News & Updates
In late September, Mexican State owned oil company PEMEX reported a huge explosion in a gas depot outside Reynosa, leaving 30 casualties and more than 40 injured. Military forces took almost all day trying to put down the inmense fireball and contain the situation. Tragedies like this happen all too often and could be prevented with a greater commitment to and investment in safety. This chilling video was taken by a CCTV camera on the site. Fire starts at around 1:15.
The past 12 months have seen continuing instability in the Middle East and North Africa (MENA) region with the toppling of the regime in Libya, intensifying turmoil in Syria, and implementation of new sanctions against Iran. There have also been significant transitional changes, including the election of a new Egyptian president. Despite these events, oil-and-gas activity remains high, and investment in the region continues, even with new hydrocarbon provinces emerging. This review highlights key developments over the past year.
PRODUCTION AND RESERVES
According to the BP Statistical Review 2012, oil reserves in the MENA region at the end of 2011 were 859 billion bbl, a 3.4% increase compared to the 2010 figure of 829.8 billion bbl, Fig. 1. This can be attributed mostly to Iraqi oil reserves increasing from 115 billion bbl to 143.1 billion bbl, related to results of initial surveys conducted by international oil companies (IOCs) as part of the First Iraqi Licensing Round. Oil production for 2011 was reported in the BP Statistical Review 2012 to be 30.7 MMbpd (Fig. 2.), rising from 29.5 MMbpd in 2010, a 4% increase. Large production increases occurred in Iraq, United Arab Emirates (UAE) and Kuwait. Significant decreases were observed in Libya, Syria and Yemen.
Gas reserves in the MENA region have remained relatively static, with only a small increase from 3,092.2 Tcf to 3,115.5 Tcf, Fig. 4. Gas production increased from 61 Bcfd in 2010 to 64.7 Bcfd in 2011 (Fig. 5), a 6% increase. Largest increases in production are in Qatar and Saudi Arabia. However, as with oil production, there was a large decrease in output from Libya.
While the MENA region has encountered significant political uncertainty over the past 12 months, activity levels remain relatively high. The region still faces many challenges, but continues to provide a major proportion of world oil and gas supplies, with this role increasing, if countries can export their vast reserves effectively. Following are overviews of major MENA countries, in terms of their oil and gas outlook.
In Saudi Arabia, drilling last year remained close to the 2010 level. Saudi Aramco discovered Wedyan field in 2011. The Wedyan-1 well is 450 km southeast of Damman and flowed 2,300 bopd from the Mishrif formation. Saudi Aramco continued developing the Karan offshore gas field, the first non-associated gas field in the kingdom. The field is producing from 21 wells, distributed over five wellhead platforms. The raw gas is transported along a 110-km subsea pipeline to Khursaniyah. The field is expected to produce 1.8 Bcfgd by 2013.
A large increase in Saudi gas production was reported, approaching 10 Bcfd. Baker Hughes recently announced that Saudi Arabia sits on the fifth largest reserves of gas shale at 645 Tcf; however any development of shale gas reserves would need to overcome a lack of water for large-scale fracturing.
In the combined United Arab Emirates, oil production rose from about 2.4 million bpd in 2010 to just above 2.5 million bpd last year. Korea National Oil Corporation (KNOC) signed a contract with Abu Dhabi National Oil Company (ADNOC) to develop three blocks in March 2012. Under the contract, KNOC has a 34% interest, GS Holdings has 6%, and the remaining 60% are held by ADNOC. The three blocks contain 10 undeveloped fields with combined oil-in-place of 570 MMbbl.
Wintershall and OMV signed a Technical Evaluation Agreement in July 2012 to appraise the Shuwaihat sour gas and condensate field. Wintershall will act as operator, drilling three appraisal wells and conducting 3D seismic. If the appraisal phase succeeds, ADNOC will participate in the development.
Petroleum Development Oman (PDO) spudded 23 exploration wells during 2011, a significant decrease from the 37 spudded during 2010. This number is likely to decrease further during 2012, with only 10 exploration wells spudded in first-half 2012. Licensing for future exploration is slow to materialize into firm agreements. For example, the Ministry of Oil and Gas launched a licensing round for four onshore blocks in January 2012, with bids to be submitted by March 2012. A second licensing round was launched in April 2012 for Block 65. The second round closed on Aug. 27, 2012. No awards have been announced in either round. In a previous license award, Oman Oil Company Exploration and Production (OOCEP) signed a PSA for Block 42 in October 2011. OOCEP plans to acquire new seismic data and drill one exploration well.
