OGJ Newsletter

Oct. 1, 2007
General Interest - Quick Takes

Senate committee begins energy bill discussions

After weeks of silence regarding a possible conference to reconcile differences between comprehensive energy bills passed by the US House and Senate earlier this year, the Senate Energy and Natural Resources Committee’s staff began bicameral discussions about the contents of the measures.

Senate Energy and Natural Resources Committee Chairman Jeff Bingaman (D-NM), with the blessing of majority leader Harry M. Reid (D-Nev.), asked the committee’s staff to host the discussions, a committee spokesman said on Sept. 20. “These meetings are not to decide the fate of any provisions, but to allow Senate staff to become familiar with the background of the House bill provisions, and vice versa,” he said.

The discussions were scheduled to begin with Titles IV and IX of the House’s 1,003-page energy bill and include related sections from the Senate’s legislation. Talks would continue on Sept. 21 but recess at midday for Yom Kippur and resume on Sept. 24, with a goal of covering all the material in both bills by the end of that week, the committee spokesman said.

Suriname, Guyana maritime dispute settled

The International Tribunal for the Law of the Sea has settled a 6-year maritime boundary dispute between Suriname and Guyana, giving each country access to an offshore basin believed to be rich in oil and natural gas.

“The boundary for the most part follows the equidistance line between Guyana and Suriname,” the Hamburg, Germany-based tribunal said. Guyana and Suriname lie side-by-side on the northeastern coast of South America, between Brazil and Venezuela.

Suriname had asserted a boundary further to the north and west, while Guyana had relied on the so-called equidistance line method of determining the boundary, which placed it farther to the south and east.

While the exact position of the ocean boundary between them had long been a subject of disagreement, it did not result in conflict until exploratory tests revealed potentially huge deposits of hydrocarbons beneath the sea bed.

In 2000 Suriname enforced its disputed claim by sending two gunboats to force CGX Energy Inc. to withdraw its drilling rig from the disputed area before it could drill under a license granted by Guyana.

According to the terms of the tribunal’s ruling, Guyana gained sovereignty over 12,837 sq miles of the coastal waters, while Suriname received 6,900 sq miles.

Both Guyana and Suriname agreed to abide by the tribunal’s ruling, and as a result both nations can also now proceed in further exploration of their respective ocean territories.

The US Geological Survey estimates that the coastal area off the two countries, referred to as the Guyana-Suriname basin, could hold reserves of 15 billion bbl of oil and 42 tcf of gas.

Paradigm to pay $1 million to settle FCPA issues

Paradigm BV, an exploration and production software supplier based in Amsterdam, said Sept. 24 it will pay $1 million as part of a settlement with the US Department of Justice for possible violations of the Foreign Corrupt Practices Act.

Paradigm said DOJ did not levy civil or criminal charges in the matter involving improper payments to government officials of various countries during 2002-07, which Paradigm voluntarily disclosed. No one in the company’s current senior management was involved in the payments, it added.

Paradigm said it discovered the payments during due diligence for an anticipated initial public offering. The company said it immediately retained the law firm Skadden, Arps, Slate, Meagher, & Flom LLP to conduct a multicountry investigation and make the voluntary disclosure.

As part of the agreement, Paradigm said it also agreed to implement and enhance internal controls, retain outside compliance counsel, and cooperate fully with DOJ.

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Exploration & Development - Quick Takes

Colombia awards nine offshore blocks

Colombia’s National Hydrocarbons Agency has awarded 9 of 13 offshore blocks in the Caribbean Sea that had been released for tendering.

State-owned Ecopetrol SA will participate in joint ventures with foreign partners in six of the concessions and has two others alone. BP PLC won the sole right to develop Block 5. Altogether, Ecopetrol won Blocks 11 and 12 outright, and will partner with Brazil’s Petroleo Brasileiro SA (Petrobras), India’s Oil & Natural Gas Corp. (ONGC), Hess Corp., and BP in six other blocks.

The companies have agreed to commit $5.3-5.8 million in exploration funding in return for 10-year oil and gas exploration rights, along with production rights for the lifetime of their fields.

The blocks awarded, the successful bidders, and the amounts of exploration investment committed, in millions of dollars, are as follows: 4, Petrobras, Ecopetrol, and BP, 5.5; 5, BP, 5.8; 6, Petrobras, Ecopetrol, and Hess, 5.3; 7, Petrobras, Ecopetrol, and Hess, 5.3; 8, Petrobras, Ecopetrol, and ONGC, 5.3; 9, Ecopetrol, 5.3; 10, Ecopetrol and ONGC, 5.3; 11, Ecopetrol, 5.3; and 12, Ecopetrol, 5.3.

Blocks 1, 2, 3, and 13 received no bids.

