Pam Boschee, International Editor, Canada
Chevron Canada Ltd. (operator, 28% working interest) and partners - ExxonMobil Canada Properties 37.9%; Petro-Canada 23.9%; and Norsk Hydro Canada Oil & Gas Inc. 10.2% - decided to suspend negotiations with the government of Newfoundland and Labrador and demobilize the Hebron project, bringing it to at least a temporary end.
“We have worked tirelessly with the government of Newfoundland and Labrador, especially during the past year, to find ways to move the Hebron project forward,” says Alex Archila, president of Chevron Canada Ltd., “but significant and fundamental gaps remain on fiscal terms and benefits that would enable the project to proceed in a visible manner.”
Archila also says there are “a number of challenges due to the high degree of technical complexity associated with recovering heavy oil in a harsh marine environment.”
The Hebron field is located 350 km offshore the province of Newfoundland and Labrador.
Despite this suspension of current activities, Archila says, “The co-venturers remain positive that activities could proceed at a future date with the conclusion of a definitive agreement with the government of Newfoundland and Labrador.”
Meanwhile, Newfoundland plans the third-largest auction of offshore drilling rights in its history after ending a territorial dispute with neighboring Nova Scotia.
The province plans to sell rights to more than 4.23 million acres of oil and natural-gas exploration properties, including three parcels in the formerly disputed Sydney basin.
Call for Bids NL06-1 in the Jeanne d’Arc basin consists of three parcels; Call for Bids NL06-2 in the Sydney basin consists of three parcels; while Call for Bids NL06-3 offshore Western Newfoundland and Labrador consists of five parcels.
Interested parties have until Nov 15, 2006 to submit sealed bids for Call for Bids NL06-1 and NL06-3, and until Nov. 30, 2006 for Call for Bids NL-6-2.
The sole criterion for selection of winning bids is the total amount of money the bidder commits to spend on exploration of the respective parcel during the first five years.
A minimum bid of $1 million is required for parcels in the Jeanne d’Arc basin and Sydney basin, and $250,000 for parcels in the Western Newfoundland and Labrador offshore region.
The auction will include 11 parcels that are being offered at the request of producers. The Sydney basin concessions account for about 45% of the acreage.
The province has only twice sold rights to more than 4.23 million acres, in 1990 and 2003. About 741,000 acres of properties were sold in last year’s Newfoundland auction for $34 million; however, the province sought to sell almost double that total.
Colombia
BHP Billiton has acquired rights for oil and gas E&P in two offshore blocks in Colombia’s Caribbean sector. The company signed contracts with the national hydrocarbon agency of Colombia, Agencia Nacional de Hidrocarburos (ANH) last month.
BHP Billiton holds a 75% interest in each block and is the designated operator. Colombia’s state-owned oil company, Ecopetrol, holds the remaining 25% interest.
The two contracts, Fuerte Norte and Fuerte Sur, each cover approximately 1.2 million acres and are located in water depths ranging from 50 to 2,700 m.
Financial terms of the transaction were not disclosed.
This transaction follows on from a 2005 technical evaluation agreement (TEA) with ANH, which allowed BHP Billiton to study and assess approximately 3.75 million acres offshore Colombia for exploration and development opportunities.
Brazil
Petrobras will increase production at its Golfinho light crude offshore field in May, when the FPSOCapixaba is scheduled to start operations.
Capixaba will join FPSO Seillean, currently onsite and producing 21,000 b/d.
Capixaba will significantly increase production, with its capacity to produce 100,000 b/d and 3.5 MMcm/d of natural gas.
Petrobras leased the FPSO from SBM, who had hired Keppel to convert the ship into an FPSO. TheCapixaba recently arrived in Brazil from Singapore and will undergo tests before being towed to the field.
Golfinho, in the Espírito Santo basin at water depths of 1,340 m, has estimated reserves of 450 MMbbl of 28-40° API crude. It was declared commercially feasible in January 2004.
In the second development stage, Petrobras will replaceSeillean with the 100,000 b/d FPSO Cidade de Vitória during the first half of 2007.
