The US Minerals Management Service estimates undiscovered Gulf of Mexico reserves at 50 Bboe. Estimated capex for 2007 of $7 billion for deepwater developments alone will contribute to uncovering new GoM reserves.
Canada’s east coast brings a mixed bag to the table this year. EnCana’s resumed activity on the Deep Panuke gas development is breathing life back into Nova Scotia’s offshore just as drilling is put on hold off Newfoundland. And Brazil has earmarked $38 billion for E&P through 2010.
Gulf of Mexico
The US GoM saw a string of successes last year.
Anadarko hit oil with Mission Deep in Green Canyon block 955. This find was the ninth out of the 12 tests the company carried out in the GoM last year. Anadarko plans to drill 10-15 exploration wells in the GoM in the next two years.
Nexen had a good 2006 as well, with the Ringo and Longhorn finds in Mississippi Canyon block 546. Eni found gas with Longhorn North in nearby block 502, and BP’s Kaskida logged 244 m (800 ft) of net oil sands in Keathley Canyon block 295. BP is planning appraisal drilling on Kaskida this year.
Hess’ Pony, logging 145 m (475 ft) of oil in Green Canyon block 468, hit a reservoir with estimated total hydrocarbon resources of 100-600 MMboe. And Total’s Gotcha in Alaminos Canyon block 856 hit oil as well. Gotcha, adjacent to the Great White discovery in neighboring block 857, will likely be tied back to Great White, which will be produced through a spar beginning in 2009 or 2010.
Kerr-McGee (now Anadarko) found the Caesar oil discovery on Green Canyon block 683 and the Claymore gas field in Atwater Valley block 140.
Noble Energy hit with Raton in Mississippi Canyon block 248 and Redrock in block 204.
This year will be another busy year for exploration. And a number of discoveries will go into production. BP’s Atlantis is scheduled for first production in mid-year, and Anadarko’s Independence Hub is due online in the third quarter.
Genghis Khan, operated by BHP Billiton, is to come onstream by mid-year through a tie-back to theMarco Polo TLP, with the Neptune field coming online by year-end. Petrobras’ Cottonwood field is also scheduled to begin production this year.
The Mexican GoM also saw some significant drilling in 2006.
The most exciting discovery in the Mexican Gulf last year was the Noxal 1 wildcat, drilled by Pemex in the Catemaco fold belt. Noxal 1 is Mexico’s first deepwater gas discovery. An IHS report places reserves estimates at 245 bcf.
Atlantic Canada
There is mixed news coming out of Atlantic Canada.
Husky Energy Inc. has had a busy year on the White Rose field in the Jeanne d’Arc basin off Newfoundland and Labrador. The company completed the White Rose delineation program in late 2006 and in early April this year received approval to increase production to 140,000 b/d of oil for a maximum annual production rate of 50 MMbbl.
Husky is evaluating opportunities for developing newly discovered resources from the West White Rose and North Amethyst fields. Husky and partner Hydro also had a significant discovery with the West Bonne Bay F-12 well nearby during delineation drilling and is now analyzing core and fluid samples as well as wireline log data to estimate recoverable resources.
The company will spend $290 million next year in a program that includes drilling and completion of a seventh production well on White Rose and delineation of the O-28 discovery in the West Avalon Pool north of the White Rose development.
Drilling in the deepwater Orphan basin has not been so successful. Chevron’s repeated problems with theEirik Raude semisubmersible led to suspension of drilling activities. Resumed activity is dependent on a very tight rig market.
The good news off Nova Scotia is that EnCana is going to move ahead with the Deep Panuke project. The company is reportedly looking for a jackup rig for a work program that includes re-entering four wells on the field and drilling two more, a production well and an acid gas injection well.
An official request for bids is to be issued in May, with an award following project sanction, which is expected in 4Q 2007.
