Monday, 29 September 2014

Petrobras starts extended well testing at Iara

Petrobras started-up, on June 21, the Extended Well Test (EWT) in the evaluation area known as Iara, on block BM-S-11, some 300 km off the coast and at a water depth of approximately 2,200 m. The EWT is part of the Discovery Evaluation Program, approved by Brazil’s National Petroleum, Natural Gas and Biofuels Agency (ANP).


The test is being conducted on well 3-BRSA-1132-RJS (RJS-706), in the western section of the Iara Evaluation Plan, using FPSO Dynamic Producer. The well’s initial production of 29,000 bopd is similar to the production of the wells that are currently producing for commercial purposes in the Santos basin pre-salt, indicating the area’s potential.


This EWT, the first to be carried out in Iara, will enable the acquisition of important data for the development of this discovery, which took place in 2008.


The Evaluation Plan will expire at the end of 2014, at which time the consortium must submit the declaration of commerciality to the ANP.


Petrobras is the operator of the consortium (65%), in partnership with BG E&P Brasil Ltda (25%) and Petrogal Brasil S.A (10%).


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Saturday, 27 September 2014

Anadarko to resume Marco Polo output in July

Anadarko Petroleum is set to restart production from its Marco Polo platform in the deepwater Gulf of Mexico early next month.


The platform, which was producing about 12,000 boed net to Anadarko, was shut-in on May 8 following a compressor fire.


Work to repair electrical wiring and other equipment is continuing, the company said in a statement on June 23.


Marco Polo is located on Green Canyon Block 608 about 150 mi (240 km) offshore Louisiana. The platform is stationed in 4,300 ft (1,310 m) of water and functions as a production hub.


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Thursday, 25 September 2014

U.S. oil export shift prompts second look at eligible shipments

The U.S. could allow about 750,000 bpd of light crude oil to be exported, based on a new government stance defining what qualifies for overseas shipments.


Producers, refiners and pipeline companies are questioning exactly how much the Obama administration has relaxed its position on crude exports after the Commerce Department said June 24 it had categorized some lightly processed oil as exportable. The U.S. has prohibited most crude exports for four decades.


About 750,000 bpd of oil produced from U.S. shale plays is an ultra-light variety known as condensate, said Michael Wojciechowski, head of Americas downstream research for Wood Mackenzie. More than 70% of U.S. condensate comes from the Eagle Ford shale formation in Texas, where the majority of it goes through a heating process to burn off certain gases, Amrita Sen, chief oil economist for Energy Aspects, said.


The Commerce Department gave permission for condensates to be exported after going through the process, known as stabilizing, because then it can be considered a refined product. Though most raw crude oil exports are banned, refined products can be shipped abroad without limits.


Stabilizers at oil fields along the U.S. Gulf Coast may have a combined capacity of more than 200,000 bpd, according to Eric Lee, a commodities strategist for Citi Research.


“Processed condensate exports could begin as early as August,” Lee said in a research note. The U.S. could export 300,000 barrels of condensate per day by the end of the year, according to another Citi note.


Oil producers and refiners were unsure whether other types of crude might also qualify. Far more crude might be eligible for overseas shipments if any type of stabilized oil can qualify as a refined product, since the practice is widespread in the industry, said Charles Blanchard, an analyst for Bloomberg New Energy Finance.


Oil producer BHP Billiton said it welcomed the approval of condensate exports “under limited circumstances. BHP Billiton will consider marketing opportunities that may apply to our condensate production in the Eagle Ford and Permian basin,” Jaryl Strong, a BHP spokesman, said in an emailed statement.


As the industry figures out how to define the new rule, “that’ll really help companies on the downstream side better understand business opportunities and business impacts,” Dean Acosta, a spokesman for refiner Phillips 66, said.


Producers are keen to find additional markets for crude as output from U.S. shale formations has surged, causing bottlenecks in some regions. Refiners that have benefited from access to oil at prices below the international benchmark saw their shares drop yesterday, June 25, after the Commerce Department change was announced.


The United States produced almost 8.4 mmbpd in May and annual output is forecast to reach 9.3 mmbpd in 2015, the highest since 1972, according to the Energy Information Administration.


More than 80% of the Eagle Ford’s output goes through stabilizers, Energy Aspects’ Sen said. Pioneer Natural Resources, one of the companies that asked the government for permission to export stabilized condensate, said this week that a large portion of its 43,000 bpd of Eagle Ford production is condensate that already undergoes the processing.


