Ecuador expects to raise block 6 gas output by 61% next year

QUITO -- Ecuador expects to increase its natural gas output in block 6, in the Amistad field, by 61%, to 100  Mcfpd by the end of next year, state run company Petroecuador said.In a press release, the company said four new development wells will be drilled in the field, thanks to a rented rig that recently arrived in Ecuador and expected to start operations in December.
The rig was rented by Petrex, a unit of Italy's Eni, that will run the operations over 18 months.
The cost of renting the rig is about $48 million and includes perforation of two additional exploratory wells and a workover of another two.
Petroecuador also aims to raise gas production from the field to 85 Mcfpd from the current 62 Mcfpd by the end of this year.
Last March, Petroecuador said it had upgraded the size of the reserves in the Amistad field to about 1.7 Tcf of natural gas, following a review and reinterpretation of seismic testing in the Amistad Norte, Santa Clara, BBJ, BBJ Sur and Amistad Suroeste areas.
The Amistad gas field was formerly operated by a local unit of Noble Energy, but Petroecuador took it over after the U.S. company refused in 2010 to change its production sharing contract to a new service agreement.

Cnooc and CPC plan joint deepwater exploration pact

TAIPEI -- State controlled energy firms in China and Taiwan are preparing to jointly explore for natural gas in deepwater in the Taiwan Strait, having failed to make significant shallow-water finds despite nearly a decade of prospecting together.
Chinese oil and gas giant Cnooc and CPC are now drawing up a pact to jointly explore the northern end of the 180 km wide Taiwan Strait, and may invite a foreign partner to join them, a CPC official told the Wall Street Journal. He declined to be named.
Energy-deficient China's search for offshore oil and gas reserves has pit it against several of its neighbors, resulting in naval jousting with Japan, Vietnam and the Philippines near disputed islands and atolls.
CPC has been working with Chinese oil companies in several overseas exploration ventures for over a decade. But since China friendly Ma Ying Jeou became Taiwan's President in 2008 and the subsequent signing of a landmark trade pact with China, both Beijing and Taipei have been expanding economic cooperation.
Large gas reserves have already been found in undisputed Chinese waters south of Hong Kong by Husky Energy, working with Cnooc's listed unit, Cnooc. Gas from their Liwan field is due to be piped onshore from late 2013.
No other major discoveries have been made in the South China Sea since then, and in the meantime China's energy deficit has resulted in soaring natural gas imports in the first nine months of 2012 they rose 35.5% to 30.5 Bcm.
Taiwan imports more than 95% of its energy needs, shipping in 14 to 15 Bcm of LNG annually, mostly from Qatar, Indonesia and Malaysia.
The new Cnooc-CPC project follows the failure a 2002 Cnooc-CPC joint venture to find gas under shallow waters in the southern end of the Taiwan Strait and the Chaozhou Shantou Basin off the coast of China's Guangdong province, officials at the two energy firms said. That deal is due to be terminated later this year.
Under the new deal, the CPC official said, Cnooc and CPC will explore off the coast of Keelung and Hsinchu counties of Taiwan. A formal agreement is expected by late 2013.
Cnooc is transforming itself from a shallow water domestic oil producer to a global player with deepwater, unconventional and conventional hydrocarbon assets in countries ranging from Uganda to Argentina and the United States
In July, Cnooc agreed to acquire Nexen for $15.1 billion, which if approve by the government will allow it to absorb deepwater drilling technology Nexen is using in six Gulf of Mexico prospects.
Cnooc is now working domestically with foreign partners in at least 11 deepwater projects in an effort to grow its oil and gas reserves at home.
All foreign companies exploring in deepwater in South China Sea have signed production sharing contracts with Cnooc, which retains the right to take a majority interest in any commercial oil or gas discovery.
However, it isn't clear what arrangement will apply to the new Cnooc-CPC joint venture. Among international energy majors active in the South China Sea are Chevron, BP and ENI.

Occidental awarded $1.77 billion in Ecuador case

WASHINGTON DC -- A World Bank arbitration tribunal has aawarded Occidental damages of $1.77 billion in a claim the United States oil company brought against the government of Ecuador, according to the ruling posted on the International Centre for Settlement of Investment Disputes website.
The Washington based arbitration tribunal ruled that Ecuador illegally nullified Occidental's exploration and production rights in 2006, violating the Ecuador Bilateral Investment Treaty.
The country violated the treaty by "failing to accord fair and equitable treatment to Occidental's investment," and by "expropriating" the company's investment, according to the written ruling released by the tribunal.
Ecuador canceled Occidental's operating contract in May 2006, during the administration of President Alfredo Palacio, alleging that Occidental broke the terms of its contract by transferring a 40% stake to Encana without obtaining approval from the country's energy ministry.
The tribunal agreed that Occidental did fail to get approval for its farm out agreement, so the $1.77 billion award is a 25% reduction from what the tribunal otherwise would have awarded.
The tribunal also ordered Ecuador to pay interest on the award at the rate of 4.188% per year, compounded annually from May 16 of 2006. Ecuador's government, currently led by President Rafael Correa, has taken a hard-line stance with resource-extraction companies operating in the Andean nation, legislating to increase the government's control of production.
Mr. Correa told to reporters in Quito that the Andean country would ask for the ruling to be declared null. Mr. Correa said the country is reviewing the ruling, although there are "unacceptable things" and his government "will appeal" the tribunal decision and "will ask to annul it."
Previously, the office of Ecuador's attorney general said the government "categorically rejects this award," claiming the annulment of Occidental's contract in Ecuador was "in compliance with our domestic laws and the contract." The attorney general's office said it will make an official announcement, although it added Ecuador respects domestic and international laws and investment treaties.
Raymond James analyst Pavel Molchanov said the tribunal has no mechanism to enforce its ruling if Ecuador doesn't comply. The Ecuadorean government previously has said it would pay up to $417 million, and Mr. Molchanov said Occidental may be unable to recover more than that.
I think Occidental is going to find it very difficult to make Ecuador pay anything more than what Ecuador wants to pay, he said.

GE technology to power Cheniere Energy’s LNG export facility in Louisiana

LONDON -- GE Oil & Gas will supply gas compression trains for Cheniere Energy’s Sabine Pass liquefaction expansion project in Cameron Parish, La., about 170 miles west of Baton Rouge. Adding liquefaction capabilities will transform the existing Sabine Pass LNG terminal into the first LNG terminal capable of importing and exporting LNG in the U.S.

GE will supply 12 PGT25+G4 aeroderivative gas turbines to drive the first two liquefaction trains of the Sabine Pass Liquefaction Project currently under construction. Each train will have the capacity to produce approximately 4.5 million mtpa of LNG. Cheniere has received regulatory approvals from the Federal Energy Regulatory Commission to construct up to four liquefaction trains at Sabine Pass. Cheniere is expected to reach a final investment decision on its third and fourth liquefaction trains in the first quarter of 2013, with construction of those trains expected to commence shortly thereafter.
GE’s PGT25+G4 aeroderivative gas turbine, which has been selected for the Sabine Pass liquefaction project, features high efficiency and reliable performance. The G4—derived from CF6 aircraft engines—contains a rugged GE high-speed 34-megawatt gas turbine, the LM2500+G4, coupled with a two-stage high-speed power turbine module with increased flow capacity. A highly efficient machine for mechanical and generator drive applications, the PGT25+G4 was developed based on GE’s extensive experience with heavy-duty gas turbines.
“We’re pleased that our well-proven technology has been selected for the Sabine Pass liquefaction project. We have been able to build a strong presence in the LNG sector by leveraging our gas turbine, compressor and offshore production technology for many of the world’s leading LNG projects,” said Prady Iyyanki, president and CEO—turbomachinery for GE Oil & Gas.
“Technology innovation and economies of scale have been the two key contributors to the oil and gas industry's progress. GE Oil & Gas has played a key role in the evolution of LNG technology. Our sustained commitment to innovative design and world-class engineering and our production and testing capabilities have allowed us to push the envelope of highly reliable, advanced LNG solutions,” added Iyyanki.

