Ecopetrol, Talisman acquire BP's Colombia assets
Ecopetrol SA and Talisman Colombia acquired BP Exploration Co. Ltd. for $1.75 billion and renamed the company Equion Energia Ltd.
Ecopetrol owns 51% interest of Equion and Talisman owns the remainder. Equion consists of all assets and business formerly owned by BP's Colombia subsidiary.
John A. Manzoni, Talisman president and chief executive officer, said, "Talisman looks to build a strong production base in Latin America over the next 3 to 5 years. We look forward to deepening our strategic relationship with Ecopetrol."
Equion produces 90,000 boe/d of which it has direct ownership of 27,000 boe/d. Equion reports proved and probable reserves of 94 million bbl.
Schlumberger: Deep water, E&P to drive earnings
Schlumberger Ltd.'s top executive expects robust world oil and gas activity, especially deepwater exploration and development outside the US, will drive strong 2011 earnings for his company and for oil service providers in general.
Andrew Gould, Schlumberger chairman and chief executive officer, recently told investors and analysts that he believes oil prices have moved into a range that will encourage operators to increase worldwide exploration investments.
Schlumberger reported fourth-quarter profit of $1.04 billion, or 76¢/share, compared with $795 million or 65¢/share for the same period the previous year. Last year, Schlumberger closed its $10.8 billion acquisition of drilling fluids provider Smith International.
"While we do not anticipate a return to pre-Macondo activity levels in deepwater US Gulf of Mexico in 2011, we do expect a marked increase in deepwater activity in the rest of the world," Gould said of the April 2010 blowout of BP PLC's Macondo well off Louisiana and subsequent oil spill.
Gould anticipates increased development activity and production enhancement worldwide "promise stronger growth rates as the year unfolds."
During a Jan. 21 conference call, Gould said it's possible Schlumberger's first-quarter 2011 earnings could be lower than fourth quarter 2010 earnings because of various factors, including seasonality in the Russian market and North Sea weather.
For natural gas, demand recovery has been less marked. Increased supply of both US unconventional gas and of LNG worldwide will limit gas price increases, he said.
"Nonetheless, activity in the United States is likely to remain strong—at least through the first half of the year—due to the commitments necessary to retain leases, the backlog of wells to be completed, and the contribution of natural gas liquids to overall project economics," Gould said. "Increased service capacity, however, will negatively affect pricing at some stage during the year."
Worldwide, he said the governing factor on gas activity, particularly in the Middle East, will be the ability of many nations to use gas as a substitute for oil to meet increased local energy demand, thus freeing up more liquids for export.
Gould also expects that unconventional gas resources will continue to attract interest outside the US and Canada.
"The leading activity will continue to be gas in tight, or low permeability, reservoirs, and in coalbed methane developments," he said. "There will be exploration activity around the potential that shale gas offers in many other parts of the world."
Halliburton's profits climb on liquids-rich shale plays
Halliburton Co. said higher drilling activity in oil and natural gas shale plays boosted its fourth-quarter earnings, more than offsetting declines in revenue from restrained international markets and suspended deepwater activity in the Gulf of Mexico.
During a Jan. 24 conference call, Halliburton reported fourth-quarter net income of $605 million, or 66¢/share, compared with $243 million, or 27¢/share, for the same period the previous year.
"Our United States land operations experienced continued improved profitability," said David Lesar, Halliburton chairman, president, and chief executive officer. "The increase in horizontal drilling and activity in liquids-rich plays continued to drive service intensity."
Meanwhile, Halliburton reported a decline in its Gulf of Mexico revenue and income following the April 2010 blowout of BP PLC's deepwater Macondo well off Louisiana and the subsequent oil spill in the gulf.
"We continue to believe that prospects for a recovery in the Gulf of Mexico will remain uncertain through the first half of 2011 and perhaps the full year," Lesar said. "However, I believe it is prudent to maintain all of our infrastructure and most of our headcount in anticipation of a rebound in the gulf."