Stabilizers are relatively simple pieces of oilfield equipment sometimes positioned near wellheads. They heat oil enough to boil off some gases, separating those products from the rest of the crude mix, Blanchard said. “A caveman could do it,” Blanchard said, comparing the process to heating oil in an oven.


The process is commonly performed before putting oil and condensate into pipelines. Stabilizing oil is far less complex than the process of splitting or refining crude, which involve more sophisticated devices that heat and separate fuels from oil. Stabilizers that qualify crude for export can cost as little as one-tenth that of more complex processing units, said Wojciechowski at Wood Mackenzie.


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Tuesday, 23 September 2014

Four wastewater wells tied to Oklahoma quake surge, study says

Four wastewater wells used in oil and natural gas drilling may be responsible for triggering 20% of all earthquakes in the central and eastern U.S. from 2008 to 2013, according to a study published in the journal Science.


The wells are used to dispose of high volumes of wastewater released from underground rocks when they are fractured using modern oil-drilling techniques. The four wells are likely responsible for a dramatic rise in earthquakes near Oklahoma City since 2009, according to the research.


Oklahoma has had more earthquakes than California so far this year, making it the most seismically active state in the continental U.S. and raising suspicions that drilling activity is influencing a surge in temblors there. The state had 238 earthquakes with a magnitude 3.0 or greater through June, more than double the number in California, which has historically ranked second in earthquakes behind Alaska.


Scientists studied wastewater-injection volumes, geologic information and data from earthquake sensors to show that fluids pumped into the wells increased underground pressures and spread them. The area of elevated underground pressure grew in a way that overlapped with a “migrating front” of earthquakes centered near Oklahoma City.


The data showed that water pumped into wastewater wells can increase and affect underground pressures as far away as 35 km (22 miles), potentially triggering earthquakes at faults that would have previously been considered too distant.


Researchers from Cornell University, University of Colorado, Columbia University, and the U.S. Geological Survey collaborated on the study.


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Sunday, 21 September 2014

Obama administration seen widening exports for shale oil

The U.S. Commerce Department opened the door to more U.S. oil exports as long as the crude is lightly processed, tempering the impact of a law that’s banned most overseas petroleum shipments for the past four decades.


The department widened its definition of what’s traditionally been considered a refined product eligible for shipping to customers abroad. That means more of the oil being pumped from U.S. shale formations may be eligible for export after being run through small-scale processing units.


The Commerce Department issued its ruling after Pioneer Natural Resources Co. petitioned for approval to export a type of ultra-light oil that had been stripped of lighter gases to make it less volatile for transport -- a minimal level of processing known as stabilization. The ultra-light oil, known as condensate, has been abundant in shale formations during the shale drilling boom, leading to oversupplies on the Gulf Coast.


“It’s a crack in the door which has otherwise been shut for 40 years,” Harry Tchilinguirian, head of commodity markets strategy at BNP Paribas SA in London, said by phone. “If approval for condensate exports are extended to more companies, it’ll benefit U.S. producers and processors in Asia, particularly in Singapore and South Korea.”


Distillation Exception


Any oil that has been processed through a distillation tower -- a preliminary form of refining -- is no longer defined as crude oil, and therefore is eligible for export, said Jim Hock, a department spokesman, in an emailed statement yesterday, June 24.


Pioneer uses a distillation unit to stabilize oil it produces in the Eagle Ford shale of South Texas, most of which is condensate.


The Commerce Department “recently confirmed our interpretation that the distillation process by which our Eagle Ford shale condensate is stabilized is sufficient to qualify the resulting hydrocarbon stream as a processed petroleum product eligible for export without a license,” Pioneer said in an emailed statement.


“It’s not exactly going to be a game changer but it’s certainly the next step in providing the market with some relief,” said Robert Campbell, head of oil products research at Energy Aspects Ltd., a London-based research firm.


West Texas Intermediate crude for August delivery climbed as much as $1.47, or 1.4%, to $107.50 a barrel in electronic trading on the New York Mercantile Exchange, before trimming gains to trade 0.2% higher at $106.20 at 8:53 a.m. in London. Brent oil futures slid 0.5% to $113.86.


