OGJ Newslwetter

Oct. 2, 2006
While the total amount of energy required to meet the demand of the 25 European Union countries in 2005 remained the same as in 2004 at 1,637 million tonnes of oil equivalent (toe), a 4.5% fall in EU energy production from all sources pushed up its dependence on imports to 56% from 54%, according to Eurostat, the EU’s statistical office, in its first 2005 estimates.
General Interest - Quick Takes

EU energy production drop forces higher imports

While the total amount of energy required to meet the demand of the 25 European Union countries in 2005 remained the same as in 2004 at 1,637 million tonnes of oil equivalent (toe), a 4.5% fall in EU energy production from all sources pushed up its dependence on imports to 56% from 54%, according to Eurostat, the EU’s statistical office, in its first 2005 estimates.

Crude oil production decreased by 9%, gas production by 5.8%, coal by 5.7%, and nuclear energy by 1.3%. The UK accounted for 70% of the oil produced, followed by Denmark 15%, with production falling in both countries by 11.4% and 3.8%, respectively.

The UK also was the EU’s largest natural gas producer, with 44% of total production, followed by the Netherlands at 32%. In both countries production fell by 7.7% and 5.9%, respectively.

Oil accounted for about 60% of the EU’s net energy imports, and gas for 25%. Net crude imports and products rose by 2.9%, while net gas imports rose by 9.2%.

Eurostat has determined that energy consumption per capita in the 25 EU member states was equivalent to 3.6 toe in 2005, compared with 7.8 toe/capita in the US and 4.1 toe/capita in Japan. But consumption varies greatly from one member state to another, reflecting economic development, the degree of industrialization, and climates.

SEC, former Willbros exec settle bribery charges

The US Securities and Exchange Commission said it reached an agreement on Sept. 14 with Jim Bob Brown, who formerly worked for a Willbros Group Inc. subsidiary, to settle charges that he violated antibribery provisions of the Foreign Corrupt Practices Act.

In a civil action filed in Houston federal court, SEC also alleged that Brown circumvented internal controls and falsified records while he was a supervisor in Willbros’s Nigerian operations.

It said that Brown participated in three separate schemes to bribe foreign officials in Nigeria and Ecuador.

The complaint alleged that in February and March of 2005, Brown procured $1 million on behalf of a Willbros affiliate, which he delivered as partial payment to Nigerian government officials and to employees of a joint venture majority-owned by a Nigerian government division. It said he also assisted in paying another $550,000 to satisfy earlier commitments.

Second, in return for Willbros receiving a $3 million contract, Brown allegedly assisted in a scheme to pay $300,000 to officials of an oil and gas company owned by the Ecuadorian government, according to the complaint.

Finally, it said, Brown knowingly assisted a long-running scheme in which employees of Willbros affiliates fabricated invoices to procure cash from the company’s Houston headquarters for bribing Nigerian tax and court officials and for other purposes.

Brown neither confirmed nor denied the allegations in the settlement. Pursuant to the judgment, the court will determine, at a later date in response to an SEC motion, whether Brown will have to pay a civil penalty, the federal agency said.

DOE to support CO2 EOR at Citronelle, Ala.

A project to inject carbon dioxide into Alabama’s largest oil field to improve recovery and later store the greenhouse gas will have its costs shared by the US Department of Energy.

DOE plans to provide nearly $3 million of the $6 million cost of the enhanced oil recovery project in Citronelle field operated by Plano, Tex.-based Denbury Resources Inc. in Mobile County 25 miles northwest of Mobile. The project could recover 64 million bbl of oil, DOE said.

The University of Alabama-Birmingham proposed the project to DOE. After economic oil production ceases, it calls for storage in the reservoir and adjacent formations of CO2 produced from the combustion of fossil fuels in power plants and other processes.

Southern Co., Atlanta, one of the country’s largest electricity generators, is evaluating the capacity of such reservoirs as possible locations for permanent sequestration of CO2 separated from coal and natural gas combustion products in its power plants, DOE said. Project goals are to provide oil field operators and CO2 producers with improved estimates of the oil yields from EOR and the capacity of depleted reservoirs to sequester CO2. Another objective is to improve reliability of computer simulations of the oil yield and sequestration capacity of a given geologic formation and the rate at which CO2 can be injected.

Other project participants are the University of Alabama-Tuscaloosa, Alabama A&M University, Huntsville; Geological Survey of Alabama; and the University of North Carolina, Charlotte.

Denbury also plans CO2 EOR injection projects in Tinsley and Eucutta fields in Mississippi. The natural CO2 to be injected will originate in that state (OGJ Online, Nov. 28, 2005).