Petrobras reports success with Brazil fields

Petroleo Brasileiro SA (Petrobras) has tested 2,900 b/d of 27° gravity oil from its exploration well in deepwater Carioca field on Block BM-S-9 in the Santos basin off Brazil. The well also tested 57,000 cu m/day of gas. Both results were constrained by test equipment.

Carioca lies in 2,140 m of water 273 km off southern Rio de Janeiro state. It is near the Tupi discovery on Block BM-S-11, announced last October (OGJ, Nov. 20, 2006, p. 43).

The partners, Petrobras, Repsol-YPF Brazil SA, and BG Group, say the find is a significant one. For BG, this is the third well to find hydrocarbons in the new Santos basin presalt play, which has enhanced the company’s confidence in the highly prospective area.

Petrobras has a 45% stake, Repsol-YPF 25%, and BG 25%.

Additionally, Petrobras has informed Brazil’s National Petroleum Agency that the Xerelete heavy oil discovery in ultradeep water off Brazil is commercial. It tested flows as high as 2,500 b/d.

Xerelete-formerly known as Curió-was previously operated by Total SA, which made the discovery in 2001 over Blocks BC-2 and BMC-14 in the prolific Campos basin.

The 1-EPB-1-RJS exploration well, drilled in water 2,483 m deep, hit sandy, 17.5° gravity oil-bearing reservoirs at a depth of 3,478 m. It is Brazil’s deepest subsea discovery to date.

Xerelete contains relatively heavy oil of 17-20° gravity. Preliminary geological studies suggest that Xerelete may extend for more than 26 sq km, holding an estimated in-place volume of some 1.4 billion boe. “Additional studies are being carried out to define this new field’s production development project,” Petrobras said.

Petrobras operates both blocks. It is working with Total on Block BC-2. On Block BMC-14, Petrobras and Total each hold a 50% stake.

Agiba tests oil well on Egypt’s Meleiha block

Agiba Petroleum, operator of the Meleiha block in Egypt’s Western Desert, has tested 1,000 b/d of dry crude oil from its exploration well in the Gawaher structure on the block. Production is expected to increase to 1,500 b/d.

“Appraisal of drilling results, adjustment of the field reserves, further drilling-out, and development of field infrastructure is presently going on,” said Lukoil Overseas, a partner in the project.

More than 17 million tonnes of oil has been produced on the block during the last 30 years. The operating well stock is 141 units, 12 of which were drilled since the beginning of this year and are producing a combined 3,200 b/d.

In April, the Egyptian parliament ratified the extension of the concession agreement on Meleiha Block to 2024 (OGJ Online, Apr. 13, 2007).

Agiba Petroleum is a joint venture of Egyptian General Petroleum Corp., Eni subsidiary IEOC Production, and International Finance Co. Production-sharing contract interests are held by IEOC 56%, Lukoil 24%, and IFC 20%.

Drilling & Production - Quick Takes

Woodside brings Thylacine gas project on stream

Woodside Petroleum Ltd. has brought on stream its Thylacine gas development in the Otway basin off western Victoria after the project’s scheduled start-up had fallen behind by more than a year (OGJ Online, Oct. 20, 2006).

Production from Thylacine field, which lies in Tasmanian waters, is being piped ashore to a processing plant in Victoria. Geographe field, adjacent to Thylacine in Victorian waters, will be connected to the main offshore pipeline during a later development phase.

Thylacine will supply 980 bcf of gas to Victoria over an estimated 10 years. There also will be 100,000 tonnes of liquid petroleum gas and about 800,000 bbl/year of condensate. These products will be the main revenue earners for the project.

The commissioning phase is complete, and gas production will be increased to scheduled levels over the coming weeks.

Sales gas is transferred to TruEnergy’s adjacent Iona gas plant to be piped onward to Melbourne and Adelaide. Condensate will be trucked to Shell Australia’s refinery in Geelong, 50 km west of Melbourne.

Delays were concentrated in the onshore gas plant construction, which also inflated the project’s Phase 1 cost by about 20% to almost $1 billion (Aus.).

This puts into question the original total budget for the project of $1.1 billion, as the Phase 2 connection of Geographe has yet to begin.

Santos brings Oyang field off Java on line

Santos Ltd.-operated Oyang oil and gas field off East Java has been brought on stream. Production rates are expected to stabilize at 8,000-10,000 b/d over the next few weeks.

Adelaide-based Santos holds 45% interest, while Cue Energy Resources, Melbourne, has 15%, and Singapore Petroleum, 40%.

Oil is being produced via a wellhead platform that houses five oil wells and two gas wells. Oil is processed on the Sea Good 101 production barge and piped to the Shanghai storage and offtake vessel.

Front-end engineering and design studies to develop Oyang gas reserves are now well under way, and a final investment decision is expected before yearend. First gas production is anticipated during first-half 2009.

