Crude-Oil Futures Settle Lower After Rise in Inventories

Crude-oil futures settled slightly lower Wednesday after a larger-than-expected rise in U.S. inventories stirred concerns about demand.

The federal Energy Information Administration said crude-oil stocks climbed 3.8 million barrels to 381.4 million barrels in the week ended March 1, well above the 500,000-barrel increase analysts expected. The stocks are at the highest level for this time of year in 82 years, as domestic production increased and demand from refiners eased during a period of seasonal maintenance.

"It's the same general theme we've been seeing: crude is plentiful, products are a little tight," said Kyle Cooper, managing partner at IAF Advisors.

The EIA data showed domestic crude production neared 7.1 million barrels a day, or 1.3 million barrels above the same week in 2012.

Refiners cut crude-oil processing by nearly 500,000 barrels a day to the lowest levels in almost two years. At current reduced processing rates of just above 14 million barrels a day, stocks are sufficient to meet nearly four weeks of refiner demand, the highest level in almost 20 years.

Mr. Cooper said seasonal refinery maintenance appears to be running longer than had been expected, and some companies are suffering unplanned outages at units, reducing supply of refined products like gasoline.

Light, sweet crude-oil futures for April delivery on the New York Mercantile Exchange settled 39 cents, or 0.4%, lower at $90.43 a barrel. The contract hit a low of $89.55 a barrel after the EIA data but recovered some losses after failing to break below the 2012 intraday low of $89.33 the front-month contract touched Monday.

Gene McGillian, broker and analyst at Tradition Energy, said he expects prices to consolidate around $90 for the near term, as traders look for clues on the pace of economic recovery and oil demand. U.S. oil use dropped 2.1% to a one-month low last week, EIA data showed.

"We've wiped out $8 from the price and if we continue to see slowing in economies in the U.S. and Europe, prices could go down to the mid-$80s," a level last seen in mid-November, he said.

ICE North Sea Brent for April delivery settled 55 cents, or 0.5%, lower at $111.06 a barrel.

The EIA said U.S. crude-oil imports last week fell by 650,000 barrels a day to 7.3 million barrels a day. Higher domestic flows from shale-oil fields are expected to continue the trend of reducing the need for crude-oil imports.

Gasoline output fell 600,000 barrels a day last week, to a seven-week low, cutting nationwide inventories in the week.

But stocks in Northeast U.S., including the New York Harbor delivery point for the benchmark gasoline futures contract, climbed for an 11th-straight week, as regional supplies continued to recover from effect of Hurricane Sandy. Stocks are 2.6% above year-earlier levels in the region, reversing a mid-December year-on-year fall of 2.5%.

April-delivery reformulated gasoline blendstock futures settled 2.35 cents, or 0.7%, lower at $3.1247 a gallon.

The EIA reported inventories of distillate fuel (diesel/heating oil) fell by a steep 3.83 million barrels, more than five times larger than expectations of a decline of 700,000 barrels. April heating oil gained 0.26 cent, or 0.1%, to settle at a one-week high of $2.9756 a gallon.

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Oilmin Proposes Body for Shale Gas Exploration

India is set to join a select group of countries having a specialised agency mapping its shale gas potential. A proposal to this effect has already been worked out by the oil ministry. The proposed agency will fall under the central government. It will have the mandate to map the presence of shale gas across various states in the Gangetic plain, Assam, Rajasthan and many coastal areas.

The agency will conduct studies on the basis of geological, geophysical and geochemical aspects of shale gas exploration, micro-seismic imaging, drilling, completion and production technologies and environmental hazards in shale gas exploitation. New Delhi-based National Geophysical Research Institute and the Geological Survey of India have been carrying out studies to identify new sources of shale gas.

According to the oil ministry, the country has a potential resource base of 300-1,200 trillion cubic metres of shale gas and 92 trillion cubic feet of coal bed methane (CBM). The government has identified Cambay, Assam-Arakan, Gondawana, KG onshore, Cauvery onshore and the Indo-Gangatic basins for carving out blocks to tap the unconventional fuel. The draft policy favours market-determined pricing of shale gas.

Similar entities exist in developed nations such as the US and Canada. Mirroring the gas market and following the emergence of shale gas, wholesale electricity prices have dropped more than 50% on average in the US since 2008. Taking a cue from the global success, the ministry of petroleum and natural gas will be taking up the policy on shale gas extraction to the cabinet in the next two weeks, a senior oil ministry official said.