Industry Scoreboard
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Exploration & Development - Quick Takes

Shell, Maersk to drill new block off Brazil

Royal Dutch Shell PLC and Maersk Oil & Gas AS plan next year to drill the first exploration well on the BMS-31 Block in the Santos basin off Sao Paulo, Brazil.

Shell, the block’s operator and majority stake holder, is conducting seismic studies on this and on its other Brazilian blocks.

John Haney, Shell’s vice-president of Brazilian E&P, said the company also plans in October to drill an appraisal well on the BS-4 Block in the same basin. The company has until yearend to declare this block commercial or return it to Brazil’s National Petroleum Agency.

The block has reserves of 300 million bbl of very heavy crude. Shell holds a 40% operating stake.

In the Campos basin at Shell’s 50%-held BC-10 Block, production of 17-24° gravity oil reportedly could start in late 2007 or early 2008. BC-10 was declared commercial in December 2005 and has a potential to produce about 100,000 b/d of oil from oil reserves of 400 million bbl (OGJ Online, Jan. 23, 2006).

Seismic indicates giant gas at Sampaguita

The 1976 Sampaguita gas-condensate discovery in the South China Sea northwest of Palawan Island could be an accumulation of as much as 20 tcf of gas, said Forum Energy PLC, London.

Interpretation by consulting engineers of 3D seismic data acquired over the structure confirmed a minimum of 3.4 tcf of proven gas in place in the three wells. It also confirmed the structure’s extension to a possible closure of 290 sq km, which would yield an estimated 10 tcf in these sands alone. Untested sands known to contain gas could double the higher figure.

Previous estimates of Sampaguita’s resource were 1 to 17 tcf with a likely 5 tcf (OGJ, Nov. 19, 2001, p. 49).

Forum, which holds 100% of the equity in Reed Bank GSEC 101, is converting the license to a service contract and plans to drill an appraisal well as soon as possible. The license is 250 km west of Malampaya gas and oil field.

NW Alberta gas resource play adds momentum

EnCana Corp. is building gas production at a resource play in the deep basin of west-central Alberta to which it attributes 2 tcf of unbooked resource potential.

The company drilled 20 wells in the play in 2004, 51 in 2005, and 38 in the first half of 2006. Gas production averaged 95 MMcfd in the second quarter of 2006 compared with 55 MMcfd in 2005 and 42 MMcfd in 2004.

The company holds 448,000 net acres and is running eight rigs in the play, which produces from a deep basin Cretaceous reservoir. EnCana estimates original gas in place at 20 to 40 bcf/sq mile. It expects to drill two to four wells per square mile with the average well initially producing at the rate of 2 to 5 MMcfd and ultimately recovering 2 to 5 bcf of gas.

Bighorn is one of nine gas resource plays in the company’s portfolio.

Western Oil Sands exploring Kurdistan tract

A unit of Western Oil Sands, Calgary, has begun exploring a 914,000-acre block in Kurdistan southeast of Kirkuk under an exploration and production-sharing agreement with the Kurdistan Regional Government Sulaymaniyah Administration.

WesternZagros Ltd., seeking conventional oil and gas in the Zagros fold belt, has identified three large structures from satellite imagery and noted that the block has active oil seeps and oil shows in water wells. The subsidiary ran a preliminary 2D seismic survey in late 2005. The block lies 60 km southeast of and on trend with the southeastern edge of supergiant Kirkuk oil and gas field. The identified structures, Bawanoor, Kalar, and Shakal, are each more than 25 km in length.

The agreement, to become law after passage by the unified government, requires a $45 million work commitment that includes geological and geophysical programs and exploratory drilling. Drilling could begin as soon as late 2007.

Western Oil Sands has assigned the block 1.7 billion bbl of risk-adjusted potential. The company has a 20% interest in the Athabasca Oil Sands Project in Alberta, with Shell Canada Ltd. holding 60% and Chevron Canada Ltd. 20%.

Dana Petroleum logs gas pay with Babbage well

Dana Petroleum PLC, Aberdeen, has reported the successful drilling and flow testing of Babbage gas field in the UK Southern Gas basin.

The Babbage appraisal well, on North Sea Block 48/2a, targeted a crestal area of the field with a view to proving gas reserves and productivity in order to proceed with development.

The well, drilled vertically to more than 11,000 ft TD, was spudded July 16 and found gas throughout a substantial Leman sandstone section. The well flow-tested at 10.7 MMcfd of gas without stimulation. The well will be suspended at the seabed and kept for use as a future gas producer.