Uruguay signs $1.65 billion in offshore exploration deals

MONTEVIDEO -- Uruguay's government has signed offshore exploration deals with four oil and gas companies that have committed to invest $1.65 billion over the next three years.
The companies include BP, BG, Total, and Ireland's Tullow Oil. They will join Uruguay's state-owned energy company, Ancap, to explore in eight offshore blocks, according to a statement on the Uruguay president's website.
The blocks are located in waters that range from 500 m to 2,500 m deep. BP and BG will each explore three blocks, while Total will explore one and Tullow another.
"This is the most significant event in the search for energy resources in recent years," Industry, Energy and Mining Minister Roberto Kreimerman said in the statement.
Mr. Kreimerman said the projects aim to diversify Uruguay's energy matrix. "We have the chance for a country that is not an oil producer to have new wealth through this exploratory work, which will be done over the next three years, as well as the exploitation that follows," he said.
Mr. Kreimerman expects the drilling work to begin in mid-2013. He also said that by 2015 half of Uruguay's energy matrix will come from renewable energy.

Tanzania delays offshore oil and gas licensing round

KAMPALA, Uganda -- The Tanzanian government said that it would delay a licensing round for up to nine deep sea oil and gas blocks, previously slated for this month, to allow parliament first to ratify a new natural gas policy next month.
In a statement, the state-run TPDC said that the delay will allow the policy to be ratified before the start of the next round.
"As TPDC is the key player in the preparation and consultation of this policy document, their management and staff will be unable to attend the previously scheduled roadshow events throughout september and october," TPDC stated.
The licensing round will include nine blocks sitting between 1,200 m and 3,500 m of water depth. The blocks on offer include new areas and blocks that have been relinquished by current operators.
According to TPDC, despite the postponement, bid round data packages will be available for review and purchase by the end of september. "This will allow potential investors in Tanzania an extended the time period to evaluate the technical data and assess the prospectivity of the nine blocks on offer," TPDC said.
Tanzania continues to attract international oil and gas companies following a spate of huge natural gas discoveries. In june, the country announced that new natural gas discoveries had pushed its reserve estimates up to 28.7 Tcf from 10 Tcf.
The East African nation is trying to revamp its natural resource laws and policies to ensure that it "benefits" more from the recent gas discoveries.
In July, the government announced that it would renegotiate the production-sharing agreement with Pan African Energy, which operates the country's largest gas field Songo Songo to enable TPDC to get "better profit-sharing arrangements".
Among the companies with oil and gas exploration licenses in Tanzania are ORC, Statoil and Exxon Mobil.
The United States geological survey estimates that East Africa's coastal region holds up to 441 Tcf of natural gas.

U.S. offshore leasing plan limited to explored areas of Gulf of Mexico and Alaska Arctic

WASHINGTON – Secretary of the Interior Ken Salazar and Bureau of Ocean Energy Management (BOEM) Director Tommy Beaudreau today announced the release of a proposed final offshore oil and gas leasing program for 2012-2017 that is mostly limited to the already-explored areas of the Gulf of Mexico and Alaska Arctic.
The 15 scheduled potential lease sales contained in the plan will occur in six planning areas – the Western and Central Gulf of Mexico, the portion of the Eastern Gulf Of Mexico not currently under Congressional moratorium, and the Chukchi Sea, Beaufort Sea and Cook Inlet Planning Areas offshore Alaska.
In the Central and Western Gulf of Mexico Planning Areas, the Proposed Final Program includes annual area-wide sales of all available, unleased acreage, as has been the typical practice in the Central and Western Gulf of Mexico. Additionally, two sales are scheduled within a portion of the Eastern Gulf of Mexico Planning Area.
The Proposed Final Program re-affirms existing protections for Arctic coastal areas by continuing to exclude certain areas from leasing, including a 25-mile buffer area near the coast of the Chukchi, as well as two subsistence whaling areas in the Beaufort near Barrow and Kaktovik, Alaska. The program also identifies an additional exclusion area in the Chukchi, near Barrow, that will not be made available for leasing because of input received from Native Alaskan communities and because the area is known to be of particular importance for subsistence hunting and fishing. With respect to all other areas in the Arctic that are open to oil and gas exploration and development in the Proposed Final Program, BOEM will identify targeted areas to offer in the lease sales based on information the agency will gather about industry interest, resource potential, subsistence hunting and fishing, wildlife, and environmental sensitivities.
As is mandated by the OCS Lands Act, the Proposed Final Program has been submitted to Congress. The Secretary may implement the Program in 60 days, however no further action is needed prior to its implementation, and BOEM is on track to hold the first sale under the new program later this year. Earlier this month, BOEM held a lease sale for nearly 39 million acres in the Central Gulf of Mexico, which attracted more than $1.7 billion in high bids for more than 2.4 million acres. That follows on a Western Gulf of Mexico lease sale held in December 2011, in which 21 million acres were offered for lease.

Eni starts up gas production offshore Egypt

ROME -- Eni has started production of gas from the offshore field of Seth, located in the Ras El Barr concession, approximately 37 miles (60 kilometers) from the Mediterranean coast of Egypt.

After an initial ramp-up phase, the field will produce approximately 4.8 million cubic meters of gas per day, of which Eni's equity 1.7 million cubic meters (approximately 11,000 boepd). The partners of the Ras El Barr license are Eni (50 percent), through its subsidiary IEOC, and BP (50 percent) as operator.

The Seth project, whose construction and operations has been assigned by Eni and BP to Petrobel, a joint venture between IEOC and the Egyptian state company EGPC, consists of a platform placed at a water depth of 262 feet (80 meters), two production wells and a pipeline of 6.8 miles (11 kilometers). The pipeline links the platform to the onshore processing facility in El Gamil, which handles around 20 percent of the gas produced in Egypt, through the existing transport network.

The development of this project is further evidence of Eni's involvement in Egypt and its contribution to satisfying the growing gas demand in the country through the exploration and development of gas reserves in the Mediterranean Sea.

Eni is the leading foreign oil operator in Egypt with total operated production of approximately 236,000 barrels of oil equivalent per day in 2011. Eni operates in the country through IEOC, which directly executes the exploration activities and participates in the production activities through joint ventures with the Egyptian state company EGPC.

Petrobras Argentina makes second major discovery in Santa Cruz

BUENOS AIRES -- Petrobras Argentina, the Argentine unit of Brazil's oil and gas company Petroleo Brasileiro, has found an estimated 6 MMboe in the province of Santa Cruz.
The discovery is the second at Petrobras's Estancia Agua Fresca concession in the province, where it already produces almost 3,000 bopd and close to 3.2 MMcfd.
Petrobras Argentina operates the concession and is a 50% shareholder in it along with Compania General de Combustibles, according to a statement Petrobras Argentina sent to the Buenos Aires Stock Exchange Tuesday.
In November, Petrobras Argentina said it would invest $800 million over the next four years in Santa Cruz.

Technip awarded contract for Ichthys FPSO unit

PARIS - Technip was awarded a services contract for the Ichthys floating production storage and offloading (FPSO) unit. The FPSO unit will be located in the Browse basin, Western Australia, at a water depth of 250 m. Technip will provide these services to Daewoo Shipbuilding & Marine Engineering (DSME).

This contract covers detailed engineering and procurement assistance for the topsides(1) facilities of the 1.2-million-bbl storage capacity Ichthys FPSO.

The Ichthys LNG project is a joint venture between INPEX (operator) and Total. Gas from the Ichthys field, in the Browse basin approximately 200 km offshore Western Australia, will undergo preliminary processing offshore to remove water and extract condensate. The condensate will be pumped to the FPSO facility anchored nearby, from which it will be transferred to tankers for delivery to markets.