The global impact of shale gas discoveries could also be significant. For example, under the old assumption that domestic supplies would be limited, companies built LNG import facilities in the US. That trend has now reversed, and there is more interest in conversion to LNG export terminals. In India, the government is taking up all initiatives to be self-sufficient in energy as the country imports around 80% of its natural resources. "Our import bill has reached a whopping $140 billion. This is not a happy situation. With policy initiatives, we hope to cut our import dependence by 75% by 2025," the oil minister said.

The US Energy Information Administration's "Annual Energy Outlook 2013" estimated that US' natural gas production will increase from 23 trillion cubic feet in 2011 to 33.1 trillion cubic feet in 2040, a 44% increase. Almost all of this increase in domestic natural gas production is due to the projected growth in shale gas production, likely to grow from 7.8 trillion cubic feet in 2011 to 16.7 trn cu ft in 2040.

Despite its geographic abundance and enormous production potential, shale gas presents many challenges, starting with the lack of an agreed-upon definition of what exactly comprises shale.

Copyright 2013 The Financial Express, distributed by Contify.com. All Rights Reserved.

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Iraqi Budget Deepens Oil Dispute with Kurds

AMMAN, Jordan - The Iraqi parliament Thursday passed a budget for 2013 that allocated to Kurdistan just a fraction of the oil revenue requested by the semi-autonomous region, a move that deepens a dispute that has disrupted oil exports from the north of the country.

The parliament agreed that the Iraqi central government should make $650 million in payments to the Kurdish government, which would be used to pay companies operating in the region for oil exports, said Ibrahim al-Mutlaq, a member of the parliamentary finance committee. The Kurdish government had asked for $3.5 billion, he said.

The budget decision adds to existing tensions between the Kurdish region and Baghdad over oil exploration rights, trade with Turkey and the redevelopment of oil fields in a disputed territory. The dispute over the payment of oil revenues has already led to the suspension of crude oil exports from the Kurdish region since December.

Kurdish lawmakers boycotted the session which led to the passing of the budget, Mr. al-Mutlaq said. Kurdish officials weren't immediately available to comment.

The Kurdish government says the $3.5 billion it requested includes outstanding payments covering all exports between 2010 and 2013. The Baghdad government collects the oil revenues because it controls the export pipeline.

The central government in Baghdad made one payment of around $550 million in October for the companies operating in Kurdistan, but Iraqi officials later said that they wouldn't pay a second portion of around $300 million because the Kurdistan Regional Government failed to reach an oil production level of 250,000 barrels a day agreed in September.

Iraqi Prime Minister Nouri al-Maliki's bloc in parliament, the State of the Law, is arguing that the Kurds should pay Baghdad for their failure to produce the promised amount since November, Mr. al-Mutlaq said.

The allocation of oil revenues has been a significant sticking point in the Iraqi parliament's vote on the 2013 budget, which is $118.6 billion in total. The vote was delayed many times because lawmakers differed on whether Baghdad should allocate money to companies working in Kurdistan.

The Kurdish government further annoyed Baghdad when it started unilateral exports of more than 15,000 barrels a day of oil and natural gas condensate in trucks to Turkey at the beginning of January. It has pledged to increase these exports gradually and even plans to set up its own pipeline, bypassing the Baghdad-controlled export route.

The two sides are also locked in a dispute over who has the right to award oil exploration licenses in the region. Baghdad considers scores of oil deals signed with companies, including Exxon Mobil Corp., Total SA and Gazprom Neft as null and void because they haven't been approved by the central government. The Kurds argue that they are legal according to the new constitution.

Another war of words broke out in January, when the oil ministry in Baghdad said it was considering signing a contract with BP PLC to redevelop the Kirkuk oil field, which is in a disputed territory bordering the Kurdish region. 

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Iraq 2013 Budget Allocates $650M to Firms Working in Kurdistan

The Iraqi parliament Thursday passed the country's 2013 budget, allocating some $650 million to central government payments to companies working in Kurdistan, a leading Iraqi lawmaker said.

Ibrahim al-Mutlaq, a member of the parliamentary finance committee, said Kurds boycotted the session which led to the passing of the budget. They had asked for 4.2 trillion Iraqi dinars ($3.5 billion) to be paid to companies producing oil and gas in Kurdistan.

Kurdish officials weren't immediately available to comment.

The Iraqi parliament postponed a vote on the 2013 budget, running at $118.6 billion, many times because lawmakers differ on whether Baghdad should allocate money to companies working in Kurdistan, in the north of the country.