In field projects, the Block 3 and 4 consortium of Consolidated Contractors, Tethys Oil and Mitsui is continuing development of Farha South and Saiwan East fields. A pipeline between these fields was completed earlier this year.
Drilling activity increased in the Kurdistan region during 2011, with 19 exploration wells spudded, up from 15 in 2010. In first-half 2012, six exploration wells were spudded, with another 19 wells anticipated before the end of the year. The Petroleum Contracts and Licensing Directorate launched the Fourth Licensing Round in April 2011, offering 12 blocks under exploration service contracts. Only four were awarded. A fifth licensing round with more than 60 blocks is planned for the next few months.
In other licensing, ExxonMobil signed six concessions with the Kurdistan Regional Government (KRG) in October 2011. In August 2012, Gazprom Neft signed a deal with KRG to acquire an 80% interest in the Shakal Block in the Kurdistan region. The block was previously relinquished by a consortium of Oil Search, Petoil and Prime Natural Resources in October 2011.
Also in Kurdistan, DNO announced a discovery in June 2012 with the Peshkabir-1 well. Additionally, Western Zagros announced an oil discovery at the Mil Qasim-1 well. Also, the operator announced an oil find at the Kurdamir-2 well in March 2012. Afren announced success at its Simrit-2 exploration well, spudded in October 2011. In another discovery, the Iraqi Oil Company, in conjunction with the South Oil Company, announced a find in the Missan area. Al Dima is the first oil field to be discovered in Iraq, outside of Kurdistan, in over 20 years.
In development activity, in July 2012, PetroChina, Total and Petronas started full-scale oil production from Halfaya field, which was awarded as part of the Second Petroleum Licensing Round in December 2009. Halfaya is expected to produce 100,000 bopd and reach a plateau of 535,000 bopd in 2016.
Noble Energy made its fourth discovery in Israel in December 2011 with Dolphin field. The field is smaller than its earlier finds, with reported reserves of around 80 Bcf of gas. Noble then drilled the Tanin-1 well, making a more sizeable discovery, with reserves thought to be 590 Bcf of gas. The operator also made a smaller discovery at Pinnacles field in June 2012. The field should produce only 1 Bcf of gas, but due to proximity to Mari-B and a simple tie-back to existing facilities, it is considered economic. Smaller fields are becoming more economic in Israel, due to termination of gas supply from Egypt, as well as the Mari-B field coming toward the end of its life. Success has not been restricted to Noble. ATP Oil & Gas drilled its first well, Shimshon-1, in April 2012. The well was drilled in 1,104 m of water and found more than 19 m of gas pay.
Noble began development of Tamar field, aiming to bring it onstream in April 2013 at around 1 Bcfgd. The development involves five subsea completions. Noble also decided to develop the Noa North field in July 2011, drilling two development wells and commencing production in June 2012. The field is estimated to produce 1.2 Bcf of gas.
The situation for IOCs has been difficult since the uprising, and in July 2012, the EU announced its 17th round of sanctions. Prior to sanctions, Syria exported most of its oil to Europe and earned $7–$8 million per day from oil and gas. Due to the restrictions, the country is thought to have lost around $4 billion. According to the International Energy Agency (IEA), Syria produced around 370,000 bopd and exported 150,000 bopd before the sanctions. Syria’s oil minister recently announced that production is less than 140,000 bopd.
Many companies have declared force majeure on their contracts. Gulfsands Petroleum declared force majeure in December 2011, and it can no longer participate in the operation of its producing assets and has also ceased exploration activities. Total, which produced around 39,000 boed in 2010, also stopped activity to comply with the sanctions. Other companies, including Shell, Suncor, Kulczyk Oil and INA, also halted operations.
Iran has been hit with a number of sanctions during the past year over international concern about its nuclear program. In January 2012, the EU announced an oil embargo against Iran, with a deadline of July 1, 2012, to wind down existing contracts. Collectively, in 2011, the EU bought 600,000 bopd from Iran, a quarter of Iran’s total oil exports. The resulting shortfall has been offset by Saudi Arabia, Iraq and Libya. Equally, other significant buyers of Iranian crude have agreed to cut their imports. The sanctions meant that many companies have left Iran, including Total, Eni, Edison and Statoil.