The gas will then be exported to onshore processing facilities in Darwin via an 889 km subsea pipeline. The Ichthys LNG project is expected to produce 8.4 million tonnes of LNG and 1.6 million tonnes of LPG per annum, along with approximately 100,000 bbl of condensate per day at peak.

RIL scouts for additional shale gas assets

NEW DELHI -- Reliance Industries, India's second largest company by market value, is scouting for more shale gas assets in the US, Canada and Poland, investment bankers working on the potential assets said.

"RIL is looking for large shale gas assets, which will need investments of anywhere between $500 million and $2 billion," one of the bankers looking for assets said. The company has chosen not to appoint a specific investment bank, but has given indications to bankers to scout for such assets. "They have hinted at looking at assets brought to the table."
"We will not comment on market speculation," RIL spokesperson said in a email response. Shale gas will strengthen energy security for the US to a net exporter in several years.

RIl, which has more cash of R70,252 crore than its debt, has raised $1.5 billion as long-term loans through its US subsidiary Reliance Holdings USA. RIL had invested in excess of $3.5 billion for three shale gas assets in the US in the past few years.

The company has invested $2.14 billion in Pioneer shale gas fields, $1.04 billion in Chevron's shale gas field and $0.59 billion in Carrizo fields. "There has been been a seven-fold increase in RIL's share of gross production," the company told its shareholders on its website.

"Petroleum and refining, which will be the core of RIL, will be a capacity driven business with no chances of growth year after year," said Alok Deshpande, oil and gas analyst at Elara Capital, a brokerage. "In exploration and production, even with low investment, they can get a good find which can be their future growth avenues."

The US energy department is now accessing how exports could affect job creation, trade and domestic price of natural gas and is expected to release a report later this year. Some companies have been allowed to export gas in small quantities.

Cheniere Energy has been allowed to supply 3.5 million tonnes of liquid gas every year from 2017 to India's largest gas distributor Gas Authority of India. Other gas producers are pushing for exports.

The demand for gas could come from China, Japan and India. "China's large shale gas reserves could even be bigger than North America's, yet the country is arranging long-term natural gas supplies via ships and new pipelines," Peter Voser, Royal Dutch Shell's chief executive, said at an industry conference in Malaysia on June 5. "Between now and 2050, we see energy demand will double and gas will play a much larger role in meeting that demand."

The rise in Japan's demand is triggered by the closure of n-power plants following the 2011 Fukushima Daichi nuclear accident as it switches to gas to generate electricity. As India's demand for gas overshoots supply, many oil companies are scouting for gas field assets across the globe to reduce energy deficit.

On March 30, 2012, India's largest hydrocarbon explorer Oil and Natural Gas Corp signed an agreement with ConocoPhilips, America's third-largest energy company, to cooperate in areas including equity partnership in shale gas assets and deep water oil and gas exploration blocks. The Indian company will ride on the technological expertise of the US company.

RIL acquisition of shale gas assets have given them an early mover advantage with their peers in the US. One, it gives enough time to gain technological expertise and, two, prepare itself to bid for shale gas assets in India. Petroleum minister Jaipal Reddy told parliament on March 13, that his ministry is working on a strategic policy on shale gas assets and will be finalized by end of 2013 fiscal.

Chinese companies have invested roughly $17 billion in shale gas assets in the US to gain expertise before it starts exploring in their home country.

The Financial Express

Sinopec mulling large buy of Chesapeake Energy assets

OKLAHOMA CITY -- China Petroleum & Chemical Corp., or Sinopec, is considering a multi-billion-dollar purchase of Chesapeake Energy Corp. assets, and has conducted due diligence on the matter, the Financial Times reported Wednesday on its website, citing people familiar with the move.
Sinopec Chairman Fu Chengyu was in Oklahoma this week as part of the company's due diligence, the newspaper reported.

U.S. Central Gulf lease sale drew $1.7 billion in winning bids

HOUSTON  - U.S. Interior Secretary Ken Salazar said Wednesday that the first lease sale in the central U.S. Gulf of Mexico since the Deepwater Horizon oil spill drew $1.7 billion in winning bids from energy companies.
The central area of the Gulf is considered the most promising by the oil and gas industry, and has yielded a huge bounty of oil in the past two decades. It is also where in 2010, a well blow-out destroyed the Deepwater Horizon rig, killed 11 and unleashed the largest offshore spill in U.S. history.
The high demand for drilling leases in the central region underscores both its potential and the eagerness of oil and gas companies to ramp up activities in the area after months of acrimonious exchanges with U.S. authorities over tough revisions of drilling regulations.
The sum of winning bids is the fourth largest raised in a lease sale for the central Gulf, which includes waters off the coast of Louisiana, Mississippi and western Alabama. It is also the largest amount in bids in a sale held after the Deepwater Horizon incident. In December, a lease sale in the less developed western part of the Gulf raised $337 million.
Mr. Salazar, who called the sale "record-breaking," said the interest is "proof positive" that the oil and gas industry is confident it can meet new drilling rules put in place following the 2010 accident.
"The Gulf of Mexico is a crown jewel for oil production," Mr. Salazar said, adding that the total bids indicate that " this is the right place to be."
Norway's Statoil ASA (STO) offered the highest single bid, $157 million, for a block in the Mississippi Canyon area, Salazar said. Anglo-Dutch oil giant Royal Dutch Shell Plc (RDSA) submitted the highest total value of bids, $406.5 million.
If fully developed, the U.S. government estimates that the leases for sale could result in the production of up to 1 billion barrels of oil and 4 trillion cubic feet of natural gas.
At Wednesday's lease sale, 56 companies made 593 bids on 454 blocks. There were 7,250 blocks up for lease, comprising 39 million acres.
Several environmental groups filed suit in federal court seeking to block Wednesday's sale, including Oceana, the Center for Biological Diversity, Defenders of Wildlife and the Southern Environmental Law Center.
"It's premature to increase drilling in the Gulf before we know how much damage has already been done to the ecosystem," said Jacqueline Savitz, vice president for North America at Oceana. "The big question remains--can endangered species like sea turtles, and commercially important ones like Bluefin tuna, handle more drilling?"
Since 1954, the U.S. government has conducted 112 offshore lease sales, including Wednesday's sale.
The record bid for a U.S. Gulf of Mexico lease came in 1973 when a consortium of Mobil Oil Corp, Champlin Petroleum Co. and Exxon Corp. bid $212 million for a block off the Alabama coast. But entering the winning bid hardly guarantees a big payout for companies. That particular block, known as Destin Dome 162, came up with seven dry holes drilled by the companies.
In another instance, in the 1960s, Texaco Inc. spent more than $280 million on acreage that turned out to be light on oil but heavy with natural gas, which at the time was less desirable to exploration and production companies.
Another firm, Pennzoil Co., was unable to develop all of the acres it successfully bid on in the early 1970s, leading the company to sell the leases or bring in partners to develop them.