The Kurds have suspended crude oil exports via the Baghdad-controlled export pipeline since December last year, protesting against delays in payment to producing companies in the region. Even in November, the Kurds didn't reach export levels of 250,000 barrels a day, as agreed with Baghdad.

The Kurds want the budget to include some IQD4.2 trillion Iraqi dinars as payments due to oil companies working in the Kurdish region. The Kurds said this amount would cover retroactive payments from 2010 up to 2013.

Meanwhile, Iraqi Prime Minister Nouri al-Maliki's bloc in parliament, the State of the Law, is arguing that the Kurds should first pay for the 250,000 barrels a day they have failed to export from November up to now, Mr. al-Mutlaq said.

The central government in Baghdad has made one payment to companies, but Iraqi officials said last year that they wouldn't pay oil firms a second portion because the Kurdistan Regional Government has failed to reach agreed production under an agreement reached in September.

The KRG further annoyed Baghdad when it started unilateral exports of more than 15,000 barrels a day of oil and condensate via trucks to Turkey at the beginning of January and pledged to increase them gradually. The Kurds also plan to set up their own export pipeline away from the Baghdad-controlled one.

Baghdad paid some IQD650 billion last year to companies but decided to suspend payment of another portion of IQD350 billion because the Kurds suspended exports.

The KRG and Baghdad are locked in a dispute over who should control oil in the Kurdistan region. Baghdad considers scores of oil deals signed with companies, such as Exxon Mobil Corp., Total SA, Gazprom Neft, DNO International ASA and Genel Energy PLC, as null and void because they haven't been approved by the central government, while the Kurds argue that they are legal according to the new constitution.

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Total Expects to Restart Elgin within a 'Very Few Days'

Total expects to restart production from the Elgin and Franklin fields in the North Sea within "a very few days" after the UK's Health and Safety Executive (HSE) announced Wednesday this week that it had given the go ahead for production to resume on the company's Elgin platform. The Elgin platform was shut down almost a year ago, on March 25, 2012, after a major gas leak.

A spokesman for Total told Rigzone following the HSE announcement:

"Now that the HSE has accepted the safety case we will be looking to restart safe production at Elgin as soon as it's practical to do so, which we hope will be within a very few days."

The spokesman added that Total would make an announcement once production has resumed.

The resumption of gas production at Elgin is much needed by the UK's energy infrastructure at the moment. UK energy regulator Ofgem warned Feb. 19 that a dwindling of foreign gas supplies was among the factors contributing to "uncomfortably tight" energy reserves in the country.

At the time of the leak incident in March last year, the Elgin and Franklin fields were producing around 9 percent of total UK gas production. At their peak the two fields can produce up to 280,000 barrels of oil equivalent per day (boepd), according to Total.

Once resumption begins Elgin/Franklin will reach 70,000 boepd – only half its pre-shutdown output of 140,000 boepd – by the end of this year and that it will not reach its full output until 2015, warned Patrice de Vivies, Total's senior vice president of exploration and production for Northern Europe, in February.

The restart of production should also eventually see the full complement of more than 230 personnel who work on the platform return to duty.

Total had hoped that production on the Elgin platform would resume by the end of 2012, but the HSE took longer than expected to decide if it was safe to resume production. Indeed, there was concern that the resumption of production might be delayed further when an HSE spokesman said March 1 that the safety regulator was still assessing the case for the Elgin restart and that the matter was "complex".

Total shut down and evacuated non-essential personnel from the Elgin March 25, 2012 after a sheen of gas was reported within the vicinity of the platform.

The firm soon performed a "dynamic kill" well-intervention operation – using the West Phoenix (UDW semisub) rig – that involved pumping heavy mud into the well that had leaked, which was achieved in May. A lengthier process to seal the well with cement was completed in autumn.

Total stated in August last year that the overall environmental impact of the gas leak incident at Elgin was "minimal", with 3,096 tons of natural gas and 3,076 tons of condensate being lost because of the leak. Most of this evaporated in the atmosphere, the firm said, while the sheen – representing some 407 tons of condensate – dispersed naturally into the sea.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Tethys: Production Testing Completed at Oman Well

The production testing of the exploration well B4EW4 on Block 4 onshore the Sultanate of Oman has been completed. The well flowed at a combined rate of close to 3,000 barrels of oil per day (bopd) on a 36/64 inch choke from the Buah and Khufai sections. The well has been completed as a production well and will be put on a long term production test.

"We are delighted with the results of this exploration well, and are looking forward to gain more data on this new discovery from the long term production test. The ongoing 3D seismic survey on the block has been extended to also cover the B4EW4 structure," commented Tethys Managing Director Magnus Nordin.