Avante Petroleum has signed agreements to acquire Anadarko Petroleum’s wholly-owned subsidiary, Anadarko Brazil Co. The primary asset is the Tartaruga offshore oil field in the Sergipe-Alagoas basin.
The deal gives Avante a 67.5% working interest and future operatorship of block 1-SES-107D, covering 53 sq km and located in shallow water. The block currently produces oil from a single well situated on the Tartaruga oil field. Since its discovery in 1994, the field has produced over 700,000 bbl of light sweet crude (41° API).
In December 2005 a delineation well was spudded on the field to gain further information on the production potential. This well will also test a deeper exploration objective known to be productive in other parts of the basin.
The other partners in the license are Petrobras with 25% and TDC Engineering with 7.5%. The deal is expected to close during the first half of 2006, once the current drilling operations are completed.
Also in the Santos basin, Shell must decide this year whether to announce commercial feasibility or hand back to Brazilian authorities its BS-4 offshore block where it is operator.
Shell (40% interest) and partners Petrobras (40%) and Chevron (20%) have been exploring the block since 1998, when Brazil’s oil sector was opened up to private investment.
The block is located in water depths of 1,500 m and estimated to contain total reserves of 1.6 MMbbl of 14° API heavy crude.
In addition to BS-4, Shell also has interests in the BC-10 block in the Campos basin and in 11 exploratory blocks in Brazil.
The company plans to file development plans by mid-year for the BC-10 block, which it operates with a 35% stake; its partners are Petrobras with 35% and ExxonMobil with 30%. Shell expects to recover as much as 400 MMbbl of heavy crude there by 2010.
At the same time, Shell should drill new appraisal wells this year in the existing productive fields of Bijupira and Salema, where the company is producing some 35,000-40,000 b/d of oil.
In 2005, Shell invested $200 million in its Brazilian operations, of which $150 million went into E&P.
Petrobras plans to conclude a business plan by the start of the second half of this year that will allow the Santos basin to produce 300,000 boe by 2010.
The Santos basin is expected to become one of the three largest oil-producing districts in Brazil.
The other two districts are the Campos and Espirito Santo basins. Its importance lies partly in its size: Santos contains Petrobras’ 419-bcm Mexilhao gas field and the producing Merluza gas and oil field.
Petrobras announced plans early this year to invest $18 billion in the Santos basin over the next 10 years.
By the end of 2010, the company and its partners plan to produce 30 MMcm/d of natural gas and 100,000 b/d of oil from Santos.
Santos has become attractive to Petrobras because of its proximity to the industrial hub of São Paulo, as well as the burgeoning demand for natural gas in the country. Although production at older fields like Merluza, Coral, and Cavalo Marinho is ongoing, the large finds in Mexilhao were not registered until early 2000.
Petrobras is also counting on future production from the BS-500 block in the same basin, which it is currently appraising.
Mexilhao is scheduled to start production in 2008 at a rate of 8 - 9 MMcm/d. The basic feasibility studies for Mexilhao are concluded and have been approved by Petrobras management. Complete feasibility studies were expected to be approved sometime last month.
Meanwhile, at press time, Petrobras plans to select a contractor in April to build a production platform for the Mexilhao gas condensate field on block BS-400 in the Santos basin off Brazil.
Discovered in 2003 and estimated to contain 2.54 tcf of natural gas, the block’s development could cost $1.9 billion.
Petrobras plans for platform construction to start in the second half of this year with production start-up as early as 2009
Competitors for the contract include two groups of companies and a shipyard: the Mexilhao consortium (Odebrecht, Ultratec, and Techint); the Atlantico Sul consortium (Aker Promar, Andrade Gutierrez, Camargo Corrêa, Iesa, and Queiroz Galvão); and Mauá-Jurong shipyard in Janeiro State.
Plans call for the Mexilhao platform to produce 15 MMcm/d of gas and 3,200 cu m/d of condensate.
At the Manati gas field in the Camamu and Almada basins off Brazil, a second jackup, theP-13, has arrived and started drilling the second production well.