Ernst & Young: Banner year for growth through drilling

HOUSTON -  As a result of strong oil prices and technology advances making domestic shale resources accessible, the US oil and gas industry had a banner year for growth across several categories. Combined exploration and development spending increased 38% in 2011, according to Ernst & Young's annual U.S. E&P benchmark study. Oil reserves grew by 9%, or 1.7 billion barrels, in 2011, while oil production increased 3%. Gas reserves and production rose 4% and 9%, respectively in 2011. Oil and gas revenues experienced 23% growth in 2011.
"Long thought of as an oil region in decline, the combination of strong prices for oil and ever-improving technology has turned the US into a growth market," said Marcela Donadio Americas Oil & Gas Sector Leader for Ernst & Young. "The tremendous success of oil production in the Bakken formation, for example, is a true testament to the domestic opportunity and the industry's ability to act on that opportunity."
Capital expenditures
Total capital expenditures for the companies reviewed were down 16% as a result of lower property acquisition activity. But significant capital went into identifying new resources and developing existing reserves with an investment of $106.1 billion for exploration and development spending in 2011. The smaller independent producers led the growth in exploration and development spending with a 51% increase over 2010; while the large independents increased spending by 39% and the integrated oil companies increased their investments by 25%. Three companies increased exploration and development spending by more than $2 billion in 2011: large independents Occidental Petroleum and Chesapeake Energy along with Hess (an integrated). Ninety-six percent of the companies surveyed increased their capital budgets for exploration and development spending in 2011.
The cost to find and develop new reserves rose from $17.78 per BOE in 2010 to $19.38 per BOE in 2011, reflecting the higher cost of activity in the current economic environment.
Oil and gas reserves
End-of-year oil reserves increased 9% from 18.6 billion barrels in 2010 to 20.3 billion barrels in 2011. This growth was primarily driven by extensions and discoveries of 2.4 billion barrels, the highest level in five years. Oil production rose 3% to 1,403.5 million barrels in 2011.
The growth in oil reserves over the five-year period studied was driven by the independents and large independents with increases of 92% and 37%, respectively.
Led by development in unconventional shale gas or tight gas formations, natural gas reserves experienced a 4% increase to 178.2 Tcf in 2011, while gas production increased 9% to 12.9 Tcf.
"The year-over-year growth in US reserves is impressive," said Donadio. "Increases in exploration and production budgets in light of new potential resources create a very positive outlook for future production potential."
Revenues and profits
Strong oil prices drove a 23% increase in revenues from $147.8 billion in 2010 to $181.4 billion in 2011. US production costs, however, rose 27% in 2011 as the costs for labor, services and other expenses rose by $5.8 billion and production taxes increased $3.9 billion. After-tax upstream profits were $45.6 billion in 2011, an increase of 21% over 2010.

Myanmar inks oil exploration deals with international operators

YANGON -- Myanmar has signed a raft of oil exploration deals with foreign companies as the reformist government seeks overseas investment to spur economic development.
State-owned Myanma Oil and Gas Enterprise has inked nine agreements since early March to allow firms from Asia and Europe to explore for oil and natural gas, the Myanmar Ahlin newspaper reported.
"It was the first time in the history of Myanma Oil and Gas Enterprise to sign nine agreements within such a short period," the report said, without giving financial details.
"More significantly, Myanmar national companies were involved in all nine agreements as partners," it added.
The firms are EPI Holdings of Hong Kong, Geopetro International Holding of Switzerland, Petronas of Malaysia, Jubilant Energy of India, PTTEP of Thailand, Istech Energy of Indonesia and CIS Nobel Oil of Russia.
The report said the energy ministry had decided in principle to grant licenses to foreign companies to invest in Myanmar only if they cooperate with domestically owned firms.
It said 10 foreign companies were exploring for oil at 24 offshore energy fields, while eight overseas firms--as well as seven joint ventures with local companies--were exploring 20 inland fields.
"Many companies are contacting Myanma Oil and Gas Enterprise to explore for oil and natural gas by investing at other inland and offshore fields," it said.
Myanmar's reform-minded President Thein Sein said in a televised speech on Tuesday that economic development would be at the center of his next phase of reforms, which aim to boost the role of the private sector.

BP spill fine may hit $25 billion

HOUSTON--Federal regulators are seeking a settlement of $15 billion to $25 billion from BP PLC (BP) for the 2010 oil spill in the Gulf of Mexico from the ruptured Macondo well, according to report by the Financial Times over the weekend.
Analysts at Tudor Pickering Holt said the $25 billion figure is above what they have assumed BP's liability would be under the Clean Water Act. "It is encouraging that a dialog with the U.S. government appears to be open/ongoing and removal of the threat of criminal prosecution would be helpful to BP shares," analysts said.

ATP Oil & Gas resumes production at Gulf of Mexico Titan platform

ATP Oil & Gas Corporation said it has resumed production at the ATP Titan platform in the U.S. Gulf of Mexico, which was shut-in May 14 due to a temporary closure of a pipeline.
The Titan platform, which services the ATP's Telemark Hub, resumed production after the operator of the Mars pipeline temporarily completed the tie-in of a new platform, the company said in a press release. Production at Titan is proceeding as expected and will ramp up over the next few days, the company added.
ATP also announced that fracturing process on the Mississippi Canyon 941 A-2 well, which is part of the Telemark Hub, is expected to be completed before the end of June and that the well will be placed on production immediately.
ATP operates the ATP Titan and Telemark Hub which is in about 4,000 feet of water with a 100% interest.

ONGC discovers oil well in Golaghat

ONGC said it has discovered a new oil well in the Chalukpather area in Golaghat district and the oil major's Assam and Assam-Arkan basin has started drilling operations at the new site from Wednesday.
"Assam & Assam-Arakan Basin has commenced drilling operations in its new well at Chalukpather. The well will be drilled as a directional well with state-of-the-art technology, having a horizontal drift of 1,240 metres from surface location," said an ONGC official.
He added, "The well was formally spudded by Upper Assam commissioner Syed Iftekar Hussain in the presence of senior district authorities of Upper Assam districts and senior executives of ONGC. After its big find at Merapani in 2010, the ONGC is optimistic to strike it big in the nearby petroleum habitats."
Hussain said ONGC's operations in Upper Assam have resulted in significant development of the region's economy. "I wish all the best to ONGC for its petroleum business here and all communities here should share a sense of ownership with ONGC's operations, which leads to socio-economic development of local communities," he added.
ONGC's Assam & Assam-Arakan Basin manager S K Jain said ONGC is taking up exploration of oil and gas in Upper Assam aggressively. "This northeast basin is unique in the sense that there is both exploration and production of oil and gas. After a long time, the financial fortune of this basin, headquartered in Jorhat, is looking up. We are optimistic to sustain this healthy trend in the days ahead."
After the spudding of the well, a meeting was held between ONGC executives and senior district authorities. ONGC, recently crowned as the most admired company of the northeast, presented some sustainable socio-economic developmental programs to be undertaken in its operational locations to engage and enrich the local communities. The district authorities assured support to ONGC to deliver the programs professionally.
Evincing keen interest in oilfield operations of ONGC, Hussain volunteered for more such meetings between ONGC executives and district authorities on various administrative issues.

PetroMagdalena resumes production at Cubiro block

TORONTO -- PetroMagdalena Energy Corp. announced that production operations have resumed at its Cubiro Block located in the province of Casanare, with the blockade being lifted on the morning of Saturday May 5, 2012. As previously announced on April 24, 2012, public roads in the province of Casanare were being blocked and this led to a lack of public order in the area, impacting production from PetroMagdalena's Cubiro block.

No employees or contractors of the Company were involved. Discussions between all four levels of government are focusing on delivering a long term solution for the local communities.

Chevron begins operations on next-generation drillship in deepwater GOM

SAN RAMON, Calif. -- Chevron Corporation  announced that the Pacific Santa Ana, a deepwater drillship built to Chevron's specifications, has arrived in the Gulf of Mexico to work for Chevron under a five-year contract with a subsidiary of Pacific Drilling S.A.. Pacific Santa Ana is the first drillship designed with the capacity to perform dual gradient drilling (DGD).
"Pacific Santa Ana will enable us to demonstrate dual gradient drilling, which has the potential to change the way deepwater wells are drilled," said George Kirkland, vice chairman, Chevron Corporation. "This new process builds on our record of technology leadership in deepwater."
"The addition of Pacific Santa Ana as Chevron's fifth drillship in the deepwater Gulf of Mexico demonstrates our long-term commitment to developing America's energy resources," said Gary Luquette, president of Chevron North America Exploration and Production Company. "We are bullish on the Gulf, where robust energy exploration and development is vital to our nation's economy and energy security."
Unlike conventional deepwater drilling, which uses a single drilling fluid weight in the borehole, dual gradient drilling employs two weights of drilling fluid - one above the seabed, another below. This allows drillers to more closely match the pressures presented by nature and effectively eliminates water depth as a consideration in well design. DGD also allows drillers to more quickly detect and appropriately react to downhole pressure changes, which can enhance the safety and efficiency of deepwater drilling operations.
Pacific Santa Ana is equipped with a DGD riser, a mud lift pump handling system, six mud pumps - three for drilling fluid and three for seawater - extensive fluid management system enhancements and more than 72,000 feet of DGD-related cables. After additional equipment is installed and tested, Pacific Santa Ana will be used for exploratory and development drilling in the deepwater Gulf of Mexico.