The B4EW4 well was spudded in November 2012 and was drilled to a final total depth of 9,941 feet (3,030 meters). The well was drilled on a dense grid of high quality 2D seismic data approximately 20 km west of the Saiwan East oil field. Strong oil shows were recorded during drilling in the Lower Al Bashir, Buah, Khufai and Masirah Bay formations. The testing program was designed to evaluate the Khufai and Buah reservoirs.

Tethys Oil AB, through its wholly owned subsidiary Tethys Oil Block 3 and 4 Ltd, has a 30 percent interest in Blocks 3 and 4. Partners are Mitsui E&P Middle East B.V. with 20 percent and the operator CC Energy Development S.A.L. (Oman branch) holding the remaining 50 percent.

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Halliburton Launches New Recycling Service for Fracking Water

Halliburton announced the commercialization of its H2OForwardSM service. The new technology allows customers to recycle waste streams of produced water for use in well completions.

A part of Halliburton's Multi-Chem business line, the Water Management Solutions group formulates stable fracture fluids that have the ability to work with any waste stream, including water containing total dissolved solids (TDS) with values as high as 285,000 parts per million, for use in hydraulic fracturing operations.

"The H2OForward service provides a cost-effective customer solution that combines chemistry and innovative engineered technology," said James Archer, vice president of Halliburton's Multi-Chem business line.

"The product offerings from Water Management Solutions, including the CleanWave system and CleanStream service as well as our advancements in high TDS fluids are part of Halliburton's investment to further the sustainable development of the oil and gas industry," said Archer.

The new integrated service delivers technological advancements in fluid chemistry, water treatment and scale inhibition by using Halliburton's CleanWave system to treat the water, customizing both slickwater and crosslinked fracture fluid systems to work effectively with the high-TDS produced treated water, and reducing liquid biocides with Halliburton's CleanStream service technology.

"We believe the H2OForward service, especially the high-TDS fracture fluid formulations, is a paradigm shift that negates the use of fresh water and meets the supply chain needs of the customer," said Halliburton Global Strategic Business Manager – Water Management Solutions Walter Dale.

"This is no longer a technical issue; this is a function of logistics. Customers can now use produced water on unconventional wells with no loss of well productivity at a net economic benefit while minimizing the overall environmental impact," said Dale.

To date, Halliburton has completed more than 60 wells and 280 fracturing stages in the Permian and Bakken using its H2OForward services approach.

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Musings: Building Sand Castles - BSEE's Regulatory Over-Reach

This opinion piece presents the opinions of the author.
It does not necessarily reflect the views of Rigzone.

On April 20, 2010, an explosion occurred on Transocean's Deepwater Horizon, a nine-year old semisubmersible drilling rig working to drill the first well on BP plc.'s Macondo prospect in the Gulf of Mexico. The explosion, resulting fire and eventual sinking of the rig set off a chain of events that unleashed the greatest oil spill in U.S. oil industry history. The Deepwater Horizon disaster resulted in the deaths of 11 workers, while 94 crewmen were rescued.

Two days after the explosion, an oil leak was detected from the well and industry and government officials shifted into high gear in an attempt initially to contain the spill and ultimately design a way to permanently seal the well. Numerous attempts were made to try to close the blowout preventer shear rams, pump drilling mud and cement into the well, place a containment dome over the well to catch the leaking oil and burning off some of the oil that rose to the surface. Other ideas were considered and discarded. Eventually a relief well was drilled that intersected with the original well bore and cement was pumped in to permanently plug the leaking well. On September 19, 2010, U.S. Coast Guard Admiral Thad Allen (ret.), the incident commander for the Macondo spill, declared the well "effectively dead" and of no future danger to the Gulf of Mexico.

The offshore oil and gas industry was disrupted not only by the disaster but also from the federal government's actions to shut down all offshore drilling until forced by the courts to allow shallow water drilling activity and eventually deepwater drilling to resume. Another impact of the Deepwater Horizon disaster was the revamping of the federal government's natural resource regulatory structure, taking the Interior Department's Minerals Management Service and breaking into three parts in order to eliminate conflicting missions – one (Office of Natural Resources Revenue) to manage the royalty and revenues derived from the nation's resources, another (Bureau of Ocean Energy Management) to manage the sustainable development of the nation's offshore resources, and the third (Bureau of Safety and Environmental Enforcement) to regulate safety and environmental oversight of offshore oil and gas activities.

