General Interest — Quick Takes

Dutch fund charged with US futures control

The US Commodity Futures Trading Commission (CFTC) on July 24 charged a global proprietary trading fund based in the Netherlands, two of its subsidiaries, and three employees with manipulating and attempting to manipulate US petroleum commodities markets.

Optiver Holding BV; subsidiaries Optiver US LLC and Optiver VOF; and employees Christopher Dowson, Optiver US’s head trader; Randal Meijer, trading head and supervisor at Optiver US and Optiver VOF; and Bastiaan van Kempen, Optiver US’s chief executive, were named in the CFTC’s civil complaint filed in US District Court for New York’s southern district.

They were charged with allegedly trying 19 times to manipulate light, sweet crude, New York Harbor heating oil, and New York Harbor gasoline futures contracts, which trade on the New York Mercantile Exchange.

The attempts were made during 11 days in March 2007, CFTC said. In at least five of the attempts, the defendants successfully manipulated energy futures contracts and created artificial prices, the federal commodities trading regulator continued. Futures prices were forced lower in three instances and higher in two instances, it said.

The scheme produced about a $1 million profit for the defendants, the complaint said. It said the defendants allegedly used a manipulative scheme commonly known as “banging” or “marking” the close, which involves acquiring a substantial position leading up to the closing period followed by offsetting the position before trading closes.

The complaint also charges Optiver and Van Kempen with concealing the scheme and making false statements in response to a NYMEX inquiry, CFTC said.

“These charges go to the heart of the CFTC’s core mission of detecting and rooting out illegal manipulation of the markets,” said CFTC Acting Chairman Walter L. Lukken. “Although this alleged energy trading scheme lasted only several days in March 2007, even short-term distortions of prices will not be tolerated by the commission.”

The UK Financial Services Authority and NYMEX assisted CFTC in its investigation, he added.

Chavez: IOCs must transfer technology with pacts

Venezuelan President Hugo Chavez, renewing concerns about an old theme, said his country will stop doing business with international oil companies (IOCs) that fail to transfer technology as part of their contracts.

“The order I’m giving is the following: Any foreign company that doesn’t transfer technology, well, their contracts will be canceled. We’ll get others that want to be here,” Chavez said on Venezuelan national television.

The issue of technology transfer is a sore one with the Venezuelan president as well as with IOCs themselves.

Last October ExxonMobil Corp. and ConocoPhillips, under pressure from the government, withdrew from Venezuela, leaving behind their right to produce oil as well as technology and infrastructure that could be used by their competitors.

Technology for advanced well drilling, upgrading oil quality, and prevention of accidents could fall into the hands of companies, such as state-owned Petroleos de Venezuela SA (PDVSA), that do not have the technical expertise to extract reserves with the same efficiency as the two US firms.

The future remains unclear as to the status and use of the left-behind technology, but it could prompt a legal challenge from the two companies.

Earlier in 2007, Chavez blamed former directors of PDVSA for allowing transnational companies to extract oil from the country without investing in new technology.

“The transnational companies did not uphold their agreements. They extracted a billion barrels of oil without investing in technology to produce heavy crude,” Chavez said in his weekly Alo Presidente talk show.

Chavez said the former PDVSA directors who signed agreements with transnational companies during the period between 1958 and Chavez’s first election in 1998 should be taken to court.

“It was authorized robbery,” Chavez said.

Neptune TLP resumes full oil production

Full oil production has been restored on the Neptune tension leg platform in the deepwater Gulf of Mexico, BHP Billiton Ltd. said.

BHP and its partners recently completed remediation work to strengthen components inside the hull’s pontoons (OGJ, July 14, 2008, Newsletter).

Production began July 6. As of July 25, Neptune had five of six wells on line, and its oil production was at full design capacity of 50,000 b/d.

Natural gas production continues to ramp up to its design capacity of 50 MMcfd of gas.

The TLP stands in 4,250 ft of water on Green Canyon Block 613, which is 120 miles off Louisiana. Field development includes six subsea wells. More development wells are expected to be drilled after interpretation of seismic data, being obtained this year.