Halliburton's gulf strategy could result in continuing losses there until the rig count recovers, Lesar noted. For 2011, he expects US and Canadian operators will continue investing in unconventional oil and gas.
"Development of these resources requires expansive well programs resulting in longer-term contracting arrangements for some services," he said. "We continue to expect that we can improve prices in select basins where the demand for our integrated services is robust."
For instance, one customer plans to increase the length of its laterals in the south Texas Eagle Ford play to 10,000 ft compared with 6,000-ft laterals that it is currently drilling, Lesar said.
Halliburton reported improved results in Norway, West Africa, Iraq, and Algeria, Lesar said. He expects activity increases to continue in those markets despite a traditional first-quarter decline for international earnings.
"We continue to win significant additional awards in Iraq," he said. Halliburton plans to double the number of workers it has in Iraq to 1,200 this year.
"The improving oil consumption demand levels combined with the industry's declining spare capacity provides a more favorable outlook for oil services and technologies in 2011 and beyond," he said. Halliburton plans to invest in technology and to expand its manufacturing capacities as a result.
Cairn soldifies position off West Greenland
Cairn Energy PLC, which plans to drill as many as four exploratory wells off western Greenland in 2011, will maintain 10-12 potential well locations in a variety of operating environments and geological settings for as long as possible.
The company will pick which prospects to drill in May 2011.
Cairn continues to evaluate the results of its 2010 three-well exploratory drilling campaign on the Sigguk Block in the Disko Bay area. The wells found biogenic and thermogenic gas and oil but not significant target reservoir rocks. Geochemical evaluation has now identified three oil types.
The Alpha-1S1 exploratory well has been suspended to allow possible reentry to sidetrack or deepen. The T8-1 and T4-1 exploratory wells have been plugged and abandoned.
The company has secured the dynamically positioned Leiv Eiriksson semisubmersible and the Ocean Rig Corcovado drillship for the 2011 drilling season.
Cairn plans to shoot 3D seismic off Greenland this year, subject to approvals. Two 3D seismic survey vessels are expected to be contracted to acquire as many as five 3D surveys in different areas.
The company shot more than 15,000 km of 2D seismic on the Eqqua, Ingoraq, Napariaq, Pitu, Sigguk, and offshore south Greenland blocks in 2010, bringing its total 2D seismic data base in Greenland to more than 30,000 km.
Cairn now holds 102,000 sq km off Greenland, equivalent to 15 quadrants in the UK North Sea.
The government has confirmed Cairn as operator of the Atammik and Lady Franklin blocks, and Cairn has acquired the 47.5% interest held by Encana Corp. The entitlement interests are Cairn operator with 87.5% and Greenland's Nunaoil 12.5%. The blocks are usually free of sea ice year-round.
Cairn was awarded the Ingoraq, Napariaq, and Pitu blocks in the December 2010 Baffin Bay bid round. Shell, Statoil, GDF, Conoco-Phillips, and Maersk also won blocks in the round (see map, OGJ, Jan. 3, 2011, p. 71).
Total adds discoveries off Congo (Brazzaville)
Total SA notched two more oil discoveries on its Moho-Bilondo license off Congo (Brazzaville), boosting its confidence that a second development hub is emerging as a direct extension of the producing first phase in the southern part of the license.
The Bilondo Marine 2 and 3 wells, in 800 m of water in the central part of the license 70 km off the coast, follow the successful Moho Nord Marine 1 and 2 exploratory wells drilled in 2007.
Bilondo Marine 2 and 3 went to 1,800 m in the Tertiary series and flowed successfully at undisclosed rates. They cut 77 m and 44 m, respectively, of gross reservoir, and neither well encountered water.
This first phase, brought on stream in 2008, was the first ultradeepwater field developed in Congo (Brazzaville). That field is making 90,000 b/d from 13 subsea wells tied into a floating production unit. The oil is shipped to the onshore Djeno terminal.