Gas will be piped via a 55 km undersea pipeline to an onshore processing facility to be located adjacent to the existing Grati power station in East Java.

PT Indonesia Power will purchase the gas.

Santos said its nearby Wortel gas field, discovered in 2006 about 7 km west of Oyang, is likely to be incorporated into the gas development program, but that is still subject to further field appraisal, which is planned for first half 2008.

Talisman starts production from Duart oil field

Talisman Energy (UK) Ltd. has begun production from Duart oil field on Block 14/20b in the North Sea. The field lies 5 miles west of the Tartan platform and 116 miles northeast of Aberdeen. Initial production, expected to exceed 6,000 b/d, was brought on 2 months ahead of schedule.

Duart field, discovered in 1988, was developed with a single well tied back to the Tartan platform. Duart oil will be exported via the Flotta system, together with other Tartan area production.

Prospective reserves of 6 million bbl are assigned to the northern section of the field.

Duart is an integral part of Talisman’s plans to prolong the life of both the Tartan platform and the Flotta export system.

AGR to drill nine wells in UK North Sea

AGR Group will drill nine wells for various clients in the UK North Sea under contracts valued at $202.2 million.

AGR will use the Sedco 704 semisubmersible for an eight-well multiclient program, including operators Serica Energy PLC, Dana Petroleum PLC, Fairfield Energy Ltd., Century Exploration Ltd., and OMV AG. These wells will take a year to complete. Sterling Resources has contracted its Ensco 85 rig for a single well on Block 42/13 in the UK southern North Sea (OGJ Online, Sept. 24, 2007).

Sedco 704 will soon spud its first well following major upgrades to its drilling equipment and accommodation modules. The rig can operate in harsh environments and in as much as 1,200 ft of water, using an 18¾-in., 15,000 psi blowout preventer and a 21-in. OD marine drilling riser.

With the arrival of the Sedco 704 and Ensco 85 jack ups, AGR is now operating four drilling units on the UK continental shelf.

This year AGR plans to drill more than 55 wells in northwestern Europe, North Africa, West Africa, Middle East, the US, and Asia-Pacific.

Rigs under management this year include Stena Clyde, Wilcraft, Sedco 704, Bredford Dolphin, Byford Dolphin, Transocean Prospect, Maersk Giant, Ensco 80, Ensco 85, Ensco 92, Ensco 100, Ocean Spur, and Noble George Sauvagneau.

Processing - Quick Takes

Motiva Port Arthur refinery expansion to proceed

Motiva Enterprises LLC, Houston, said a final investment decision has been made that allows the company to proceed with a 325,000 b/d expansion of its 285,000 b/cd refinery in Port Arthur, Tex.

The expansion-essentially adding the capacity equivalent to a new refinery-will increase the refinery’s oil throughput capacity to 600,000 b/d, making it the largest refinery in the US.

The additional production capacity is expected to be online in 2010.

Motiva selected Bechtel Jacobs joint venture as the project’s engineering, procurement, and construction contractor. Construction is scheduled to begin this year.

Rajasthan refinery no deterrent to Cairn’s plans

Cairn India and India’s state-owned Oil & Natural Gas Corp. (ONGC), partners in Barmer field in Rajasthan, said they will not “go slow” in constructing a preheated pipeline to carry the waxy crude from the field.

This is despite the Rajasthan government’s saying it would build a refinery to process the oil, making the $750-million pipeline superfluous.

“The pipeline is the most feasible option and is likely to [be built] before the start of crude oil production,” said a senior official of ONGC, Cairn’s 30% partner in the oilfield.

He said building a refinery with a capacity of about 7.5 million tonnes/year “would take around 40 months, whereas work on the pipeline is expected to take just 18 months,” he said.

A Cairn India executive revealed that 83% of the pipeline engineering design work has been completed and that tenders for construction would open soon.

The Scottish explorer’s oil discovery in Rajasthan is the largest in the country since ONGC struck oil in Bombay High in 1972. Barmer field is expected to produce 150,000 b/d during its 4-year peak production period.

Although a refinery in Rajasthan would mean another buyer for the company’s crude oil, “we know the economics of the refinery are dubious,” the Cairn executive said.

ONGC agreed: “There is simply not enough crude oil in the field to justify a new refinery. The state consumes only 5 million tonnes/year of oil products. With new refineries coming up in Bina [in Madhya Pradesh] and Bhatinda [Punjab], there will be no market for the Rajasthan refinery.

The price of the oil also must be resolved. Its poor quality, Cairn says, likely will garner the companies about 10% less than the Brent benchmark. Refiners, however, hope for a discount of more than 20%. “The contract allows pricing to follow the international prices of similar oil,” Cairn said.

The pricing will determine how cost-effective a preheated pipeline would be. If Cairn does not get a good price, the gains may not justify the cost of the pipeline.