Trinidad
In January 2005, BHP Billiton started production from the Angostura field in block 2(c) off Trinidad’s northeast coast. Angostura contains an estimated 310 MMbbl of recoverable oil reserves.
The next big news off Trinidad came in mid-July 2006, when BG Group and its partner Chevron delivered first gas from the Dolphin Deep development to the onshore processing facilities at Beachfield on the southeast coast.
Dolphin Deep is the first subsea development in Trinidad and Tobago.
The BG-operated field is 83 km (52 mi) off the east coast of Trinidad in the East Coast Marine Area (ECMA). The ECMA contains four natural gas fields: Dolphin, Dolphin Deep, Starfish, and Manatee.
The Manatee field, discovered by BG and Chevron in January 2005, is part of a cross-border accumulation that stretches into neighboring Venezuela. Monetization options for Manatee gas are under review. Exploration drilling plans within the ECMA also are being evaluated.
More exploration also is under way.
In mid-November, BHP hit oil with the Ruby-1 exploration in block 3(a), 48 km (30 mi) off the northeast coast and 8 km (5 mi) east of the central processing platform for the Greater Angostura field on block 2(C).
Ruby-1 was drilled to a TD of 1,753 m (5,750 ft) and encountered 366 m (1,200 ft) of hydrocarbon bearing sands, including more than 244 m (800 ft) of net pay.
Canadian Superior is just launching its exploration program in Trinidad with the Victory 1 well on the Intrepid block 5(c), which lies 97 km (60 mi) off the east coast.
TheKan Tan IV semisubmersible will drill two additional wells following Victory 1 on separate natural gas prospects on the block. The initial three-well program will take a year to complete.
Canada’s Talisman Energy Inc. has plans for the region as well. The company has budgeted $65 million to drill at least two onshore and four offshore wells this year.
Venezuela
The two big projects offshore Venezuela are Plataforma Deltana and Corocoro.
Plataforma Deltana lies 240 km (149 mi) from the Orinoco Delta.
Statoil won operatorship of block 4 on Plataforma Deltana through a competitive bidding process in February 2003. Block 4 covers 1,435 sq km (554 sq mi) in 200 m to 800 m (656-2,625 ft) water depth in the gas-rich Columbus basin along the border with Trinidad and Tobago. The entire Plataforma Deltana area, which includes five separately licensed blocks, covers 32,000 sq km (12,355 sq mi).
A number of oil and gas discoveries have been made on the Trinidad side of the border, where exploration is more mature.
For licensing, Plataforma Deltana has been separated into five blocks: block 1, site of the Dorado discovery; block 2, awarded to ChevronTexaco in 2003 and home of the Loran gas field; block 3, also licensed to ChevronTexaco; block 4, licensed to Statoil that includes the Cocuina gas find; and block 5 which was offered for license but did not receive bids.
The Statoil license includes an exploration period of four years, with a commitment to drill three exploration wells.
Statoil completed the Cocuina 2X well in December 2006 and confirmed the presence of dry gas. The next two wells to be drilled are Ballena 1X and Orca BX. This exploration program is due to be completed by Oct. 2007.
Meanwhile, ChevronTexaco, which operates blocks 2 and 3, has made several significant gas discoveries.
The operator hit gas in 2006 on the Loran field in block 2. In block 3, Chevron hit gas the previous year with the Macuira well.
Macuira encountered six gas intervals with total gross thickness of 140 m (456 ft) and tested a rate of 51 MMcf/d.
The discovery is in close proximity to the Loran natural gas field and provides significant resources that will be included in the detailed evaluation as one potential gas supply source of what would be Venezuela’s first LNG train. Seismic work elsewhere in block 3 began in 2006.
ConocoPhillips expects to bring the Corocoro field in the Gulf of Paria onstream this year, but not as early as the operator would have liked. The field has already missed its 1Q 2007 startup goal. The delay in reaching first oil means Corocoro probably will not reach its full production potential until late next year.