Arsenal Energy Inc. completes drilling bakken, North Dakota wells

At Stanley North Dakota, Arsenal Energy, as operator, has completed drilling both the Anthony Robert and Wade Morris 2-mile horizontal Bakken wells. Each well encountered good shows while drilling. Arsenal has an approximate 84% working interest in each well. It is anticipated that both wells will be completed with multistage fracturing and placed on production by the end of June.
At Princess in Eastern Alberta, Arsenal has received approval from the Alberta Energy Board for waterflood of the Mannville Q pool. Water injection conversion and pipeline operations have begun. Arsenal anticipates that water injection will begin by the end of June and that waterflood response should become apparent within six months after that. Reservoir modeling indicates an incremental 470,000 bbl of reserves should be recoverable from the Q pool under waterflood. Arsenal has two additional Mannville pools of similar size at Princess that are in the application stage of the waterflood permitting process.

BG Group achieves first production from Bolivian gas field

BG Group announced Wednesday what it described as another key project delivery milestone for 2012 with the first phase of development at the Margarita gas field in Bolivia now on-stream.

"Margarita Phase I, delivered safely and to plan, will give BG Group additional net production of some 17,000 barrels of oil equivalent per day (boepd), taking total net production from Margarita to over 25,000 boepd," said BG Group Chief Executive Sir Frank Chapman.

"Already this year we have delivered new production from projects in Egypt, Norway and Thailand and, together with the successful start-up of Margarita Phase 1, these developments keep us on track with our programme to deliver average 6 percent to 8 percent per annum production growth through to 2020."

Margarita Phase I is expected to reach capacity in the second quarter of 2012. The project involved the construction of a new 48-mile (77-kilometer) network of gas gathering and export pipelines, four wells and gas processing facilities.

A second phase of development at the Margarita gas field was sanctioned in July 2011. Margarita Phase II, comprising the installation of a new processing train, flowlines and at least three additional development wells, will at capacity increase BG Group net production from the Margarita field to around 42,000 boepd by the end of 2014.

BG Group has a 37.5-percent interest in the Caipipendi block, which contains the Margarita gas field. (Repsol Bolivia 37.5 percent, operator, and PAE E&P Bolivia Limited 25 percent.)

Total CEO: Elgin top-kill job starting in a few days

PARIS -- Operations will start in a few days to "kill" a leaking natural gas well that forced Total SA to abandon and power down its North Sea Elgin platform, Total's Chairman and Chief Executive Christophe de Margerie said Thursday.
The group is also simultaneously drilling two relief wells in case the top kill job doesn't work, he said.
Total has lost around $2.5 million a day from loss of revenue and the costs to address the leak since March 25, when the leak was detected.
The two sorts of operations are "under control," de Margerie also said.

Brazilian Regulator: Chevron needs to show it can prevent spill before drilling again

HOUSTON -- Chevron Corp. won't be allowed to resume drilling in its Frade field offshore Brazil until it finds the cause of two recent oil spills in the area and shows the Brazilian government it can prevent another oil spill from happening, the head of Brazil's oil regulatory agency said Monday.
Chevron "has not identified yet the real cause of the problem," Magda Chambriard, president of Brazil's national oil regulator, ANP, told reporters on the sidelines of the Offshore Technology Conference in Houston. "The report we have [from Chevron] says that it is due to natural causes and natural causes can happen again."
Chevron's spill was smaller than the massive April 2010 Deepwater Horizon leak in the Gulf of Mexico, but that doesn't mean it wasn't a large spill or a major problem for Brazil, Chambriard said.
"It was a real disaster," she said. The incident resulted in the spill of 3,600 barrels of oil, she added.
The Brazilian government is in talks with Chevron and is conducting an investigation into the causes of the spill and it is "confident it can reach an agreement with Chevron," Chambriard said.
To prove that Brazil is not being especially tough on Chevron because it is an international company, ANP plans "to be even harder" with Brazil's state-run energy giant Petroleo Brasileiro SA, which is Chevron's partner in the field.
Chevron shut down operations at the Frade field in March to better study the geology of the area, which has come under scrutiny because of a series of oil seeps from the seabed.
Chevron is lead operator of Frade, which holds estimated recoverable reserves of between 200 million and 300 million barrels of oil equivalent, with a 51.7% stake.
Petrobras holds 30%, while the Frade Japao Petroleo Ltda. consortium has the remaining 18.3% share.

Canada's Pacific Rubiales to start producing oil in Peru

BOGOTA -- Canada-based Pacific Rubiales Energy Corp., the top private oil producer in Colombia, on Friday announced a $335 million deal with BPZ Resources that will allow it to start producing for the first time in neighboring Peru.
In a statement, Rubiales said it will acquire a 49% stake in Houston-based BPZ's offshore Z-1 Block in Peru. The block has two producing fields that averaged 3,800 barrels of oil per day last quarter, and has total proved oil reserves of about 34.7 million barrels.
BPZ has been seeking a partner for its Z-1 Block.
Rubiales said it will pay $150 million in cash and a commitment to pay $185 million for BPZ's share of capital and exploratory expenditures in Block Z-1.
"The acquisition complements our existing exploration acreage in Peru, and it provides us with first production in the country," said Rubiales Chief Executive Ronald Pantin.

Plans unveiled to drill world’s deepest well

HOUSTON -- Discussion of a plan to drill  in the seafloor more than 12,000 feet beneath the surface of the Pacific Ocean  impressed even the technical professionals at the Offshore Technology Conference, who already know a lot about doing complicated work under water.

The project,  scheduled for 2017 in the Pacific Ocean, would involve drilling a scientific well  to retrieve a core of the Earth’s mantle. It would bring the sample to the surface using a riser similar to the pipe that connects underwater wellheads to surface rigs.

If successful, it would drill in water as deep as 12,000 or 14,000 feet, well beyond the deepest drilling now, around 10,000 feet.
Nicolas Pilisi, an engineer for Blade Energy Partners, said the  greater water depths are accessible with changes in materials used and with additional power to move mud and other materials into and out of the hole.

While  steel risers used now are too heavy and pose a risk of buckling at greater depths, innovative designs using thinner risers, or ones made from titanium or aluminum, would offer strength and also cut down weight, Pilisi said.

Those advancements — which Pilisi said aren’t far from reality — could advance offshore capability, especially if the project settled for a more shallow site off the coast of Hawaii.

“Drilling and coring a scientific hole in the upper mantle is definitely possible,” Pilisi said. “A hole could be drilled today with the existing technology.”

Anadarko reports strong results from Utica program

HOUSTON -- Anadarko Petroleum Corporation provided an update on its drilling program in the Utica Shale play in eastern Ohio after filing the required production history with Ohio Department of Natural Resources. To date, the company has drilled and is producing from three wells in the Utica Shale, the most recent of which has delivered more than 9,500 barrels of light-gravity crude oil during its first 20 days on line.

"Though it is very early in our exploration program, the strong initial results are encouraging," said Bob Daniels, Anadarko Sr. Vice President, Worldwide Exploration. "We expect to begin flowing back our fourth Utica exploration well in the next few days and are currently drilling our fifth exploration well in the play. We plan to continue an active drilling program throughout the year, as we evaluate the liquids-rich potential of our 390,000-acre (gross) position in the Utica Shale."