While Lebanon has never licensed areas for hydrocarbon activity, deepwater discoveries, such as Tamar and Leviathan offshore Israel, have increased interest in the country. The first deepwater licensing round remains anticipated, with 163 companies represented at the Lebanon International Petroleum Exploration Forum in July 2012.
Exploration activity decreased in Yemen in 2011 compared to 2010, to nine exploration wells last year, compared with 17 in 2010. This decline can be attributed to the continued uprisings in Yemen during 2011, resulting in many oil and gas companies suspending their operations. With the political situation improving, and more oil companies re-starting operations, the Petroleum Exploration and Production Authority of Yemen anticipates 23 exploration wells will be drilled during 2012.
Approximately 153 exploration wells were drilled in 2011 in Egypt, compared with 130 in 2010. However, the Ministry of Petroleum had previously announced that it expected to drill 350 exploration wells in 2011. In first-half 2012, more than 70 had been drilled, 16 by Apache.
Considerable investments have already been made in Egypt’s offshore industry, but with the launching of a new EGAS bidding round in June 2012, there are interesting opportunities for new ventures. The licensing round offered two onshore and 13 offshore blocks, and is scheduled to close in November 2012. Additionally, the awards from Egyptian General Petroleum Corporation’s (EGPC’s) recent bidding round, which closed in March 2012, are anticipated soon. The round reportedly received 25 proposals from 12 international companies.
About 40 new discoveries were made in Egypt during 2011, on par with 2010. Around 20 finds have been made so far in 2012. Apache continues its high activity level in the Western Desert with recent discoveries in Shadow field. The operator reported that it will invest $1 billion in Egypt during 2012. Also in the Western Desert, Eni, through its JV company, Agiba, made a potentially large Cretaceous oil and gas discovery.
Kuwait Energy, with its partners, Dover Investments and Beach Energy, drilled six exploration wells in the Abu Sennan concession, four of which recovered hydrocarbons. The company also made two finds in Area A in the Gulf of Suez basin. Also in the Gulf of Suez, Dana Petroleum made new discoveries near the Fin and Lorcan finds of 2010. The operator’s Matr field is now onstream, while Dana also made discoveries at East Matr-1X and North Matr-1X. BG Group struck gas in the Nile Delta with its Harmatan Deep-1 well.
BP and RWE’s $9-billion gas field development offshore Egypt may be delayed until 2015, due to the town of Idku taking issue with the building of an onshore processing plant. The project includes development of Giza, Taurus, Libra, Fayoum, Ruby and Raven fields, with combined reserves of 5 Tcf of gas.
Sonatrach maintained its high level of exploration activity, reportedly drilling 160 exploration wells in 2011. The company announced that it plans to drill 110 exploration wells during 2012. The state company also recently announced that it had made 20 new discoveries in Algeria during 2011. According to Sonatrach, it has already made 15 discoveries of its own during first-half 2012. One of the 2011 discoveries was made by an IOC. The field was found by E.ON Ruhrgas in November 2011 with the Yacoub Nord-1 well and follows E.ON’s Zemlet Cherguia discovery made near the end of 2010. E.ON made an additional discovery with the NEY-1 well, announced in July 2012. All three discoveries are in the prolific Berkine basin, in the 406a Block awarded to E.ON in 2009. Also, PTTEP drilled the Rhourde Terfaia-1 well to 4,129 m and tested 1,000 bopd and 0.3 MMcfgd.
Field development activity is robust. Anadarko’s El Merk development is 90% complete, with first oil anticipated by the end of 2012. The development includes two 65,000-bbl trains and the capacity to process 600 MMcfgd. Repsol’s Reggane North development received approval in February 2012, and the operator and its partners plan to invest $3 billion, with production likely to span 25 years, with a plateau of 282 MMcfgd. The basic engineering on Total’s Timimoun project is complete. Total also submitted a development plan for the nearby Ahnet project, which has an expected plateau of 400 MMcfgd.