Total E&P Congo is operator with 53.5% interest in the license. Chevron Overseas Congo Ltd. has 31.5%, and Soc. Nationale des Petroles du Congo has 15%.
Brazil Santos post-salt light oil find gauged
Petroleo Brazileiro SA (Petrobras) and Karoon Gas Australia Ltd. found 38° gravity oil and associated gas in the Tertiary post-salt section at the Maruja-1 exploratory well on the BM-S-41 concession in the Santos basin off Brazil.
Karoon said Petrobras achieved an equipment-constrained flow rate of 6,142 stb/d through a 5/8-in. choke during the clean-up flow period. In the 24-hr main flow period, the high-porosity Oligocene sandstone reservoir stabilized at 4,675 stb/d of oil and 800 Mcfd of gas on a 1⁄2-in. choke with 1,050 psia flowing wellhead pressure.
Test interval at the well is 2,201.5-2,210 m. Total depth is 3,789 m. The wellsite is 16 km southeast of the Petrobras Tiro and Sidon discoveries, which are on extended well test in similar geology.
Petrobras operates the block with an 80% stake, while Karoon holds a 20% stake subject to approval by Brazil's Agencia Nacional do Petroleo.
Analyst IHS Global Insight said Petrobras earlier indicated it hopes the new find can form part of a new production pole in the southwestern Santos basin along with the Caravela, Cavalo Marinho, Coral, Tiro, and Sidon discoveries.
Petrobras announced the Maruja find last November when it said it discovered light oil in sandstone reservoirs in an exploratory well in Block S-M-1352 of the BM-S-41 concession (OGJ Online, Nov. 16, 2010).
Drilling & Production — Quick TakesCNOOC orders Liuhua 4-1 subsea equipment
China National Offshore Oil Corp. (CNOOC) placed an $85 million order with FMC Technologies Inc. for the manufacture and supply of subsea production equipment for the Liuhua 4-1 oil field development in the South China Sea.
Liuhua 4-1 field lies in 850-1,000 ft of water about 130 miles from Hong Kong and 150 miles from Shenzhen. FMC expects equipment deliveries to commence in this year's fourth quarter.
Intecsea, a unit of WorleyParsons Group, described the Liuhua 4-1 development as having eight subsea trees clustered around a central manifold and an 11-km pipe-in-pipe flowline tying back to the existing Liuhua 11-1 field, which has a Sedco 700 submersible production unit and a floating production, storage, and offloading vessel.
Both the Liuhua 11-1 and the Liuhua 4-1 have low reservoir pressure and require downhole electric submersible pumps for artificial lift. Each Liuhua 4-1 well will have dual ESPs, with one pump in standby mode. Switching from one pump to the other will be done remotely. Three 5 kv power cables will supply power to the ESPs.
Intecsea said Liuhua will have a permanently moored drilling rig available to service the wells Control, monitoring, and chemical injection will be via a 14-km umbilical. The control system is electrohydraulic.
First oil from the field is expected in 2012, according to Intecsea.
Chevron to expedite Platong Gas II project in Thailand
To meet Thailand's rapidly growing demand for natural gas, Chevron Corp. hopes to begin production at the $3.1-billion Platong Gas II project in the Gulf of Thailand later this year.
"With gas demand in Thailand growing by 13% in 2010, we are working to accelerate Platong II's progress towards first gas," said Jim Blackwell, president, Chevron Asia Pacific Exploration & Production Co.
"The need to accelerate is very much understood," said Joe Geagea, managing director of Chevron Asia South, who joined Blackwell and other officials at a "sail away" ceremony for Platong II's central processing platform.
"This is something that is very much needed for the economy," said Geagea, adding, "We're getting close to putting this on a big barge and…getting it online as soon as we can."
Built by McDermott International, the platform will increase Thailand's gas production more than 10% from its current 2.89 bcfd.