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Exploration & Development — Quick Takes

Sonangol OKs developments on Block 31

Angola’s position as Africa’s leading oil exporter is set to rise as new offshore deepwater discoveries on Block 31 are brought on stream by 2011.

Angola’s state oil company Sonangol has given operator BP Exploration (Angola) Ltd. and its partners the nod to develop Pluto, Saturn, Venus, and Mars (PSVM) fields, which lie in the northeast part of the block.

Development is expected to start this year and oil production is expected to peak to 150,000 b/d by 2012. The fields lie in 2,000 m of water and are 400 km northwest of Luanda.

The PSVM field development will comprise a converted-hull floating, production, storage, and offloading vessel with 1.6 million bbl of storage capacity; 48 production, gas, and water-injection wells plus infill wells; 15 manifolds and associated subsea equipment; 170 km of flowlines; and 95 km of control umbilicals.

Sonangol’s approval is key for BP’s production profile into the next decade and beyond. Andy Inglis, chief executive of BP exploration and production, said, “It demonstrates the scale of the resource base in Block 31.”

So far the consortium has discovered 15 fields on the acreage to date and it will develop the others in a similar manner to the PSVM group of fields. The partners have begun to plan the second development in the southeast part of the block. They are also ready to award major contracts for the first phase once it has been sanctioned.

BP holds a 26.67% interest in Block 31. Partners are Esso Exploration & Production Angola (Block 31) Ltd. 25%, Sonangol EP 20%, Statoil Angola AS 13.33%, Marathon International Petroleum Angola Block 31 Ltd. 10%, and TEPA (Block 31) Ltd. with 5%.

Santos JV makes gas find with Netherby well

Santos Ltd.’s offshore Otway basin joint venture, which includes Australian Worldwide Exploration Ltd. (AWE) of Sydney and Japan’s Mitsui E&P Australia Ltd., has discovered 22 m of natural gas pay in primary reservoir target sands with its Netherby-1 wildcat drilled on permit Vic/P44 off Victoria.

The well, drilled using the Ocean Patriot semisubmersible rig to a total depth of 1,870 m, will now be assessed with wireline logs and a pressure-testing program.

Netherby is the second of three planned appraisal and development wells in this sector of the permit in which it is hoped to add reserves to the planned Henry field gas development as an adjunct to the existing Casino field production facilities.

Netherby-1 lies 4 km north of Henry. If the coming tests are successful, Santos plans an immediate sidetrack well to fully determine the reserves before moving the rig to the planned Henry-2 appraisal.

Operator Santos, Adelaide, has 50% interest in the project with AWE and Mitsui each having 25%.

In related news, Santos has appointed acting Chief Executive Officer David Knox as permanent chief executive of the company (OGJ Online, July 29, 2008).

Coogee behind with Montara development

Coogee Resources Ltd., Perth, is about 4 months behind schedule with its Montara oil development project in the Timor Sea. The project is now expected to come on stream by yearend.

One reason behind the delay, the company reported, is a labor shortage in Singapore, where the project’s floating production, storage, and offloading vessel is being converted at Jurong Shipyard.

However China’s Chiwan Schenzen Engineering had delivered the wellhead platform jacket on time and budget, and Clough Thailand is currently loading out the topsides.

Phase 1 of the Montara development includes production from four wells: two on Skua field (previously produced by BHP Petroleum, but abandoned in 1997) and one well each in Swift and Swallow fields. Phase 2, to be completed in 2009, includes two wells at Montara field itself and one more at Swift.

In addition, Coogee has completed feasibility studies into the potential commercialization of the smaller gas fields surrounding Montara, Jabiru, and Challis, and expects preliminary front-end engineering and design work to begin into on methanol production option during the third quarter. FEED itself is planned for 2009.

The company also is considering CNG and LNG options for these fields with potential partners.

Drilling & Production — Quick Takes

BHP gets funding for Turrum development

Melbourne-based BHP Billiton Pty. Ltd. has given the green light to development of Turrum oil and gas field, which lies in the Bass Strait production area off southeast Victoria.