Babbage, with as much as 390 bcf in place in Permian Rotliegend, could be tied back to Johnston 10 km north or Ravenspurn North 12 km northwest (OGJ Online, Sept. 28, 2005).

Dana holds a 40% interest in Block 48/2a. Partners are operator E.ON Ruhrgas UK North Sea 47% and Centrica Resources Ltd. 13%. Dana called the well’s results “highly encouraging” and the partnership has already secured a rig for further drilling. Dana said Babbage field is now thought to be one of the largest undeveloped gas fields in the UK North Sea.

NWT field’s bounty put at 20-30 million bbl

Cameron Hills field in the Northwest Territories could be an accumulation of 20-30 million bbl, operator Paramount Resources Ltd., Calgary, told financial analysts in mid-September.

Paramount, which has booked only 1-2 million bbl of reserves in the field, is producing 1,500 b/d of light, sweet crude and 7-8 MMcfd of gas.

Each of the 17-18 wells drilled has produced or tested oil or gas, but only two oil wells have been on sustained production because of the capacity of the 4-in. oil pipeline to Alberta.

The regulatory process has slowed the rate at which new wells can be drilled, Paramount said, and the field is the company’s second lowest site for 2006 capital spending.

The company started producing gas in March 2002 and oil in April 2003 and has seen practically no decline in the oil rate. It placed a third well, J-74, on production last winter at 500 b/d.

Oil and gas are found in structural and stratigraphic traps in the Middle Devonian age Slave Point, Sulphur Point, and Keg River formations (OGJ Online, June 18, 2004). The field lies just northeast of the northwest corner of Alberta.

Drilling & Production - Quick Takes

BP gets DOT nod to restart Prudhoe Bay field

BP Exploration (Alaska) Inc. said Sept. 22 it will restart a portion of the Eastern Operating Area (EOA) of Prudhoe Bay field in order to run cleaning pigs and conduct an in-line, smart pig inspection of the oil transit line.

DOT’s approval will allow BP to run the smart pig through a 5-mile, 34-in. segment that carries oil from processing facilities on the field’s eastern half.

The EOA was shut down Aug. 10 following the discovery of a spill caused by isolated pitting corrosion on Aug. 6 (OGJ Online, Aug. 10, 2006).

The company has determined that the line can be returned to service. Three of the four flow stations currently on warm stand-by will be returned to full production, the company said.

“This is an important milestone in returning all of Prudhoe Bay to production many months in advance of our complete replacement of 16 miles of oil transit lines,” said David Peattie, BP Group vice-president for existing profit centers.

Results of the smart pig inspection will aid BP and the US Department of Transportation to determine whether to continue operations through the transit oil line or to shift production through a system of bypass lines currently under construction.

BP has performed tests on thousands of feet of the EOA pipeline using ultrasonic and other imaging equipment. As added precaution, BP’s start-up plans include an enhanced spill-response contingency plan, in which crews and material will be positioned to respond if any leak occurs, the company said.

BP said safely restarting the field will take about a week. Resuming full operation of eastern Prudhoe should add about 200,000 b/d of oil production from the Alaskan North Slope. Current production from the rest of Greater Prudhoe Bay is about 250,000 b/d.

Chevron contract includes new drillship

Chevron Corp. awarded Transocean Inc., Houston, a deepwater drilling contract requiring construction of an enhanced version of Transocean’s Enterprise-class drillship, dedicated to Chevron’s use for as long as 5 years.

Daewoo Shipbuilding & Marine Engineering Co. Ltd. will build the $670 million dynamically positioned, double-hull drillship in Okpo, South Korea. The rig will have a variable deckload of more than 20,000 tons. It will allow for parallel drilling operations and will have a larger, stronger, more efficient top drive than conventional rigs, enabling wells to be drilled to 40,000 ft TD in 12,000 ft of water, Transocean said.

Chevron has the right to convert the 5-year contract to 3 years if declared by September 2007. Revenues generated during a 5-year contract period are estimated at $862 million, or $609 million for 3 years.

The contract commencement date is scheduled for early 2010, and Chevron will take delivery in the Gulf of Mexico. This is the second drillship construction contract has Chevron awarded Transocean this year (OGJ, Mar. 6, 2006, Newsletter).

ReedHycalog: worldwide rig fleets see growth

Due to improved market conditions influenced by high oil and gas prices, the numbers of available rigs in the US, Canada, global offshore mobile, and international land all rose this year, according to Grant Prideco’s 53rd annual ReedHycalog Rig Census.