Economic Forces


“There are certainly a lot of inexorable economic forces that suggest the U.S. is going to relax the export ban in the long-term,” Ric Spooner, a chief strategist at CMC Markets in Sydney, said by phone.


Further applications for exports from the U.S. may follow this approval, Morgan Stanley analysts led by Adam Longson wrote in a report today, June 25. If more overseas sales are allowed, U.S. condensate could find its way to Asia, from which companies can produce naphtha used in the petrochemical industry, BNP’s Tchilinguirian said.


“A lot of condensate splitting capacity is in Asia and more will be added this year,” he said. “Some of the Asian processors would have been wondering where the condensate is going to come from.”


Restricted Exports


The U.S. has restricted most crude exports since 1975, in response to the Arab oil embargo. Shipments to Canada are an exception, and those averaged 246,000 bpd in March, the highest level since April 1999.


U.S. oil producers such as Continental Resources Inc. and ConocoPhillips have been clamoring for an end to the restrictions as shale production has brought a surge in North American petroleum supplies. U.S. crude production has jumped 45% since the start of 2012, driven by horizontal drilling and hydraulic fracturing in places including North Dakota and Texas.


Supplies on the Gulf Coast rose to more than 215 MMbbl in May, the highest level on record since 1990, according to Energy Information Administration data. Much of that supply has been in the form of lighter crude, and arrived after Gulf Coast refiners made expensive upgrades to their plants to process heavier crudes from places such as Canada and Mexico.


‘First Step’


The Commerce Department’s willingness to qualify more lightly processed crude for overseas shipments should lead to even wider approval of crude exports, said Senator Lisa Murkowski, Republican of Alaska. The decision “is a reasonable first step that reflects the new reality of our energy landscape,” she said.


It could also make plans for more complex processing plants, known as splitters, less economic. Several companies are building and planning condensate splitters that are designed to process lighter crudes from shale formations into products like naphtha, kerosene and gasoil, which are eligible for export.


The plants, built for one-tenth the cost of a complex, full-scale refinery, were also aimed at using minimum processing to qualify oil as a refined product for export.


The first of the units, a 50,000 bpd processing plant built by Kinder Morgan Energy Partners LP for use by BP Plc, is scheduled to come online in November. BP has signed a 10-year contract to use the facility, which will be expanded to 100,000 bpd in 2015. Several additional plants have been proposed by other pipeline or trading companies, and refiners including Valero Energy Corp. and Phillips 66 said they plan to add similar oil processing equipment.


Refined Product


The distillation towers that the Commerce Department says are needed to process oil into an export-eligible refined product aren’t defined by size, said Andy Lipow, president of Lipow Oil Associates LLC, a consulting firm in Houston.


The towers could include equipment such as stabilizers that are used in oil fields to separate the lightest gases such as propane and butane from some condensate to prepare it for shipping, he said.


An eventual removal of the export ban would promote U.S. oil production, said Zak Cikanek, a spokesman for the oil industry trade group American Petroleum Institute, which said it hasn’t yet reviewed the Commerce Department ruling.


“Allowing the export of processed condensate would be a very small step toward a much more important goal, which is free trade,” Cikanek said.


Largest Refiner


While Phillips 66, the largest U.S. refiner by market value, has been supportive of lifting the crude export ban, refiners will probably reap lower profits if they are forced to pay higher prices to compete with international buyers for U.S. crude.


“We don’t think the current system needs to be changed,” said Bill Day, a spokesman for Valero Energy Corp. “The United States is still importing quite a bit of crude oil to satisfy our needs.”


Net U.S. crude imports were 7.16 MMbpd as of June 13, down 24% over the last five years, according to data from the U.S. Energy Information Administration.


The decision to allow a wider category of lightly processed oil provides a stronger base to argue for broader approval of crude exports, said Lipow, the Houston oil consultant.


“There’s cracks in the crude oil export dam,” he said.


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Friday, 19 September 2014

Leviathan gas field partners set for talks to supply BG in Egypt

Partners in Israel’s Leviathan offshore natural gas field signed a letter of intent to hold talks with a subsidiary of BG Group Plc about supplying the company’s gas-liquefying plant in Egypt.