Anadarko's Brookfield A-3H well in Noble County has produced approximately 9,500 barrels of oil and approximately 12 million cubic feet (MMcf) of high-BTU (British thermal units) natural gas during its first 20 days on line. The Spencer A-1H and Spencer A-5H wells, located in Guernsey County, have cumulatively produced a combined 20,000 barrels of light-gravity crude oil and 37 MMcf of liquids-rich natural gas in just under two months on line. All three horizontal wells were drilled to a vertical depth of approximately 6,500 feet and a lateral length of about 5,000 feet with 16- to 19-stage completions.

Anadarko operates the Brookfield and Spencer wells with a 100-percent working interest (82.5-percent net revenue interest) subject to a participation agreement with Artex Energy Group LLC.

Total weighing Elgin options

PARIS -- Total is still accessing its options with regards to plugging a large gas leak at a North Sea facility which the French major says is diminishing.

One of two rigs chartered with a view to drilling relief wells also continues towards the scene of the leak from the Elgin processing, utilities and quarters (PUQ) platform but will stand off at the perimeter of an exclusion zone, a spokesperson told Upstream on Monday.

Last week Total will send a team of well control experts b y helicopter to the leaking facility and, although they returned safely, the company has yet to decide on a plan to stop the leak.

Total is considering a ‘top kill’ procedure to plug the leak using drilling mud. Simultaneously it intends to begin drilling two relief wells which would be halted should the top kill job be successful.

Transocean’s Sedco 714 rig is en route to the scene, the spokesperson said. A broking source suggested last week that it would arrive on the scene on Sunday or Monday.

The Rowan Gorilla V has also been hired by the French company with a view to drilling relief wells.

Total shut in all production at its Elgin and Franklin fields following the discovery of the leak over two weeks ago. The oil major evacuated all 238 workers from the Elgin facility and the adjacent Rowan Viking.

Anglo-Dutch supermajor Shell also pulled all workers from its nearby Shearwater platform.

ConocoPhillips begins Browse basin campaign

Karoon Gas Australia Ltd's 2012 Browse Basin exploration drilling campaign has now commenced.
The Boreas-1 exploration well spudded at 02:30 (WST) on April 5, 2012. The proposed operation is to drill a 36" hole to planned casing point, then run and cement the 30" conductor prior to drilling ahead in a 17½" hole.

Boreas-1 is located approximately 2.5 miles (4 kilometers) south of Poseidon-1 in WA-315-P on a large tilted fault block which is part of the of the north-east trending structural high of the greater Poseidon structure. The objective of the well is to test the extent, presence and quality of reservoirs within the Boreas-1 fault block.

Boreas-1 Location:
• Latitude: 13 degrees 39' 24.87170" S
• Longitude: 122 degrees 17' 52.78733" E

UPCOMING WELL PROGRAM
The exploration program, operated by ConocoPhillips, plans to utilize the Transocean Legend (mid-water semisub) rig for the entire campaign and is expected to continue through 2013.

A minimum of five wells will be drilled during the exploration program. The principal objective of the exploration program is to better define the size and quality of the hydrocarbon accumulations within the exploration permits which contain the greater Poseidon trend.

The second well, Zephyros-1, is located in permit WA-398-P on a large tilted fault block approximately 5 miles (8 kilometers) south west of Kronos-1 discovery location. The third well, Proteus-1, is located in WA-398-P on a large tilted fault block approximately 9 miles (14 kilometers) south east of the Poseidon-1 discovery location.

Additional well locations for the remainder of the program will be announced as they obtain joint venture approval.

ConocoPhillips is the operator of the jointly held WA-314-P, WA-315-P and WA-398-P Browse Basin permits containing the previously announced Poseidon and Kronos gas discoveries. Karoon Gas Australia Ltd holds a 40-percent interest of permit WA-315-P and WA-398-P, and a 90-percent interest of permit WA-314-P.

Anadarko makes new gas find off Mozambique

HOUSTON -- Anadarko Petroleum Corp. has scored another success in the Rovuma basin, offshore Mozambique, with a new gas find at its Barquentine-4 appraisal well.

The Barquentine-4 well – located approximately 19 miles north of the Lagosta discovery well at the southern end of the Windjammer/Lagosta/Barquentine/Camarao gas complex – encountered 525 net feet of natural gas pay.

This is Anadarko's ninth successful well in the complex, which is part of the larger Prosperidade complex that is estimated to hold recoverable resources of between 17 and 30 trillion cubic feet of gas.

Worldwide upstream M&A unconventional resource spending reached record high $75 billion

NORWALK, Conn. – Fueled by national oil companies and international buyers making acquisitions in North American shale gas, shale oil and tight oil basins, global transactions involving unconventional oil and gas resources reached a record high $75 billion in 2011, according to the IHS Herold 2012 Global Upstream M&A Review, which was just released by information and analytics provider IHS (NYSE: IHS). This figure represents 48 percent of total 2011 worldwide upstream merger and acquisition (M&A) spending

“Cross-border buyers, led by Asian-based investors, continued to stream into North American unconventional resource plays through asset partnerships and select corporate deals, with a bullish view on potential LNG exports to the Asia-Pacific region in the coming decades,” said Christopher Sheehan, director of energy M&A research at IHS. “In 2011, high crude oil and international gas prices were juxtaposed against persistently depressed North American natural gas prices, leading to a 15-year high in deal counts outside North America.”
Total global upstream M&A transaction value, including corporate mergers, fell 30 percent from an all-time high in 2010, which was driven by massive asset divestiture programs. Corporate deal value in 2011 rose 19 percent to more than $58 billion, including BHP Billiton’s $15 billion takeover of unconventional resource-focused Petrohawk Energy, the first upstream corporate merger greater than $10 billion since the ExxonMobil-XTO deal in late 2009.
Sheehan noted the deal flow also increased in all regions outside the U.S. and Canada as international investors pursued the prolific oil discoveries that have occurred in recent years in regions such as deepwater Brazil and Africa. In Australia, the coal seam gas-to-LNG market consolidated further, and evolving markets such as Iraq’s Kurdistan region welcomed new entrants through M&A.
Said Sheehan: “These areas are enticing international investors who continue to face access barriers in established hydrocarbon basins such as Venezuela, Russia and in the Middle East. World-class oil assets continue to be highly sought after by both cash-rich national oil companies and international integrated companies that continue to struggle to materially grow reserves through the drill bit.”
In the international gas markets, growing Asian LNG demand will increasingly fuel merger and acquisition activity from Australia to East Africa. In these regions, Sheehan believes small-cap international E&Ps that own huge resources, but lack sufficient development capital, will increasingly be takeover targets, particularly as the European debt crisis has impacted their access to and the costs of capital.
U.S. transaction value in 2011 reached a 10-year high despite a lower deal count than the prior year, as large joint-venture asset acquisitions by overseas buyers fueled mergers and acquisition activity. The U.S. accounted for approximately 50 percent of global upstream M&A spending, well above its historical average. Producing oil assets commanded a large deal price premium to gas properties, with a growing focus on liquids potential in emerging basins.
“Established shale gas and emerging shale oil and tight oil plays in the U.S. are attractive to foreign buyers since these plays offer massive discovered resources with low exploration risk in a country with relatively high political and fiscal stability, versus other global regions such as the Middle East, Africa and Latin America. The longer-term potential of LNG exports to the Asia Pacific from Canada and the U.S. is a strategic driver of many of the cross-border shale gas acquisitions in North America,” Sheehan added.
Meanwhile, decade low deal pricing for conventional gas assets, and the upside from liquids-prone plays, attracted increased M&A spending by private equity buyers seeking to benefit from a longer-term North American natural gas price revival.
Continued uncertainty in commodity price direction, wide-ranging geographic oil and gas price spreads, fragile global economic conditions, and limited or higher cost access to capital for many upstream companies are challenging strategic decision making in the industry and causing a consensus gap between potential buyers and sellers.
Added Sheehan: “We believe that, in the present volatile environment, global upstream M&A consolidation will accelerate in 2012 and beyond as the well-financed ‘haves’ prey on the capital-constrained ‘have-nots.’ Many of the latter are key holders of massive undeveloped gas and liquids resources that can provide material growth opportunities or establish a strategic foothold in emerging basins. Consolidation, including a rise in corporate takeovers, will be led by national oil companies and sovereign-wealth funds, major integrated companies, global industrial conglomerates, and private-equity investors, who all seek opportunistic purchases of capital-intensive oil and gas assets and financially strained companies that own prolific resource potential.”
IHS provides comprehensive analyses of 2011 transactions and forward-looking insights into 2012 and beyond in the just-released IHS Herold 2012 Global Upstream M&A Review. This year, the study identifies thirty key regional plays across the globe that need to be on the radar of oil and gas M&A market participants, including buyers, sellers, advisors, and capital providers.
The regional profiles in each of the study sections are drawn from the IHS Herold Company Research module Regional Play Assessments (RPAs), which use IHS proprietary geological data to independently value the resource potential and investment opportunities in established and emerging oil and gas plays around the world. This research features detailed analysis of company well results, acreage positions, drilling activity, financial strength, play economics and company and asset valuations.