Analyst IHS Global Insight noted Chevron in March 2008 approved the launch of construction for the Platong II project, which it said would be completed by this year's first quarter.
Last April Chevron announced the project was 49% complete, but its launch date had been revised to 2012.
"The cause of the project schedule revision is unclear but could potentially have been caused by uncertainties about Thailand's gas demand in the immediate aftermath of the financial crisis," IHS Global Insight said.
Meanwhile, Chevron last month said its gas sales to PTTEP PCL for 2010 were 20% higher than contracted as solid economic growth generated stronger demand, particularly from the electricity and industrial sectors.
Chevron Thailand Exploration Pres. Pairoj Kaweeyanun said PTT last year took average gas delivery of 1.5 bscfd from Chevron, compared with 1.24 bscfd stated in its contract.
Kaweeyanun said Thailand's gas demand will likely rise 12% to 4.5 bcfd this year, and 3-5% next year.
Chevron is operator of Platong Gas II with a 69.8% stake while Mitsui Oil Exploration Co. Ltd. holds 27.4% and PTTEP has 2.8%.
Albanian gas-condensate field to be developed
Albania's Ministry of Economy, Trade, and Energy formally approved development of Delvina gas-condensate field in southern Albania.
The approval allows Stream Oil & Gas Ltd., Calgary, to enhance production and sell petroleum products under state Albpetrol's existing license for 25 years with 5-year extension increments.
Delvina, near the border with Greece and 100 miles south of Tirana, was discovered in 1987.
Two wells yield a combined 700 Mcfd of gas and 47 bbl/MMcf of 62.5° gravity condensate from fractured Cretaceous-Paleogene carbonates at 2,800-3,500 m. A pipeline connects the field to a refinery in the Tirana area.
Stream's 2011 plan includes reworking the two existing wells and preparing to drill a horizontal well. Management is preparing to evaluate NGL potential upside, future horizontal well plans, and NGL development.
PROCESSING — Quick TakesHovensa plans partial shutdown of St. Croix refinery
Hovensa LLC reported plans to shut down certain processing units on the west side of its 500,000-b/cd refinery at St. Croix, US Virgin Islands. The shutdown will reduce the facility's crude distillation capacity to 350,000 b/cd, with no impact on the capacity of its coker or fluid catalytic cracking unit, the company said.
The reconfiguration will be completed in this year's first quarter, Hovensa said.
The company also is in the process of determining its workforce needs going forward, it said. In the interim, the company reported, it "has placed an immediate hold on filling most open positions and cancelled the 2011 turnarounds previously scheduled for west side units that will be shut down."
Hovensa Interim Chief Operating Officer John W. George said, "Simplifying our operation by eliminating some older, smaller process units is expected to result in improved efficiency, reliability, and competitiveness. This is an important step toward improving our performance at a time when Hovensa and the refining industry are facing difficult economic conditions."
Hovensa is jointly owned by Hess Corp. and Petroleos de Venezuela SA (PDVSA).
Bulgarian refinery to add hydrocracking units
Burgasnefteproekt EOOD, OAO Lukoil's engineering subsidiary, has let a contract to Technip, Paris, for the first phase of a heavy residue hydrocracking complex to be built at the 115,240-b/cd refinery in Burgas, Bulgaria, along the Black Sea.
The lump sum services contract is worth 70 million euros. It covers detailed engineering and procurement services for a 2.5 million ton/year residue hydrocracker based on Axens H-Oil process, as well as amine, sour water stripper, and hydrogen production units.
Technip's operating center in Rome will execute the contract. Completion is set for May 2013. The group successfully completed the front-end engineering design contract for the project. Burgas is Bulgaria's only refinery.