Additionally, PetroVietnam and PTTEP have signed an engineering contract with Japanese Gas Corporation and Petroleum Authority of Thailand for the Bir Seba development. It is anticipated to produce 20,000 bopd by 2014, rising to 36,000–40,000 bopd by 2016. Further south in the Illizi-Ghadames basin, Petroceltic has submitted a declaration of commerciality for Ain Tsila field. Petroceltic aims to reach an average wet gas plateau of 355 MMcfd, with a further 106 wells required.
Drilling activity in Morocco remains low, with four exploration wells drilled in 2011, a decrease on the seven wells drilled in 2010. No wells were reported during first-half 2012. Despite this, companies continue to invest in Morocco. Kosmos Energy expanded its position with the signing of the Essaouira offshore exploration license and the Tarhazoute offshore reconnaissance license. Pura Vida Energy, an Australian start-up, signed an agreement for the Mazagan offshore concession. Nautical Petroleum and Barrus Petroleum signed up for the Juby Maritime Block. Further agreements have been put in place onshore, including East West Petroleum’s Doukkala Block. Several reconnaissance licenses have been awarded.
Eleven exploration wells were drilled in Tunisia in 2011, compared with 17 during 2010. There has been limited exploration drilling during first-half 2012. The consortium led by Chinook Energy drilled the unsuccessful Bir Jouacha-2 exploration well on the Sud Remada permit and plans to drill its next well in late 2012 or early 2013. Also, after 12 discoveries in 2010, only two were made in 2011, including Eni’s Bochra discovery on the Borj El Khadra permit in southern Tunisia.
Acreage continues to be awarded in Tunisia. DNO in October 2011 was awarded the onshore Fkirine prospecting permit, valid for an initial two-year period. DNO is looking to invest $2.5 million in its work program. Similarly, Topic SA, was awarded the Mateur permit in March 2012.
Drilling activity in Libya decreased in 2011 as a result of the revolution. While production is approaching pre-war volumes, exploration levels are still below the 50-plus wells drilled in 2010. However, companies are resuming exploration. Despite the drop in drilling levels, Arabian Gulf Oil Company announced in June 2012 that it had made a new field discovery with the D1-NC8 wildcat, drilled to 2,139 m, 400 km south of Tripoli.
The focus in 2012 has been the ramp-up of existing production. By August 2011, oil production had halted, but a return to pre-war oil output of 1.65 MMbopd by July 2012 was anticipated. In September 2011, production restoration efforts commenced with key fields, such as Al Jurf and Abu Attifel. Oil production levels had reached 400,000 bopd by October 2011, increasing to 750,000 bopd by November 2011.
By December 2011, production levels had increased to 840,000 bopd. In February 2012, total production reached 1.3 MMbopd, and by the end of April had risen to 1.5 MMbopd.
Prior to the revolution, Libya had seen some companies exit, including BG and Woodside. In May 2012, Shell announced that it would suspend drilling and abandon two licenses, due to disappointing results. Shell had signed deals involving exploration and upgrade of the LNG plant at Marsa Al-Brega. There have been delays. RWE is awaiting agreements with National Oil Corporation to form a J.V. and has postponed the start-up of its oil fields. RWE originally hoped to start production in 2014.
Foreign companies are gradually returning to Libya, despite some concerns over security and possible contract reviews. For example, Gazprom announced that it will decide by the end of 2012 whether to proceed with the Elephant project. Production rates are expected to reach pre-war levels of 1.6 MMbopd through a continued focus on field development and production. It was reported that Libya intends to invest $10 billion on raising production capacity from existing fields, and $20 billion on new exploration over the next decade.
Following the November 16 fire on the Black Elk Energy-operated West Delta Block 32 platform, the Bureau of Safety and Environmental Enforcement (BSEE) has launched an investigation into the incident that caused the deaths of three workers.
Ellroy Corporal and Avelino Tajonera were pronounced dead within days of the incident. Jerome Malagapo, who has been missing since the incident, was pronounced dead after his body was recovered earlier this week. Eleven others were also injured in the fire.
All workers aboard the platform were contracted from the Philippines by Grand Isle Shipyard, which, along with D&R Offshore and Crewing Services, which provides staffing services for Grand Isle, is facing charges of abusive and exploitative working conditions, filed by 20 former Filipino workers last year. The suit describes the ‘improper’ conditions in which the workers were forced to live and work, with pay as little as $5.50 an hour, according to court filings.