Exxon, BP, Conoco agree to initial Pt. Thomson gas production by early 2016

HOUSTON -- Exxon Mobil, ConocoPhillips and BP have agreed to start producing natural gas at their Pt. Thomson development in Alaska by May 2016 at the latest, according to a settlement agreement between the companies and the state of Alaska.
The oil companies will be allowed to continue developing Pt. Thomson in exchange for the commitment to begin producing natural gas and condensate by end of the winter season of 2015-2016. The initial production system, which could be later ramped up, is being designed to produce about 200 MMcfd of gas and 10,000 bpd of condensate. Also, a pipeline is being designed to move about 70,000 bpd of liquid hydrocarbons from Point Thomson that will help move the fossil fuels to the Trans-Alaska pipeline. The companies also agreed to "undertake work for commercialization of North Slope gas," the document said. The Alaska government has said it would like to see a liquefied natural gas development to ship local natural gas to Asia. If a deal to sell the natural gas hasn't been struck by June 2016, the companies agreed to expand the amount of natural gas condensate shipped to the Trans-Alaska pipeline by 20,000 to 30,000 bpd. Point Thomson gas could also be delivered to oil operations in Prudhoe Bay for injection into the large oilfield there, the document said. The agreement said that a "major gas sale off the North Slope of Alaska is a primary goal of the parties."
The settlement puts to rest a long-standing dispute between the oil companies and the Alaska government. In 2006, the state revoked the Point Thomson license it had assigned Exxon and its partners alleging they hadn't moved quickly enough to develop the resource.

BP, BG, Total, Tullow awarded blocks offshore Uruguay

MONTEVIDEO, Uruguay -- ANCAP received 19 offers for offshore oil exploration and production in 8 of the 15 offered blocks, by 9 of the 11 oil companies qualified for the bidding process. There was competition between three or more companies in 5 of the blocks offered. More than 50 percent of the area from the bidding process will develop exploration works by the four new companies (the British companies BP and BG, the French company Total and the Irish company Tullow Oil) that adds to the work already being done by Petrobras, YPF, and GALP in the Uruguayan offshore.
Blocks from the three Uruguayan offshore basins were awarded: the basins named Oriental del Plata, Punta del Este and Pelotas, this last who received particular interest from the oil companies.
After the assessment of the winning bids and the approval of the Uruguayan government ANCAP will sign the contracts with the winning companies with a deadline of September 2012.

LNG Energy completes Sling seismic program

CALGARY -- LNG Energy announced the successful completion of the 2011 "Sling" 2D seismic program on its 100 percent held PPL 319 licence, onshore Papua New Guinea.

PPL 319 is in the lowland area of the Papuan fold and thrust belt between several substantial oil and gas fields and is on-trend with Oil Search's Kutubu and Gobe producing oil fields. Ninety-one miles (148 kilometers) of 2D data was acquired during the periods April-June and October-December 2011, with interpretation in early 2012. The survey comprised 41 miles (67 km) of alluvial river flats around the Kikori River, 36 miles (59 kilometers) of karst limestone and 13 miles (22 kilometers) of volcanic terrain.

PPL 319 contains proven, mature Late Jurassic (Kimmeridgian) Lower Imburu Fm. source rocks that are presently generating hydrocarbons from local kitchen areas. It is believed that PPL 319 contains clastic reservoirs of Lower Cretaceous-Upper Jurassic age (Toro-Hedinia-Iagifu sandstones), particularly in the western part and the Kikori Bend area of the PPL 319 Licence. The company believes the presence of source, seal, reservoir and structural traps on PPL 319 are extremely prospective in this proven hydrocarbon trend.

There has been little exploration activity in PPL 319 over the 20 years prior to its acquisition by LNG, despite the prospective location of the licence. In 2010, LNG undertook a HRAM/AIRGrav survey, flown by Sander Geophysics Ltd that, among other structures, identified a large structure between PPL 319 and InterOil's PPL 237. This structure was subsequently confirmed by the 2010 2D Poroman seismic survey on the eastern boundary of PPL 319.

This aeromagnetic/gravity survey and the reprocessed Base Resources 1988 Victory Junction seismic data identified another prospective area referred to by LNG as the "Kikori Bend" area near the western part of PPL 319, on trend with the Gobe oil field. The 2011 Sling seismic survey was undertaken over the entire western section of PPL 319 including the Kikori bend area and clearly identified the Tuyuwopi prospect.

The extensional fault related prospects identified at Kikori Bend are early rift-related structures that exhibit little late stage structural movement. These preserved extensional traps have increased longevity and the proven Jurassic source rocks are in the oil window in this area. The traps are believed to have been charged early as oil was generated, have good top seals and are less likely to be affected by late stage uplift or subsequent gas charge. LNG believes the reservoir will be oil charged and is undertaking a detailed analysis of the traps identified. As with many PNG discoveries, LNG anticipates multiple pay zones in the sandstone reservoirs of Lower Cretaceous-Upper Jurassic age.

Logistically, PPL 319's Kikori Bend area is strategically placed in the lowlands with river, road and helicopter access. It is in close proximity to Oil Search's existing crude export pipeline and the Exxon LNG Gas line  which traverse part of PPL 319. Also within PPL 319 is Kopi base, a hub for Exxon and Oil Search's oil and gas development activities. In a country where logistics often define economics, PPL 319 and specifically the Tuyuwopi prospect are favorably situated.
"The Sling seismic program has identified the very attractive Tuyuwopi prospect. Given the location and surrounding hydrocarbon production trends, we are very encouraged by this target and are developing our work program around it," said Dave Afseth, President and CEO. "Additional leads have also been identified that will be further investigated."

FMC Technologies signs $1.5 billion pre-salt subsea tree agreement with Petrobras

HOUSTON -- FMC Technologies, Inc. announced today that it has signed a four-year agreement with Petrobras for the supply of pre-salt subsea equipment. The total award would result in approximately $1.5 billion in revenue to FMC Technologies if all of the subsea equipment included in the agreement is ordered. The initial call-off has an approximate value of $900 million in revenue to FMC and includes 78 subsea trees.

FMC’s total scope of supply could include the delivery of up to 130 subsea trees, subsea multiplex controls and related tools and equipment. The tree systems are for use offshore Brazil in water depths up to 8,200 feet (2,500 meters). The equipment will be engineered at FMC’s South American Technology Center and manufactured at FMC’s subsea facility, both of which are located in Rio de Janeiro, Brazil. The subsea trees will achieve 70% Brazilian local content and deliveries are scheduled to commence in 2014.

"We have made significant investments in our Brazilian operations to enable large scale product manufacturing and the development of new technologies,” said Tore Halvorsen, FMC’s Senior Vice President, Subsea Technologies. “Petrobras has awarded more than 500 subsea trees to our operations in Brazil over the past 30 years, and we are pleased to support them in developing their pre-salt reservoirs.”