TRANSPORTATION — Quick TakesTransCanada proceeds with Cushing-to-GC oil line
TransCanada Corp. will proceed with its Cushing Marketlink crude pipeline project, having received sufficient market support in the project's open season. Cushing Marketlink will have capacity to move 150,000 b/d from Cushing, Okla., to the US Gulf Coast. TransCanada expects the project to be in service first-quarter 2013, subject to regulatory approval.
TransCanada concluded its open season for the Bakken Marketlink Project to deliver US-sourced crude from Baker, Mont., to Cushing, Okla., earlier this month (OGJ Online, Jan. 21, 2011). Both Bakken Marketlink and Cushing Marketlink will use pipeline facilities forming part of TransCanada's Keystone XL system. Combined the two projects will transport up to 250,000 b/d of US crude oil production to the Gulf Coast.
Copano to build Eagle Ford NGL pipeline
Copano Energy LLC entered into a long-term fractionation and product sales agreement with Formosa Hydrocarbons Co. Inc. and, to facilitate deliveries of mixed NGLs to Formosa, also formed a 50-50 joint venture with a subsidiary of Energy Transfer Partners to construct, own, and operate a 12-in. OD NGL pipeline (Liberty Pipeline).
Liberty Pipeline will extend about 83 miles, from Copano's Houston central gas processing complex in Colorado County, Tex., first to Formosa's leased NGL product storage facility in Matagorda County, Tex., and then to Formosa's petrochemical facility in Calhoun County, Tex.
The agreement provides Copano with up to 37,500 b/d firm fractionation services beginning first-quarter 2013 for a term of 15 years. The agreement also provides that Formosa will purchase the resulting NGL products and make product storage available to Copano for operational reliability.
Following completion of Liberty Pipeline, expected by summer of this year, and until additional facility improvements at Formosa are complete, Copano will have access to a minimum of 5,000 b/d of existing Formosa fractionation capacity, as well as additional capacity on a "space available" basis.
Liberty Pipeline will have initial capacity of 75,000 b/d, committed to Copano and Energy Transfer (50% each) under firm agreements. Copano and Energy Transfer will together invest about $52 million for the pipeline and related facilities.
Copano said the agreements would increase its total Eagle Ford NGL handling capacity to more than 80,000 b/d.
Eagle Ford Gathering LLC (EFG), a joint venture of Kinder Morgan Energy Partners LP and Copano, earlier announced plans to construct 85 miles of 24-in. and 30-in. OD pipeline to move natural gas produced in the Eagle Ford shale by SM Energy Co. from La Salle, Dimmit, and Webb counties in Texas to the Freer compressor station in Duval County, Tex., for transport on KMEP's Laredo-to-Katy (LK) pipeline. The LK line will in turn transport gas to Copano's Houston Central complex.
Chesapeake Energy reached 10-year agreements in December 2010 with Enterprise Products Partners LP providing Chesapeake with gas transportation, processing, and NGL processing and fractionation services for its Eagle Ford production.
Ireland approves Corrib gas line's onshore segment
Ireland's planning authority, An Bord Pleanala (ABP), has granted permission for construction of the 9-km, 20-in. OD onshore segment of the Corrib gas pipeline. In its detailed determination, ABP stated the pipeline "would help safeguard the energy security of the state, would benefit the western region of Ireland, would not seriously injure the amenities of the area, would not be prejudicial to public health or safety, and would not be likely to have significant effects on the environment."
Partners in the Corrib gas project, Shell E&P Ireland Ltd., operator, 45.5%; Statoil Exploration, 36%; and Vermillion Energy Trust, 18.5%, say that at peak production, Corrib will supply as much as 60% of Ireland's gas needs.
Corrib, with 1 tcf of gas in place, expects production to peak at 300 MMcfd for 2-4 years before a 20%/year decline ensues (OGJ Online, June 25, 2009).
Allseas' Solitaire laid the 83-km, 20-in. OD offshore section of the pipeline from Corrib at 355 m water depth, through Broadhaven Bay, to landfall at Glengad, County Mayo, in summer 2009.
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