Also, “Not only has the market upswing encouraged contractors to reactivate or refurbish their inventory of older units, but rig building programs have also been established and are now coming to fruition,” said ReedHycalog Pres. John Deane.

The total number of US rig owners increased by 31 to 257 this year, as more companies found it economically viable to enter the market.

The US rig fleet realized a net gain of 13.5% over 2005 figures, bringing the fleet size to 2,298. This increase includes 391 additions, of which 238 were newbuilds, and 119 deletions.

US fleet utilization levels maintained a record high of 96%, a 1% gain over last year.

The Canadian rig fleet reached a new record high of 799 units, up from 741 in 2005. The increase included an addition of 63 newly manufactured rigs. The rig utilization for Canada, during the spring census period, had climbed 10 percentage points to 84%.

For the global offshore mobile rig fleet, 29 additions were realized this year. The fleet rose by a net 13 units to 654. This total took into account 20 reactivations and 9 new units, as well as losses due to hurricane damage and retired units. Currently, more than 90 units are on order or under construction, estimates ODS-Petrodata.

The international rig market saw a sharp increase in its overall utilization rate, which climbed to 95% for land rigs from 83% in 2005. China, Russia, and the former Soviet Union, which were excluded last year, have reentered the census with 100% utilization. This greatly increased Europe’s and Asia’s overall percentages. Russia and the FSU added nearly 500 rigs and China added over 1,100 units.

Petro-Canada signs rigs for exploration projects

Petro-Canada has signed several drilling rig contracts over the next 18 months for work associated with its international exploration program.

The company expects to begin a multiwell exploration and field development program in the UK North Sea near yearend and plans to begin drilling in Trinidad and Tobago in 2007, said Nick Maden, vice-president of exploration.

Maden added, “Work in the Zotti Block in Algeria will start in the fourth quarter of this year, and we now expect drilling on Block II in Syria to commence early in the first quarter of 2007.”

Petro-Canada has secured the GlobalSantaFe Glomar Arctic III semisubmersible to be used in its UK work program, which includes development of Saxon oil field, in-fill drilling in Guillemot oil field, and three exploration wells, two of which recently were awarded in the 23rd licensing round. This contract is for 1 year.

Another contract is for Diamond Offshore Drilling Inc.’s Ocean Worker semisubmersible, which will start a 6-month, multiwell program on Block 22 in Trinidad and Tobago in the second half of 2007. Also at that time, the Rowan Gorilla III jack up will arrive on the Caribbean island for a 6-month, four-well program on Blocks 1a and 1b. This contract has an extension option to include an additional two wells.

Eurasia Drilling lets $65 million rig contract

Abbot Group PLC’s land rig design engineering and fabrication subsidiary Bentec has been awarded a $65 million contract by Eurasia Drilling, formerly the drilling subsidiary of OAO Lukoil, for four 250-tonne, fast-moving hybrid rigs, derived from Bentec’s original HR5000 design.

Work is to start immediately, with the first rig slated for delivery in 12 months. The other three rigs are planned for delivery by yearend 2007.

This latest contract brings to $200 million Bentec’s order intake so far this year and to ten its number of rigs under construction (OGJ, Aug. 14, 2006, p. 39).

Processing - Quick Takes

Petrotrin to use UOP technology for upgrades

Petrotrin has launched a 3-year gasoline optimization program at its 175,000 b/cd Pointe-a-Pierre refinery in South Trinidad.

The program involves constructing or revamping eight major plants, along with associated utilities and supporting units.

Four of the eight plants will use the proprietary technology of UOP LLC, Des Plaines, Ill.

UOP will provide technology for a CCR Platforming unit with a Chlorsorb system for reforming naphtha to produce high-octane fuel, a Penex unit for producing clean-burning gasoline, and a Merox unit for cleaning LPG.

It will also revamp a fluid catalytic cracker and upgrade the unit with a third-stage separator.

Russo-Indonesia JV to build Situbondo refinery

East Java Gov. Imam Utomo said a consortium of Russian investors and state-owned PT Petrogas Jatim Utama will build a $3 billion refinery in his province.

Utomo expects a contract to be signed in November for the facility, which will be built in Situbondo. Its initial capacity will be for 150,000 b/d, eventually rising to 300,000 b/d. The refinery will produce diesel, lubrication oil, and gasoline.

BP lets contract for coker at Spanish refinery

BP Oil Refineria de Castellon SA awarded a detailed engineering, procurement, and construction supervision contract to Foster Wheeler Iberia SA for a delayed coker at BP’s 104,500 b/cd Castellon, Spain, refinery.