The first jackup, thePA29, is currently drilling at some 1,200 m on the first production well. Expected total depth is 1,650 m for both wells. The two jackups will share in the drilling and completion work of Manati’s seven development wells. Production start-up is expected in mid-2006.
Each well at Manati will be tied back to an unmanned platform where wellstream measurements and manifolding into the export pipeline will take place -- a 125-km long, 24-in. pipeline (partly onshore, partly offshore), which is nearing completion, with a terminus point close to the city of Salvador.
The jacket for the platform is already installed.
The Brazilian Petroleum Agency, ANP, has approved the assignment of Norse Energy Corp.’s 10% interest in the BCAM-40 license from the seller Petroserv. The Manati gas field is part of the BCAM-40 license. The other partners are Petrobras (35%) and Queiroz Galvao Perfurazao (55%)
Confirmation of two other licenses, BCAL5 and BCAL6, involved in the Petroserv transaction is expected soon.
The plan is to drill at least two of the exploration wells in the BCAM-40 license south of Manati simultaneously with the Manati development wells. If the exploration wells are successful, this will give NEC the option to drill one or more of the identified geological leads in the BCAM-40 license.
During the second half of 2006, NEC expects to drill two wells in BCAL5 and one well in BCAL6.
Manati holds total proven reserves of 230 bcf and probable reserves of 766 bcf.
Eni SPA has signed a contract with Petroleum Geo-Services ASA for a 1,500-sq km marine 3D seismic survey on Santos basin block BM-S-4, on which it has drilled three wells.
The survey will begin by June and take 45-50 days to complete. PGS shot a seismic survey over the block in 2000.
Eni’s 1-ENI-4A-RJS wildcat, drilled last year to 5,900 m TD in 387 m of water, had gas shows. In 2003, a well was drilled on the block that encountered oil, but was plugged and abandoned.
Last month, Petrobras signed contracts to convert 32 privately run oil fields into 30 joint ventures with Venezuela that give PVDSA 60% interests in Venezuelan fields operated by Petrobras.
Venezuelan President Hugo Chavez says 17 Venezuelan and international oil companies, including China National Petroleum Corp., Repsol YPF SA, and Royal Dutch Shell Plc, agreed to the JVs, which will now be controlled by PVDSA.
This follows a 20-point agreement signed in February by Brazil and Venezuela to bolster economic ties, which included a joint venture whereby Petrobras will explore Venezuelan oil fields while PVDSA will aid Brazil in building a refinery.
Venezuela
Venezuela’s energy and oil ministry has approved a request from Total and Statoil to partner in a natural gas E&P development in block 4 of the Plataforma Deltana.
Statoil will hold a 51% interest in the venture, and Total the remaining 49%.
Statoil said last year that it was interrupting its drilling program in block 4, due to “health, safety, and environmental concerns deriving from a drill malfunction.” The program is expected to be back on track during 2Q - 3Q 2006.
Deltana blocks 2 and 3 are being explored by Chevron, which earlier this year had reported finding some 7 tcf in the two blocks.
Venezuela is eager to develop natural gas reserves estimated at least 150 tcf, which the government says are the largest in the western hemisphere.
Venezuela plans to tender the offshore Guarapiche gas block and seek a partner for PDVSA in block 1 of the Plataforma Deltana, both in eastern Venezuela.
The ministry had planned to start awarding offshore gas blocks in March this year, but the tenders have been delayed.
“Right now we will go with just two big areas, block 1 in Plataforma Deltana and Guarapiche. We will not go into the Orinoco River delta [offshore eastern Venezuela near Trinidad] that much because of environmental questions,” says Energy and Oil Minister and PDVSA President Rafael Ramirez.
Ramirez says the schedule for the Guarapiche tender will be announced soon.
As to where the gas will go, Ramirez said “the first option is the domestic market, then exporting to the Caribbean islands, and then industrialization” at the Cigma petrochemicals complex, which will be built on the coast near the E&P areas of eastern Venezuela.
With current gas production at 7 bcf/d, Venezuela needs an additional 1.5 bcf/d for refining, manufacturing of petrochemicals, and expansion of crude production.
Licenses for offshore natural gas E&P in five new blocks were granted last year to private and domestic energy firms.