These setbacks are symptomatic of PdVSA’s ever-changing rules. ConocoPhillips initially planned to begin drilling Corocoro in late 2004, but ran into contract and tax complications with PdVSA, which insisted on the operator building a drilling platform locally to aid domestic oil service companies.
Venezuela also upped the royalty rate on the project to 16.6% from 1%. The royalty rate will increase again, this time to 33.3%, when production begins. The ever changing, ever increasing royalty rates in conjunction with political hostility toward the US on behalf of President Hugo Chavez has made Venezuela a less than attractive draw for US companies, despite enormous reserves.
The Corocoro field was declared commercial five years ago. Venezuela hopes to use production on Corocoro, which is to reach 120,000 b/d, to help offset declining domestic production. The field contains an estimated 500 million barrels of recoverable oil.
Leading edge exploration is underway offshore with SCAN Geophysical ASA’s 3D seismic survey, which was contracted by Chevron. The survey covers two separate areas and is expected to take several months to complete.
Brazil
In April, Petrobras found a new light oil field in the Espírito Santo basin, the result of the 4-ESS-164A well. The find, 12 km (7.5 mi) northeast of the Golfinho field, has an estimated volume of 280 MMboe of oil.
Around the same time, Petrobras drilled well 4-ESS-160 in the basin just adjacent to the Golfinho field, which also resulted in a new discovery with estimated volumes of 60-80 MMboe. Considering the Golfinho field’s earlier estimates at 250 MMboe, this new find increases potential reserves in the region to 310-330 MMboe.
With these two recent discoveries, Petrobras estimates that potential light oil reserves in the basin now stand at 600 MMboe.
Petrobas had another discovery in the Santos basin in October. The ultra deepwater Tupi field is in block BM-S-11, 250 km (155 mi) offshore in 2,126 m (6,975 ft) water depth. Tupi reportedly is a large structure with significant reserves potential. The discovery led Petrobras and BG to agree on an accelerated exploration and appraisal program.
This discovery follows an earlier find last year 70 km (43.5 mi) away in block BM-S-10
Brazil started off 2007 by laying plans for a busy schedule through 2010.
To keep increasing production in the long term, Petrobras has been enhancing its exploratory portfolio and now has more than 100 local blocks in addition to its overseas acreage.
Seeking to maintain Brazil’s oil self-sufficiency, Petrobras has a portfolio that includes dozens of projects and will involve $38 billion in investments in exploration and production through 2010.
Petrobras will invest $7.4 million in exploration alone through 2010, including investments made by partners and third parties.
The company’s production goal for 2015 is 4,556,000 b/d of oil.
The operator took a step toward increasing production in January when it brought the Espadarte field online via theCidade do Rio de Janeiro FPSO.
Full production is expected this year with nine subsea completions - five for production and four for water injection. A new oil lifting system developed by Cenpes, the Petrobras research center, will use subsea pumps to help move the oil onto the FPSO.
The vessel can produce 100,000 b/d of oil, 2.5 MMcm/d (88 MMcf/d) of gas, and store 1.6 MMbbl of oil.
Devon Energy Corp. and its Korean partner SK Corp. plans to drill three more exploration wells this year in the BM-C-8 concession in the Campos basin offshore Brazil.
Devon will produce the field with thePolvo FPSO, which is designed to produce 90,000 b/d of oil, handle 135,000 b/d of water, and compress 7.5 MMcf/d of natural gas.
The FPSO is to produce 50,000 b/d of oil from the shallow-water field, which is to see first oil in July 2007.
An interesting side note on Brazil is the recent Petrobras/Gazprom memorandum of understanding. Petrobras and Russia’s Gazprom, the world’s biggest gas company, have signed a memorandum of understanding to identify cooperation opportunities for oil and gas projects at a meeting that took place in Brazil at the end of February.
Three potential initiatives include cooperation possibilities in LNG, natural gas storage, and natural gas transportation system projects.
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