A buyer has yet to be finalized, but Cairn executive said talks were under way “with almost all refineries. The Bhatinda and Bina refineries are keen on taking our crude oil.”

ONGC said a realistic date for production to begin is yearend 2009.

ExxonMobil to expand Rotterdam aromatics plant

ExxonMobil Chemical Co. plans to expand its Rotterdam aromatics plant in Botlek, the Netherlands, making it the company’s largest paraxylene production facility.

The expansion will increase the facility’s production capacity by 25% for paraxylene and by 20% for benzene.

Construction is scheduled to begin this year.

The project involves building a heat-exchanger, reactor, and distillation column.

ExxonMobil will use its PxMax technology to produce paraxylene and benzene. The PxMax process improves selectivity, generates less waste, and reduces energy requirements in comparison to existing technologies.

The expansion project will be owned and operated by ExxonMobil Chemical Holland BV.

Transportation - Quick Takes

Singapore plans Jurong Island LNG terminal

Singapore plans to build a $1 billion LNG terminal and regasification plant on a 30-ha site in southwest Jurong Island to diversify its natural gas imports.

Singapore Power subsidiary PowerGas, designated as majority owner and operator of the facility, expects to begin construction in 2009 and to have the plant operational by early 2012.

In early September, Singapore Minister of State for Trade and Industry S. Iswaran said at the LNG Supplies for Asian Markets conference that detailed engineering and construction should start immediately. The project was approved in August 2006.

Singapore, which relies on gas transported from neighboring Indonesia and Malaysia, is trying to diversify its sources of supply. Supplier Indonesia, in particular, has less gas to export as it seeks to meet domestic demand growth (OGJ Online, Mar. 1, 2007).

Iswaran said initial demand is expected to be 1 million tonnes/year in 2012 when the plant starts operations. It will take 4-5 years for the contracted LNG quantity to reach 3 million tonnes/year, he said.

PowerGas, currently in charge of the national gas pipeline grid, can ensure that the LNG terminal is efficiently integrated with the system and can help manage periodic gas demand and supply imbalances by adjusting supply from the terminal.

“But we have left the door wide open for other parties, both local and international, to join in,” Iswaran said, suggesting that other players could partner with PowerGas as minority stakeholders.

Singapore also has launched a request for proposals from interested parties to bid on becoming the initial sole importer of LNG into the plant. The importer-consortium (or aggregator) will import an initial 3 million tonnes/year of LNG into the country.

Singapore’s Energy Market Authority will select and appoint the aggregator from a short list of candidates by second quarter 2008.

Russia approves gas production, delivery to Asia

Russia’s Industry and Energy Ministry has approved the Eastern Gas Program leading to the creation of a unified system for East Siberia’s natural gas production and delivery to China and other areas in the Asia-Pacific.

The program will create four gas production centers in Sakhalin, Yakutia (Chayanda field), Irkutsk, and Krasnoyarsk territories, according to Anatoly Yanovsky, chief of the ministry’s energy policy department in a Sept. 7 announcement.

Ministry officials said “absolute priority” will be given to meeting domestic needs, while the dates of the fields’ development and respective exports will depend on the outcome of commercial talks between the companies involved.

Industry analysts said approval of the ministry’s program guidelines essentially ratifies OAO Gazprom’s plans for the region, including construction of LNG facilities on Sakhalin Island and direction of gas supplies from the ExxonMobil Corp.-led Sakhalin-1 project to the domestic market.

Turkmen gas may flow to Europe, bypassing Russia

Turkmenistan President Gurbanguli Berdymukhamedov said his country is ready to bypass Russia and begin selling some of its natural gas to Europe.

After meeting Sept. 19 with Austrian Economic Minister Martin Bartenstein, Berdymukhamedov said his country, “having multiple vectors in its energy policy and creating alternative export routes, including in the southern direction through the Caspian Sea, is prepared to deliver natural gas to European countries.”

Turkmenistan’s gas exports currently pass through pipelines operated by Russia’s state-run OAO Gazprom, but Berdymukhamedov suggested that a new pipeline could be built from Turkmen gas fields to Azerbaijan.

Michael Baker wins federal Alaska gas line contract

Michael Baker Jr. Inc. was the successful bidder for a contract to assist the federal coordinator’s office in the effort to construct a natural gas pipeline from Alaska to the Lower 48 states.

The firm has extensive Arctic oil and gas pipeline expertise, said Drue Pearce, federal coordinator for Alaska natural gas transportation projects, in announcing the award Sept. 12.

Michael Baker will help the federal coordinator’s office establish a local presence in Alaska; develop an information management system to allow federal, state, and Canadian agencies to share data where appropriate; and help the federal coordinator’s office incorporate lessons learned from construction of the Trans-Alaska Pipeline System and the former federal inspector’s office to develop a strategy for constructing the gas pipeline, she said.