Currently, BSEE has ordered Black Elk to cease all similar operations in the Gulf of Mexico, following an investigation that revealed several safety violations over the previous 24 months. In a letter BSEE stated that there were 45 non-compliance incidents issued to the company, including a chemical accident that injured six employees.
Pending a further investigation, Black Elk has been ordered to shut off flow at its facilities until each facility is deemed compliant with BSEE’s safety policies, which must now pass a BSEE inspection to go back online. A properly-trained safety manager must also be in place at each facility. Other BSEE requirements state that Black Elk must provide a performance improvement plan to the government agency’s auditors, begin an independent third-party audit, and submit a report on all non-compliance incidents since 2010 within 30 days to BSEE.
The accident took place while workers aboard the platform were using a blow torch to perform maintenance work. The platform was offline at the time of the incident, which occurred 20 mi off the coast of Louisiana.
Black Elk operates around 150 platforms in the U.S.
Originally published by Turbomachinery International, the article below describes the potential of a “golden age of natural gas” made possible by new technology. KEVTA believes that this represents a significant opportunity, not only for the gas and turbomachinery industries, but also as a legitimate approach to spur economic growth worldwide through investments in infrastructure and ultimately a reduction in energy costs. Although the burning of natural gas does produce air emissions, much of these can be offset by selective catalytic reduction and similar processes. At this time, natural gas is considered a “clean energy” source by the US Environmental Protection Agency.
Today, shale gas is considered a largely US phenomenon. But, if shale gas is defined as economically recoverable gas obtained through a combination of horizontal drilling and hydraulic fracturing, then we may soon be on the verge of a global gas glut. More nations are ramping up their estimates of gas reserves that could potentially be recovered using new technologies.
Today gas prices vary across the board. In China, natural gas prices are eight to nine times more than in the US. But that could soon change if the now mature technology of hydraulic fracturing were to be used worldwide.
Leading the shale gas charge is, of course, China. EIA estimates that China has at least one third more shale gas reserves than the US. These are not proven reserves, but dubbed “technically recoverable,” as estimates of production costs have not been clearly marked out. Further explorations are required to arrive at an accurate estimate.
This year the Chinese government released a five-year shale gas plan. The production target for 2015 is 6.5 billion cubic meters and for 2020 — 60 – 100 billion cubic meters. If China were to achieve the targets, it would still only be a modest achievement as the nation would be 10 years behind the US in terms of volumes. US shale gas production reached these numbers in 2010. But, given the size of its reserves, China may eventually catch up with the US and find its comfort level in the production of cheap, efficient and environmentally friendly source of fuel for power generation.
Other countries jumping on to the shale bandwagon include Mexico, Argentina, South Africa, Poland and Brazil. Of these, Argentina, by current estimates, has nearly the same amount of reserves as the US. The Poles see shale gas as helping them break Russian stranglehold over their fuel supplies.
All this is good news for gas turbine suppliers. For instance, coal-based power accounts for 70% of all power generated in China. And the five-years shale gas plan has clearly laid out its intent to change that equation to bring down carbon emissions.
But questions remain. Less-than-$3 gas is a reality in the US today. But that may not be the case in other nations. Shale geology is generally considered more complex in other nations, such as China, making shale gas production more expensive than the US.
The larger, bigger challenge may well be logistical, though. Other nations do not boast of the same extensive pipeline network as the US, and transporting the gas may require extraordinary investments unlike in the US.
Investment groups that bought BP shares on the London Stock Exchange filed a lawsuit in a Texas court under a state fraud law. They say BP made misleading claims about its commitment to safety.
“BP paid only lip service to … (safety) reforms, lacked any tools for dealing with oil disasters such as deep-water spills and continued to operate by sacrificing safety for savings,” the suit was quoted by British newspaper The Daily Telegraph as stating. “Indeed, BP’s reform failures led directly to the April 2010 disaster.”
The Deepwater Horizon rig caught fire and sank in 2010, killing 11 workers and leading to the worst offshore oil spill in U.S. history.
The investors bought shares in BP before the spill or immediately after. They said BP offered misleading statements about the size of the spill and its ability to respond to the incident.
No comment was issued by BP.
Four workers were injured in a fire at the refinery in the northeastern Mexican city of Ciudad Madero, state-owned oil giant Petroleos Mexicanos, or Pemex, said in a statement released Monday.