Terms of the contract were not disclosed. The planned 20,000 b/sd coker will use Foster Wheeler’s proprietary delayed coking technology. Foster Wheeler is based in Clinton, NJ.

The new coker, scheduled for completion during 2008, is part of BP’s planned reconfiguration of the Castellon refinery to reduce residual fuel oil production.

Details of the reconfiguration were not immediately available for the refinery in Castellon de la Plana, Spain (OGJ Online, July 15, 2002).

Shell lets turbine contract for GTL project in Qatar

A unit of Royal Dutch Shell PLC has let a contract to GE Oil & Gas for six 42-Mw gas turbines, equipped with dual fuel integrated gasification combined-cycle (IGCC) combustion systems, for the Pearl gas-to-liquids (GTL) project in Ras Laffan Industrial City, Qatar (OGJ, Aug. 7, 2006, Newsletter).

The contract scope includes IGCC combustion engineering, combustion system lab testing, spare parts, and training.

The gas turbines are capable of burning a range of low-btu fuel gasses, including a process off-gas derived from the core GTL reactors.

The turbines will be installed in the 140,000 b/d Pearl GTL plant in a cogeneration configuration that will produce 180 Mw of electric power for use in the facility.

Natural gas is the backup fuel, and will be used for plant startup. Steam injection will be used to reduce nitrogen oxide emissions.

The first gas turbine unit will be required to meet power requirements during the commissioning of the GTL facility, scheduled to begin commercial operation by 2009-10. The six units are scheduled for shipment in late 2007 or early 2008.

Transportation - Quick Takes

Terminal problems delay Sakhalin-1 oil exports

The head of Russia’s Federal Service for Ecological, Technological, and Nuclear Monitoring announced that Exxon Neftegas Ltd., operator of the Sakhalin-1 project, will not be able to start shipping Sakhalin oil for export until it has satisfied objections regarding construction of the oil terminal in the port of Dekastri.

“In violation of the law, the Dekastri oil terminal was being built in accordance with adjustments and additions made in the feasibility study before they were confirmed by experts in industrial safety,” said Konstantin Pulikovskiy. “There are problems. One could open the terminal, but the problems must be resolved.”

Pulikovskiy said he hoped the consortium developing the Sakhalin-1 project would correct the violations made during the construction of the Dekastri oil terminal in Khabarovsk Territory before the start of oil exports, scheduled for early October.

“We’ll work to keep up with the schedule. The project is in place and must be implemented,” Pulikovsky said when asked whether the problems could be resolved before the start of first exports. Two 100,000-tonne tanks in Dekastri are reported to have been filled with crude oil ready for export.

China proposes LNG terminal in Rizhao

China and EurOrient Financial Group have signed an agreement for construction of an LNG receiving terminal and related facilities in Rizhao City in Shandong province.

The proposed terminal is one of only 10 LNG projects to be commissioned in China along the coastal cities for the next 10 years by the state council.

The Rizhao terminal will have an initial capacity of 1.5 million tonnes/year of LNG. It will include a transshipment terminal and one or two storage tanks, pipelines, and gas distribution facilities. It will supply gas to Rizhao City and the greater Qingdao territory.

With estimated cost of more than $965 million, the project will be financed and developed in phases. The first phase will handle as much as 500,000 tonnes of LNG. EurOrient is considering various countries as suppliers, including Australia, Indonesia, Malaysia, Qatar, Oman, and Russia.

Pending receipt of a construction permit by December 2007, construction of the terminal is expected to start during first quarter 2008.

EurOrient said it is considering the Rizhao Lanshan Port as a possible location for the terminal.

Second Iran-Armenia gas pipeline on the horizon

In a visit to the Armenian capital of Yerevan, Iran’s parliamentary speaker Gholam-Ali Hadad-Adel said his country wants to build a second natural gas pipeline to Armenia, according to the news service AFP.com.

This would augment a $220 million pipeline now in the last stages of completion and due to start up in January to deliver about 36 billion cu m over a 20-year contract.

Earlier in 2006, Armenia maintained that the 140-km pipeline was being built with an OD of 48 in., despite Russian pressure to reduce its OD to 28 in. The pipeline covers 100 km in Iran, with the balance traversing Armenia.

Until now Armenia has depended solely on Russian gas rather than importing hydrocarbons from closer Azerbaijan. That trade is prevented, said the news service, by the long-standing dispute between Armenia and Azerbaijan over the Armenian Nagorno-Karabakh enclave in Azerbaijan.

The report said Armenia will compensate Iran in part for the costs of the first pipeline with deliveries of electricity from a Soviet-era nuclear power plant.