BHP holds a 50% share in the project, which is operated by fellow 50% interest-holder ExxonMobil Corp. BHP has now approved funding for its share of the $1.25 billion full field development.

Production will be channeled through the partnership’s existing Gippsland facilities, which comprise offshore pipelines extending to the onshore production facilities at Longford.

BHP says the new facilities for Turrum will consist of a new platform, designated Marlin B, which will be linked by a bridge to the existing Marlin A platform. Since it is one of the original steel structures in the Bass Strait, the Marlin A platform will require an upgrade to accommodate the bridge as well as new equipment.

Turrum is scheduled to come on stream in 2011. For the first 4 years the oil and condensate will be stripped from the production stream and the gas reinjected into the reservoir. Commercial gas sales are expected to begin in 2015 at a rate of 200 MMcfd of gas.

Turrum, which was discovered in the 1970s, lies 42 km offshore in 60 m of water. Reserves are estimated to be 1 tcf of gas and 110 million bbl of oil and condensate.

ExxonMobil says the field will be a key contributor to the estimated 7 tcf of remaining known gas reserves in the Bass Strait—a figure the company says will sustain gas production from its producing area for another 30 years.

Agip lets contract for Oyo field off Nigeria

Agip Exploration Ltd. has let a €75 million turnkey contract to Technip SA to design and produce the subsea system for Oyo oil field on Block OML 120/121 off Nigeria.

Technip’s contract covers the engineering, fabrication, and installation of close to 20 km of flexible production, water injection, and gas injection flowlines and risers. It will also install 15 km of umbilicals supplied by Agip.

“The offshore installation is scheduled for the summer of 2009 and will be carried out by the Constructor, one of the Technip’s pipelay and construction vessels,” Technip said.

Oyo, which lies in 410 m of water, is expected to start production in 2009 and will produce 29,000 boe/d at its peak.

Gupco starts production from Taurt gas field

Gulf of Suez Petroleum Co. (Gupco) has begun natural gas production from Taurt field on the Ras El Bar concession off Egypt.

The offshore field is a subsea development and includes two subsea wells, a 70-km pipeline, and control umbilical tieback to upgrading facilities at the existing West Harbor processing plant.

Taurt lies 70 km northeast of Port Said in the West Nile Delta. Gas production started in July and will be used to supply the Damietta LNG plant.

Gupco is a joint venture of BP PLC, Egyptian General Petroleum Corp., and Eni SPA affiliate International Egyptian Oil Co. (IEOC). Taurt is BP’s first subsea development in Egypt.

The parties to Ras El Bar Offshore Concession agreement are BP Egypt (operator 50%) and IEOC (50%).

IOCs can begin drilling in Chile, minister says

Chilean Mining Minister Santiago Gonzales said international oil companies (IOCs) that won bids to explore for oil and natural gas in the southernmost regions of Chile can begin drilling in August.

“The comptroller general approved the operating contracts so companies can begin drilling,” Gonzalez said. In May, Chile signed contracts with four IOCs for exploration of eight blocks in the southern Magallanes region (OGJ, May 12, 2008, Newsletter).

As part of that bidding round, Chile’s mining ministry July 15 awarded the Otway block in the Magallanes region to a consortium of Wintershall, GeoPark Holdings Ltd., and Methanex Corp., collectively WGM.

The award was made to WGM after Total SA, which last year won the Otway block in the round, inexplicably did not sign the special operating contract for the block in May.

The WGM consortium, which plans to invest $30.49 million on the Otway block, said it will acquire 330 line-km of 2D seismic data, 470 sq km of 3D seismic data, and will drill seven exploratory wells.

For its part, Chile’s state-run oil company Empresa Nacional del Petroleo (Enap) said it plans to invest $300 million. Enap holds a 50% stake in the Coiron, Caupolican, and Lenga blocks in the Magallanes region.

Two weeks ago, GeoPark discovered an oil field on Chile’s Fell block following drilling and testing at its Aonikenk 1 exploration well (OGJ Online, July 16, 2008).