BOEM releases Mid- and South Atlantic environmental impact statement for public comment

NORFOLK, Va. — Bureau of Ocean Energy Management (BOEM) Director Tommy P. Beaudreau has announced that the Department of Interior is taking steps to assess the conventional and renewable energy resource potential in the Mid- and South Atlantic. The draft Programmatic Environmental Impact Statement (PEIS), released for public comment, will help inform future decisions about whether, and if so where, leasing would be appropriate in these areas.
This milestone advances BOEM’s regionally-tailored approach to Outer Continental Shelf (OCS) exploration and development, consistent with the Proposed OCS Oil and Gas Leasing Program for 2012-2017, which stresses the importance of better understanding resource potential in the Mid- and South Atlantic. The draft PEIS assesses proposed geological and geophysical (G&G) activities, including seismic and other offshore surveys, in the Mid- and South-Atlantic planning areas.
Interior Secretary Ken Salazar and Beaudreau traveled to Norfolk, Va., where they met with personnel from Fugro Atlantic, which provides geotechnical, hydrogeologic, environmental and marine survey services.
“Both government and industry rely on G&G surveys, using state-of-the-art technology, for information about the location and extent of our offshore resources,” said Beaudreau. “This analysis will move us forward toward developing an updated body of scientific information about the Mid- and South Atlantic regions that will support future decisions about potential conventional and renewable resource development.”
The PEIS evaluates the potential environmental effects of multiple G&G activities in these OCS planning areas and, where needed, outlines mitigation and monitoring measures that will reduce or eliminate potential impacts.
To access the draft PEIS, go to www.boem.gov/oil-and-gas-energy-program/GOMR/GandG.aspx. The PEIS and related documents will also be available for public inspection tomorrow in the Federal Register at: http://www.archives.gov/federal-register/public-inspection/index.html.
Public meetings to receive comments are scheduled in Jacksonville, Fla.; Savannah, Ga.; Charleston, S.C; Norfolk, Va; Wilmington, N.C.; Annapolis, Md.; Wilmington, Del; and Atlantic City, N.J., to allow the public to comment on the draft PEIS and assist BOEM in developing the final PEIS. The complete public meeting schedule is available online at: www.boem.gov/oil-and-gas-energy-program/GOMR/GandG.aspx.

Total shares slump after 7 MMcfd North Sea gas leak

PARIS -- Following a three-day gas and condensate leak at its Elgin platform, French supermajor Total  said it could take several months to bring the leak under control, raising industry speculation of a huge payout bill.

Total says early reports of a subsea gas leak were incorrect and the leak is emanating at the surface at an estimated rate of 200,000 Cmd, and a 6-mile long trail of condensate has been seen on the water around the rig.

The Elgin facilities account for around 3% of the UK’s domestic gas supply.

Total said the leak may continue for up to six months, as this is how long the company estimates it will takes to drill an emergency relief well to plug the leak.

Meanwhile, Total’s share price has taken a pummeling on the French bourse, falling 6% Wednesday and a further 2.18% Thursday, over uncertainties of the costs to cap the well.

Should Total have to shut the Elgin field to cap the well, Total would take a EUR 5.7 billion hit in net present value terms, according to ratings agency Fitch, citing third party analysts. In cash terms Total has a EUR 2.6 billion stake in Elgin, and may have to reimburse its partners for their losses should responsibility for the leak fall in the operator’s lap.

WesternZagros discovers major oil column at Kurdamir-2, Kurdistan

WesternZagros Resources Ltd.  has reported a major oil discovery in the Oligocene reservoir at the Kurdamir-2 exploration well in the Kurdistan region of Iraq.
The Kurdamir-2 well has reached the intermediate casing depth of 2,812 m, and has drilled through the Oligocene interval. Wireline logs indicate a porous zone of 140 m thickness within the Oligocene interval, between 2,422 and 2,562 m, all of which is hydrocarbon bearing. Within this hydrocarbon zone, well log data indicates 22 m of gross natural gas pay above 118 m of gross oil pay. No evidence of water has been encountered within the Oligocene interval.
"We are excited to learn that the Kurdamir and adjacent Topkhana structures have a common oil leg in the Oligocene reservoir with the potential of containing a giant oil and gas field. We're even more excited by the fact that we don't yet know the full extent of the resources that the Oligocene, alone, contains," said Simon Hatfield, WesternZagros's Chief Executive Officer.
"Our 100% drilling success rate continues with this major oil discovery. The Kurdamir-2 discovery is the third high-impact discovery on our Blocks in ten months and is an important confirmation of our queue of high-quality, light oil exploration opportunities. In particular, our view is that this discovery significantly improves the oil potential of the deeper, as yet undrilled reservoirs in Kurdamir-2 and also those prospects adjacent to Kurdamir on our Garmian Block."
When the well reached a depth of 2,477 m, a drill stem test was conducted of the open hole from the base of the 13 5/8-in. liner at 2,315 m to 2,477 m, which included 55 m of the Oligocene porous zone. This test was conducted across the interpreted gas-oil contact at 2,444 m and tested 22 m of gas pay in contact with 33 m of oil pay. The test achieved a flow rate of 7.3 million cubic feet per day of gas and a stabilized flow rate of 950 bpd of 47°API mixture of light oil and condensate over the final seven hours of the main flow period. This rate was achieved through a 56/64-in. choke at an average flowing well head pressure of 650 psi and without any stimulation. There was no observed decline and no formation water was recovered during the testing.
The deeper Oligocene oil pay will not be tested at this time due to time constraints, as the well is required to drill and evaluate the deeper Cretaceous by the end of June 2012. The Company interprets these results as an additional successful confirmation of a significant oil column underlying the gas cap in the Oligocene reservoir. (The first confirmation was provided in Kurdamir-1 as disclosed in the Company's news release of December 16, 2010.)
The company interprets that since the test was conducted across the gas-oil contact, and the fact that gas flow impedes oil flow, the results do not represent the true oil rate potential of this interval. According to analysis by an independent third party engineering expert, the 33 m of oil pay tested to date is capable of flowing at rates of 4,000 bpd if isolated from the gas pay and stimulated. The Company is working with the operator, Talisman (K44) B.V., to examine options for additional cased hole testing focused on the full 118 m of gross oil pay in the Oligocene after the well has met the PSC commitments. The co-venturers are also planning a 3D seismic program and a further appraisal well to help determine the ultimate size of the Oligocene reservoir.

India awards 16 exploration blocks to local companies

NEW DELHI -- India's federal cabinet Friday approved the allocation of about half of the 34 oil and gas exploration blocks it offered for development through an auction in March 2011, while rejecting bids of companies such Essar Oil Ltd.
The South Asian nation had received bids for 33 of 34 exploration blocks auctioned in its ninth bidding round last year.
According to a government statement, the cabinet approved the award of 16 oil and gas exploration blocks and rejected bids for 14 other blocks in a late-Friday meeting. The government was to evaluate the bids and award the blocks within three months, and the entire process, including the signing of contracts, was expected to be completed within four months of the bidding round. However, because of certain security issues with some blocks the process of award delayed.
The auctions covered eight deep-water blocks, seven shallow-water blocks off both the eastern and western coasts, and 19 land blocks in Gujarat, Rajasthan, Tripura and Assam states.
India wants to fully explore its sedimentary basins by 2015, from about 65% explored so far, as it seeks to ramp up output to meet growing energy demand and reduce dependence on imports. India imports about four-fifths of its crude oil needs.
The cabinet approved award of two shallow water and two onland blocks to consortia led by ONGC. State-owned OIL led consortia got two onland blocks in the Assam-Arakan basin. Deep Energy walked away with two Cambay basin blocks while Focus Energy beat Reliance Industries to bag an area in Rajasthan. Five blocks were awarded to relative unknowns such as Sankalp Oil and Natural Resources, Pratibha Oil and Natural Gas Pvt Ltd and Pan India Consultants.