produce mainly heavy crude from 10 reservoirs. In 2004, onshore PNZ produced its 3 billionth bbl of oil, according to Chevron.

ProcessingQuick Takes

Bidding resumes on Yanbu export refinery

Bidding will resume on the second of two major refineries in Saudi Arabia for which work was delayed late last year.

Saudi Aramco and ConocoPhillips have reinstated preconstruction work on the 400,000-b/d refinery they plan at Yanbu, Saudi Arabia.

The full-conversion export refinery will process Arabian heavy crude. Willie C. Chiang, ConocoPhillips senior vice-president, refining, marketing, and transportation, said bidding had resumed “now that markets are more favorable.”

Work had been suspended during a review last year by Aramco of a several major upstream and downstream projects (OGJ, Nov. 17, 2008, p. 29).

Prequalified local and international contractors have received invitations to bid for early work and major Yanbu packages including a coker unit, crude facility, gasoline unit, hydrocracker, tank farm, offsite pipelines, high-voltage electrical facilities, and other infrastructure.

Earlier, the Saudi Aramco Total Refining Petrochemical Co. joint venture announced completion of an award plan for bids on the 400,000-b/d refinery it plans in Jubail, Saudi Arabia (OGJ, June 22, 2009, Newsletter).

Borouge to expand Abu Dhabi olefins complex

Borouge, a joint venture of Borealis AS of Vienna and Abu Dhabi National Oil Co., plans to make its already expanding ethane-cracking complex in Ruwais, Abu Dhabi, the world’s largest.

It has let a $1.075 billion contract to Linde Group, Munich, for a third ethane cracker at Ruwais with capacity of 1.5 million tonnes/year (tpy).

The project will increase total polyolefins capacity of the complex to 4.5 million tpy by the end of 2013. In addition to the ethane cracker, it includes construction of second-generation polypropylene and polyethylene units based on Borealis’s Borstar technology, a low-density polyethylene unit, and a butene unit, plus offsite utilities and marine facilities.

The new ethane cracker will add to an existing 600,000 tpy ethane cracker and a 1.5 million tpy unit under construction.

The world’s largest olefins complex in terms of ethylene capacity now is Nova Chemicals Corp.’s 2.8 million tpy facility at Joffre, Alta.

The cracker under construction at Ruwais is part of a project to increase Borouge polyolefins capacity to 2 million tpy by mid-2010. Net ethylene output from that plant will be 600,000 tpy, according to Chemical Market Associates Inc., Houston, because some of the product will be dimerized to butene, and butene and more ethylene will be metathesized to propylene (OGJ, Aug. 25, 2008, p. 48).

In that project, Borouge is adding a 752,000-tpy olefins conversion unit, a 540,000-tpy polyethylene plant, and two 400,000-tpy polypropylene plants.

Total resolves Lindsey refinery dispute

Total SA has settled a dispute with hundreds of contract workers that were fired from constructing a hydrodesulfurization unit (HDS) at its 200,000 b/d Lindsey refinery in the UK.

The employees will vote on the measures to be reinstated to work on June 29, unions said. They were fired after embarking on unofficial strikes about 51 planned redundancies by the sub contractor while another employer on the site was hiring people.

Their actions triggered sympathy strikes at other construction and energy sites around the country.

The HDS unit is already 6 months behind schedule and €100 million over budget. It is meant to be ready before the end of the year, but this is the second strike this year that has derailed its progress. Total said it was pleased that “a positive conclusion” had been reached. “We expect this means that the contractors will be able to get back to work as soon as possible and get the project completed on time and with no further disruption or additional costs.”

TransportationQuick Takes

Gorgon-Jansz gas gets interim marketing nod

The three joint venturers in the Gorgon-Jansz gas and LNG project in Western Australia have been given conditional interim authorization from the Australian Competition and Consumer Commission (ACCC) to market gas in the state.

The approval enables Chevron Corp., ExxonMobil Corp., and Royal Dutch Shell PLC to talk to potential customers and obtain information relevant to the project’s final investment decision expected later this year.

ACCC Chairman Graeme Samuel said authorization was unlikely to result in irreversible changes to the market because any gas sales agreements reached during this period would be conditional on final authorization.

The move has disappointed the so-called DomGas Alliance, which represents Western Australia’s largest customers and which told the ACCC in early June that it opposed the request for joint marketing.

Alliance Chairman Stuart Hohnen pointed out that vigorous gas competition was important for businesses and households. He said a lack of competition had resulted in gas prices recently four or five times those in eastern Australia on a delivered basis.

The ACC has addressed this issue by only allowing the interim authorization to take place after the Gorgon partners had their ring-fencing arrangements independently audited, and any changes required to make them effective had been implemented.

The commission will make a draft determination by September following a public comment period.

The Gorgon-Jansz project includes a three-train LNG plant with total capacity of 15 million tonnes/year alongside a domestic gas plant capable of supplying 300 terajoules/day of gas to the Western Australian grid. Gas is scheduled to come on stream in 2014.

Chevron is operator with 50%. ExxonMobil and Shell have 25% each.

Qatar, Poland sign 20-year LNG contract

Qatar Liquefied Gas Co. III (Qatargas) has signed a 20-year agreement to sell Poland 1 million tonnes/year of LNG.

Poland’s Treasury Ministry said value of the contract is about $550 million/year.

Poland will receive the LNG at a terminal under construction at Swinoujscie, scheduled for completion in 2015.

Qatargas expects its LNG production to rise to 42 million tonnes/year by the end of the decade from 10 million tonnes/year in 2008.

Correction

A recent story about a ramp-up in production from BP PLC’s Thunder Horse project incorrectly attributed Thunder Horse as solely accounting for 1 of every 6 bbl of oil produced in the US (OGJ Online, Apr. 17, 2009). The statement should have read: “Offshore deepwater developments like Thunder Horse now account for 1 of every 6 bbl of oil produced in the US.”