Processing — Quick Takes

China’s NDRC approves biodiesel pilot projects

China’s National Development and Reform Commission (NDRC), focusing on new output targets, has approved three biodiesel pilot projects involving total capacity of 170,000 tonnes.

PetroChina’s Nanchong refinery will build a 60,000 tonne/year biodiesel plant in Sichuan province, Sinopec will build a 50,000 tpy plant in Guizhou province, and CNOOC will build a 60,000 tpy plant in Hainan province.

NDRC, which said the three biodiesel plants will use jatropha oil as feedstock, did not provide a timetable for the plants’ construction.

In April, Gushan Environmental Energy Ltd., China’s largest producer of biodiesel as measured by annual production capacity, began construction of new biodiesel production plants at its Chongqing and Hunan sites.

Gushan expects both plants to begin production in the fourth quarter. The Chongqing and Hunan plants are expected to add 60,000 tonnes—30,000 tonnes each—to Gushan’s annual bio-diesel production capacity.

Gushan currently operates four production facilities in Sichuan, Hebei, Fujian provinces and Beijing with a combined annual production capacity of 240,000 tonnes.

The company aims to increase its annual production capacity to 400,000 tonnes by the end of 2008 with the expansion or addition of production facilities in Beijing, Shanghai, Hunan, and Chongqing.

Samsung to build biodiesel plant in Indonesia

Samsung Group intends to invest $1.63 billion to develop a 25,000-hectare oil palm plantation and biodiesel plant in Indonesia’s Riau province.

“They bought the land recently, and that was their first investment. The total investment will likely increase by 10 times,” said Al Hilal Hamdi, who heads Indonesia’s national team for biofuel development.

Hamdi, who claimed that Samsung had spent 1.5 trillion rupiah on acquiring the land and the plant, said the facility was expected to go online in 2009 and would produce 50,000 kl./year of biodiesel.

Indonesia currently produces two types of biofuel: bioethanol made from cassava, sugarcane, and sorghum; and biodiesel, which is made from castor and crude palm oil.

Output of both types is expected to increase greatly after October when Indonesia plans to impose a new regulation requiring that at least 2.5% of fuel consumed by manufacturers is comprised of biofuel.

Transportation — Quick Takes

ExxonMobil cranks up Nigerian NGL project

ExxonMobil Corp. unit Mobil Producing Nigeria has begun operating its $1.3 billion East Area Natural Gas Liquids II project on Bonny Island, about 17 miles off Nigeria. The project is expected to recover 275 million bbl of NGL from associated natural gas produced in East Area reservoirs on Blocks OML 67, 68, and 70.

In addition, the East Area NGL II project will produce at its peak about 50,000 b/d of NGL and ultimately recover 275 million bbl of NGL from about 950 MMscfd.

Major components of the project, according to a company announcement, include an offshore NGL extraction complex, more than 125 miles of new natural gas and NGL pipelines, and expansion of the existing onshore Bonny River fractionation terminal.

The NGL project is part of an integrated approach to reduce flaring in conjunction with the existing East Area Additional Oil Recovery project. “The projects will reduce flaring and improve oil recovery through reservoir pressure maintenance,” the company said.

ExxonMobil said the NGL project follows successful start-up of the East Area Additional Oil Recovery project in June 2006. Together, the two developments “provide for recovery and commercialization of associated gas streams in the field and gas injection into existing reservoirs for recovery and production of additional oil volumes,” it said.

Mobil Producing Nigeria (51%) operates the project with coventure partner Nigerian National Petroleum Corp. (49%).

Start-up of the NGL II project brings the total of ExxonMobil worldwide start-ups in 2008 to five, including Kizomba C Mondo (Angola; OGJ Online, Jan. 21, 2007), Volve (Norway; OGJ, Feb. 25, 2008, p. 9), Starling (UK; OGJ Online, Jan. 21, 2007), and ACG Phase 3 (Azerbaijan).