The fire started while workers were installing a line Sunday at the Madero refinery, which is in Tamaulipas state.
“Regrettably, four workers were injured and they are being treated at the Pemex Regional Hospital in Ciudad Madero,” the oil company said.
One of the workers, identified as Faustino Reyna Lara, 46, is listed in serious condition, Pemex said.
The other workers hurt in the accident are Pedro de Leon Martinez, 42, Angel Perez Hernandez, 38, and Sergio Alberto Reyna Lara, 41, the oil company said.
The fire started around 3:30 p.m. Sunday and was “completely extinguished” an hour later, Pemex said.
The blaze did not cause any damage to “the refinery’s processing plants, which are operating normally,” Pemex said.
An explosion occurred on Aug. 14 at the same refinery, but no one was injured.
Pemex, the world’s fourth-largest oil company, produces 2.5 million barrels per day (bpd) of petroleum.
The state-owned corporation is the biggest source of revenue for the Mexican Treasury.
Pemex, Latin America’s largest corporation, has a monopoly over the Mexican petroleum industry.
A blaze at Venezuela’s largest refinery spread to a third storage tank as firefighters try to contain flames burning since an Aug. 25 gas explosion killed at least 48 people. Gasoline prices rallied in New York.
Oil Minister Rafael Ramirez said two of the fires at tanks holding naphtha at the Amuay refinery probably will burn out by tomorrow as firefighters contend with a third fire that started at 2:15 p.m. local time today. There was no structural damage to the processing units at the facility about 240 miles west of Caracas, he said, adding that exports haven’t been unaffected.
“We have to announce that a third tank which has had flames on its roof is also catching fire at this moment,” Ramirez, who is also head of state oil company Petroleos de Venezuela SA, said on state television. “We estimate that with the wind and conditions the two tanks should extinguish themselves by tomorrow, with this new tank we’re obliged to continue putting in all the effort to extinguish the fire.”
President Hugo Chavez, who faces elections in October, declared three days of mourning and toured the affected areas. The explosion occurred after a gas cloud formed and erupted into a ball of flames that engulfed a National Guard post as well as homes and shops in front of the refining complex. The shutdown threatens refined product supply as U.S. Gulf Coast plants halt operations as Tropical Storm Isaac heads toward the region.
Chavez said he ordered an investigation into the causes and said they won’t discard any hypotheses.
Venezuela has 4 million barrels of inventories of gasoline and other petroleum products and continues to produce 735,000 barrels of gasoline a day at plants, including nearby Cardon, according to Ramirez. Amuay, which has capacity to produce 645,000 barrels a day, will be restarted within two days after all of the fires have been extinguished, he said.
PDVSA, as the Caracas-based company is known, has 10 days of inventory to meet its supply obligations internally and externally, Ramirez said. The state-owned company shipped five tankers of crude oil from Paraguana yesterday, he said.
“It’s probably going to be far longer than their public statements given the track record we’ve seen of maintenance at PDVSA facilities over the last couple of years,” Andy Lipow, president of Houston-based Lipow Oil Associates LLC, said by phone. “I think it concerns the market that it could take a long time given that it’s their largest refining complex.”
PDVSA is the sole owner and operator of the refinery. The blast is among the world’s deadliest at an oil refinery. Fifteen workers were killed at BP Plc (BP/)’s Texas City refinery in 2005, while more than 50 people died in a fire at Hindustan Petroleum Corp.’s refinery in Visakhapatnam, India, in 1997.
Amuay, Cardon and Bajo Grande form the Paraguana complex, which has a capacity of about 950,000 barrels a day. That’s second in size to Reliance Industries Ltd. (RIL)’s Jamnagar refinery in India, according to data compiled by Bloomberg. CRP, as the complex is known, supplies 67 percent of gasoline to the local market, according to PDVSA’s website. Cardon and Amuay also export refined products to the Caribbean and the U.S.
Stella Lugo, governor of Falcon state in western Venezuela, described the early-morning blast as similar to an earthquake and said more than 200 homes near the refinery were damaged. Lugo told Union Radio today that the death toll had risen to 48 from a previous estimate of 39.