The Bureau of Safety and Environmental Enforcement (BSEE) became actively involved in examining the causes of the Deepwater Horizon disaster, which has led to revisions to existing offshore safety and operating procedures. As part of the establishment of BSEE, the federal government announced it had the power (and duty) to regulate all companies involved in offshore resource activity, which was a significant extension of its regulatory power. Prior to this announced expansion of its regulatory scope, the MMS/BSEE only regulated through its contractual relationship with offshore operators (lessees). Offshore service companies conducting drilling, construction, transportation and maintenance activities on operated leases were regulated through Incidents of Non Compliance (INCs) sent to the lessee. Now, following the Deepwater Horizon accident and resulting Macondo oil spill, two service companies – Halliburton and Transocean - were issued INCs for the first time ever. The authority for BSEE to issue those INCs was derived from the regulators' broad interpretation of the scope of the agency's regulatory powers.

Beyond the question of issuing INCs was problem of BSEE not having offered rules for regulating offshore service company operations. There are strict procedures established under the Administration Procedures Act (APA) that stipulate how federal government agencies are to lay out new industry regulations, the right of industry participants to comment on the proposed rules, and for the federal government to consider these comments in any final rule-making activity. BSEE has yet to promulgate any rules, which would provide an opportunity for companies to comment, discuss and negotiate with the bureau before they become codified.

The latest development in this regulatory jurisdictional issue was the February 19th hearing in the United States District Court for the Eastern District of Louisiana where Judge Carl Barbier approved Transocean's Partial Consent Decree with the U.S. government. Transocean agreed to pay $1 billion in civil penalties for violations of the Clean Water Act and to take other remedial measures. Transocean has two years to pay the fine and to institute a series of operational safety and emergency response improvements on its rigs. This court-approved settlement resolves all other pending government agency enforcement actions and penalties against Transocean, including the four INCs issued by BSEE in October 2011 for the Macondo disaster. Those INCs (and HAL's INCs) had been on appeal with the Interior Board of Land Appeals.

The negotiated settlement requires Transocean to abandon its appeal of the INCs without an admission of liability for the claims in the INCs and for the U.S. government not to assess any civil or administrative penalties based on the INCs. Importantly, BSEE is not dismissing the INCs. This means that BSEE can claim that its first enforcement action against an offshore contractor successfully resulted in the issuance of INCs. The requirement that Transocean abandon its appeal avoids any judicial review of BSEE's action. The settlement terms raise the question of whether BSEE is concerned about its ability to withstand judicial scrutiny of the expansion of its regulatory authority.

According to a newsletter published by the Houston-based law firm Legge, Farrow, Kimmitt, McGrath & Brown, LLP, "This issue will likely remain unresolved until a court reviews BSEE's current attempts to directly regulate contractors, or until BSEE drafts appropriate regulations and submits them for notice and comment by the industry as required under the Administrative Procedures Act." We would agree with the first conclusion about the potential for a court review clarifying BSEE's authority. However, we doubt that BSEE has any intention of issuing draft regulations for the industry to comment on soon since it believes it already possesses all the authority it needs to issue INCs, even though service companies do not know the rules they must operate under. For this reason, the request by BSEE for comments about its draft safety culture policy statement offers the best opportunity for industry representatives to comment not only on the policy statement but also on other issues involving offshore regulation.

Offshore service company managements need to understand they now are regulated, but without any clear understanding of what the rules are they are operating under and will be judged against. Most energy executives think of industry regulation as that of utilities where government agencies oversee pricing, returns companies can earn and how they operate. In this case, the regulations are only dealing with how a company operates, but that can have a significant impact on financial returns. Operating in the dark is not a sound business strategy, and if it comes as a result of ignoring the opportunity to seek clarity then managers have only themselves to blame if they get caught in this Kafkaesque environment.

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

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Brent Pipeline System Restarts after 5-Day Shutdown

TAQA Bratani reported late Thursday morning (UK time) that the Brent pipeline system in the UK North Sea has restarted after a temporary shutdown March 2.

The company said that it has begun the process of restoring the flow of an estimated 80,000 barrels of oil per day (bopd) into the Brent pipeline system.

The pipeline system, operated by TAQA, was shut down Saturday after what the company described as a "small hydrocarbon release" was detected within one of the Cormorant Alpha platform's legs. Soon afterwards, TAQA removed 71 non-essential personnel from the platform as a precaution.

The leak was the second such incident to involve a particular leg of the Cormorant Alpha platform. In mid-January the Brent Pipeline System was shut down for several days after hydrocarbons were detected in the leg.