Dolphin lets contract for TFP gas line

The UAE’s Dolphin Energy has awarded a $418 million contract to Russia’s Stroytransgaz for the construction of the Taweelah-Fujairah natural gas pipeline (TFP).

Construction of the 48-in., 240-km line will begin in the third quarter, with completion expected in 2010. The line will link Dolphin’s receiving facilities at Taweelah in Abu Dhabi with Fujairah on the UAE’s eastern coast.

The award for the TFP line pipe was announced in December 2007, with the $200 million order going to Salzgitter Mannesmann International GMBH for the supply of 120,000 tons of X70, 48-in. coated line pipe. More than 40% of the pipe’s length has been received, with delivery completion set for spring 2009.

Dolphin already supplies the UAE with gas from Qatar via a 48-in., 364-km subsea export pipeline connecting the company’s Ras Laffan gas processing plant in Qatar with the receiving facilities at Taweelah. The pipeline can carry as much as 56.6 million cu m/day of gas or 20.7 billion cu m/year.

In June Oman started preparations for the import of Qatari gas. Omani Oil and Gas Minister Muhammad bin Hamed al-Rumhi said a key receiving station at al-Buraimi, on Oman’s border with the UAE, was being readied ahead of the imminent arrival of the gas. “We are hopeful that Dolphin gas will begin flowing next month,” said Al-Rumhi.

His statement followed earlier reports that Abu Dhabi National Oil Co. and Dolphin had signed a 25-year pipeline deal for Dolphin to lease and operate ADNOC’s Eastern Gas Distribution System (EGDS) in Abu Dhabi (OGJ Online, June 18, 2008).

EGDS, which is used to supply gas to ADNOC’s customers in Abu Dhabi and Dubai, will be leased by Dolphin to deliver the company’s processed gas from Qatar to customers across the UAE, as well as Oman.

Sonatrach lets EPC contract for Arzew LNG train

Algerian oil company Sonatrach has awarded Saipem/Snamprogetti, in joint venture with Chiyoda, a €2.8 billion lump sum turnkey contract for a new LNG train (GL3Z).

The contract encompasses engineering, procurement, and construction of a single 4.7-million tonne/year train to be built near Arzew, Algeria, about 400 km west of Algiers. Work is to be completed by yearend 2012.

This is the first time Saipem has been named main contractor of a large LNG plant.

Saipem is 43% owned by Italy’s Eni SPA.

Oil flow resumes from Iraq via Ceyhan pipeline

Iraq resumed sending some 480,000 b/d of crude oil through its northern pipeline after Turkey allowed exports to restart from its Mediterranean port of Ceyhan.

The Turkish government had ordered a halt to Iraqi exports on July 21 as a way of forcing Baghdad to pay an outstanding debt pegged at some $100 million for unspecified costs.

After Iraq paid half the debt on July 22, Turkish state pipeline operator Botas restarted loadings from the pipeline at Ceyhan. No statement was issued concerning the outstanding payment.

Earlier, there had been contradictory statements from Turkish and Iraqi officials about the shutdown.

An official of Turkey’s state-owned Botas gas company told the Ihlas news agency that the flow of Iraqi oil exports through the Kirkuk-Ceyhan pipeline stopped July 22 for 17 hr.

He said the cause of the halt was technical not financial. “It is true that Turkey has claims. But the halt of the flow is not concerned with this debt,” he said.

That contradicted earlier reports, attributed to Iraqi oil officials, that Baghdad’s oil exports to Turkey were halted after a Turkish court ordered the stoppage pending settlement of a claim.

“A small Turkish court issued an order to stop Iraqi exports because of claims lodged against Iraqi entities,” an official said. He said the claims were for “relatively small” amounts of money, without providing further details.

Iraq’s northern pipeline, which carries crude from Kirkuk oil fields to Ceyhan, flows at about 430,000 b/d and accounts for more than 20% of Iraq’s oil exports. The bulk of Iraqi crude oil exports, which stand at more than 1.5 million b/d, pass through its oil export terminal in the south of the country at the port of Basra.