The National Guard stationed at the refinery bore the brunt of the deaths, including 18 troops and 15 family members, according to Vice President Elias Jaua. More than 500 homes in vicinity of the plant have been damaged, Chavez said today.
Gasoline rose to the highest level in almost four months today as some refineries shut with the approach of Isaac and the disruption at Amuay. BP and other companies have suspended some crude and gas operations in the Gulf of Mexico. The area is home to 23 percent of U.S. oil production and 44 percent of refining capacity, according to the U.S. Energy Department.
Gasoline for September delivery advanced 7.68 cents to $3.1548 a gallon on the New York Mercantile Exchange, the highest settlement since April 30.
Refiners with Texas operations that are less exposed to Isaac stand to benefit by exporting more product after the Venezuela explosion, said John Auers, senior vice president at Turner Mason & Company, a Dallas-based energy consultant.
“On a sustainable basis, Venezuela hasn’t been able to produce much product as they used to,” Auers said by telephone. “The U.S. refiners have taken their place. Now in a short term, they certainly can step up and do even more.”
Shares in Valero Energy Corp., based in San Antonio, Texas, jumped 5.2 percent to $30.77 today, while Marathon Petroleum Corp., based in Findlay, Ohio, gained 1.7 percent to $49.60.
The fire at Amuay, which opened in 1950, highlights the risk to supplies of oil products from large, aging plants and may lead to more exports from Asia to the U.S., according to Goldman Sachs Group Inc.
Other major refinery fires elsewhere caused months of delays before full operations resumed, Nilesh Banerjee, an analyst at Goldman in Mumbai, said in a note e-mailed today.
Venezuela, one of the 12 members of the Organization of Petroleum Exporting Countries and South America’s biggest crude producer, had an average output of 2.7 million barrels of oil a day last year, according to BP statistics. Its main export markets are the U.S. and China.
Venezuela was the fourth-largest source of crude for the U.S. in May, after Canada, Saudi Arabia and Mexico, at 821,000 barrels a day, based on data from the U.S. Energy Information Agency. Venezuelan product imports from the U.S. nearly doubled in the first five months of 2012 to 38,000 barrels a day from 23,000 in the year earlier period, according to the EIA. They include gasoline, fuel additives and liquefied petroleum gas.
Cardon has closed units several times this year after incidents. PDVSA had to halt production and evacuate workers from its Petropiar heavy-crude upgrader last year after a gas leak and a fire.
Jose Bodas, an oil union leader, told Globovision on Aug. 25 that PDVSA has ignored calls by workers to improve “hazardous” working conditions at refineries.
Seven out of nine planned maintenance programs for the Amuay refinery were postponed last year because of a lack of materials, according to PDVSA’s 2011 annual report.
Ramirez denied that PDVSA has failed to invest in maintenance and said the company spent $6 billion in the past five years on its refining circuit. Chavez also denied reports that the leak of gas had begun hours before the explosion.
“Today’s price action probably already discounts refinery outages of a few days duration,” Tim Evans, an energy analyst at Citi Futures Perspective in New York, said in an e-mailed response to questions. “If refineries are in restart mode by the end of the week we could see the futures market rebalance. If the outages are extended beyond the next few days, then we’d look for more gains for gasoline and more weakness in crude.”
Japan’s top oil refiner JX Nippon Oil & Energy said one of the three gas-fired power generating units at its 145,000 barrels per day (bpd) Sendai refinery caught fire late on Sunday, but there has been no impact on refining operations.
The fire at the No.3 gas-turbine unit, with a capacity of about 34 megawatts, had been extinguished by early Monday and there were no injuries, in large part due to successful usage of an automatic fire suppression system, a company official said.
More information on the plant:
Operator: Nippon Petroleum Refining Co Ltd
Configuration: 102-MW, 2+1 CCGT with H-25 gas turbines CHP
Fuel: petrochem off-gas
HRSG supplier: MHI
T/G supplier: Hitachi, MHI, Melco
Quick facts: This CHP plant was commissioned on 20 Sep 2007 as part of a project undertaken by NPRC to upgrade facilities at its Sendai Refinery. The primary fuel is gas created as a by-product of the increased production of propylene and xylene. Surplus power is exported to the grid. This is the world’s first CCGT of its kind with two fully-fired boilers and the ability to use other gas fuels depending on the refinery’s gas balance. The plant has SCR.