But TAQA said Thursday that investigations have found that there is no connection between the pipeline system and the pipeline involved in the release.

Cormorant Alpha usually handles approximately 90,000 bopd, feeding the Brent Pipeline System. According to Oil & Gas UK the fields that use the pipeline system account for around 10 percent of UK production.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Brazil's Economic Woes Make It Reluctant Successor to Chavez

SAO PAULO - The death of Hugo Chavez makes room for Brazil to take a stronger leadership role in Latin America, but the opportunity comes at a difficult time for Brazilian President Dilma Rousseff, who is struggling to restart her country's stalled economy.

Despite being Latin America's largest economy and most-populous country, Brazil in recent years had been overshadowed politically by Venezuela's flamboyant former president, who built strong alliances with the continent's left-wing leaders and challenged the involvement of the U.S. in the region.

"Chavez occupied a huge ideological space," said Rubens Barbosa, who served as Brazil's ambassador to the U.K. and later to the U.S. and currently heads consulting firm Rubens Barbosa & Associados. "What Chavez did was divide the region, leaving Brazil in the middle."

While Mr. Chavez spurned the U.S. and sought to build close ties with its adversaries, such as Cuba and Iran, Brazil took a more pragmatic stance, seeking to expand trade with developed economies as well as emerging markets, and forge friendly relationships with the U.S. and Europe as well as Asia, Africa and the Middle East.

While Venezuela antagonized some of its neighbors, on occasion cutting off trade with Colombia, Brazil tried to act as a mediator for the continent's political conflicts. But Brazil often found itself isolated, being the only Portuguese-speaking country on the continent and, with a population highly concentrated along the Atlantic coast, far from its Latin American neighbors.

While Mr. Chavez's ample financial aid to ideological allies in Bolivia and Ecuador won him popular support, Brazil's more-businesslike dealings with neighbors often led to accusations of economic imperialism.

Analysts say the death of Mr. Chavez creates a temporary power vacuum, but it is one that Ms. Rousseff will be reluctant to fill.

"Dilma [Rousseff] lacks a motive to occupy the space left by Hugo Chavez in Latin America," said Celso Roma, a political scientist associated with the National Science and Technology Institute, a Brazilian think tank. Ms. Rousseff "is worrying herself with building an economy that's attractive to overseas investors and fomenting policies based on international cooperation," he said.

Brazil reported just 0.9% growth in its gross domestic product in 2012 despite a slew of tax cuts and record-low interest rates. With presidential elections coming up next year, Ms. Rousseff is likely to focus on ways to stoke domestic growth, rather that strengthening the country's regional role.

"Brazil is organizing important events like the Confederations Cup, the World Cup, the Olympics and the possibility of hosting the 2020 [World] Expo," said Cristiano Noronha, a political analyst at consulting firm Arko Advice. "These are events that force the country to look inward."

Some, however, say Brazil won't be able to avoid taking a larger role in the region.

"Chavez always sought to wrest regional leadership from Brazil," said David Fleischer, a political science professor at the Federal University of Brasilia. "With his death, Brazil will delicately and pragmatically take that leadership back. Argentina could be a potential threat to Brazil's leadership in the region, but more in words than in practice. Argentina could try to assume Venezuela's role in the region as a country that likes to make a lot of noise."

Analysts say little will likely change economically for Brazil, with Venezuela maintaining its trade deficit with its southern neighbor. Venezuela has hired Brazilian construction firms for infrastructure projects, and that demand is likely to continue, even if Venezuela's opposition party comes into power.

"In itself, Chavez's death doesn't bring about economic or social change in Brazil," said Mr. Noronha.

However, the death of Mr. Chavez could ease a logjam in one of the biggest economic projects between Brazil and Venezuela: the troubled Abreu e Lima refinery joint venture in northeastern Brazil.

Brazil's state-run energy giant Petrobras has waited years for Venezuelan counterpart Petroleos de Venezuela SA, or PdVSA, to come up with loan guarantees for its 40% stake in the refinery, and has watched as PdVSA repeatedly missed deadlines to get its financing in order. Mr. Chavez's death may be an opportune time for Brazil to pull the plug on PdVSA's participation, reducing project costs by eliminating needs for expensive equipment to process the heavy Venezuelan crude that PdVSA was expected to bring to the refinery.

Luciana Magalhaes and Rogerio Jelmayer in Sao Paulo and Jeff Fick in Rio de Janeiro contributed to this article.

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