The letter sets out terms of a final accord, including the sale of 7 Bcm of gas a year for 15 years at a price to be determined, the partners said today, June 29. Gas would be supplied at the Leviathan platform and delivered by pipeline to BG International (NSW) Ltd.’s plant at Idku, Egypt, according to a filing that Ratio Oil Exploration 1992 LP and two units of Delek Group Ltd. made to the Tel Aviv Stock Exchange.


The 2010 discovery of Leviathan, coming after the nearby Tamar find, is proving a bonanza for Israel, which expects the gas to meet its needs for a quarter of a century and also enable it to sell to other countries. Egypt formerly supplied gas to Israel until repeated sabotage of a pipeline in Egypt’s Sinai Peninsula led the Arab nation to cancel the exports in 2012.


“This is an opening shot for the development of Leviathan,” Guil Bashan, an analyst at Tel Aviv-based IBI- Israel Brokerage & Investments Ltd., said by phone today. “The supply at the platform implies BG will be building the pipeline and all the infrastructure to transport the gas, which means much lower capital expenditure and lower risk for the Leviathan partners.”


Tamar


The partners signed their non-binding letter of intent on June 27, according to today’s filing by Delek Drilling-LP, Avner Oil Exploration LLP and Ratio Oil Exploration 1992. Noble Energy, Inc. of Houston, Texas, is the fourth and biggest partner in Leviathan, with a 39.7% stake. Noble said May 5 that it signed a non-binding agreement of intent to sell gas from the Tamar field to Union Fenosa Gas SA’s LNG plant in Egypt.


Shares of Delek Drilling-LP and Avner Oil Exploration advanced 1.2% and 1.8%, respectively, at the close in Tel Aviv. Ratio Oil Exploration 1992 gained 3.3%, the most since Feb. 2. Delek Group, which has stakes in Delek Drilling and Avner, added 0.4%.


Delek and Noble already have gas-supply agreements with Jordan and the Palestinian Authority. “We expect more export deals for Leviathan, including Turkey, Cyprus and Jordan,” Bashan said.


Australia’s Woodside Petroleum Ltd. scrapped an agreement last month to buy a quarter of Leviathan, Israel’s largest gas field, for as much as $2.6 billion.


Aside from Noble’s stake in the field, Delek Drilling and Avner hold 22.7% each and Ratio Oil Exploration has 15%.


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Wednesday, 17 September 2014

Enterprise doubles capacity on Seaway oil line to Gulf coast

Enterprise Products Partners LP and Enbridge Inc. said the 512-mile expansion of their Seaway oil pipeline is mechanically complete, with commissioning work remaining before it starts to move oil south from the delivery point for West Texas Intermediate futures in Cushing, Oklahoma.


Enterprise looped the existing Seaway line with a parallel pipe, increasing capacity to the Houston area to 850,000 bpd, the companies said in a joint statement.


The expansion will draw barrels from the nation’s biggest oil-storage hub, where stockpiles have fallen 48% this year to the lowest level in five years. New pipelines and expansions, including the southern leg of TransCanada Corp.’s Keystone XL system, helped eliminate a glut that built at Cushing as oil flooded in from Canada and North Dakota.


Workers need to perform several tests on the pipe to make sure there are no leaks before pumping oil into it, said Andy Lipow, an oil industry consultant with Lipow Oil Associates LLC in Houston.


“The pieces of the pipe are put together, the pumps are hooked up,” he said. “Now it’s been turned over to operations, and they have to complete their procedures ensuring the line is ready to receive oil and begin routine operations.”


The new 30-in. Seaway Loop Pipeline connects to the Jones Creek storage terminal near Freeport, Texas, the companies said in the statement. Jones Creek is connected to Enterprise’s ECHO crude storage facility in Houston by a 65-mile, 36-in. line. Construction of a 100-mile pipeline from ECHO to Beaumont and Port Arthur is expected to be completed this month, and commissioning of both lines will continue through the third quarter.


West Texas Intermediate futures were down 74 cents, or 0.7%, to $103.74 a barrel on the New York Mercantile Exchange at 11:47 a.m. New York time. WTI’s discount to the European benchmark crude Brent widened by 22 cents to $6.98.


Enterprise, a Houston-based company that operates the Seaway pipeline and co-owns it with Enbridge, reversed the system in May 2012 and expanded its capacity to 400,000 bpd in January 2013. As part of the most recent expansion, Enterprise said storage at the ECHO terminal would increase by 900,000 bbl to 6 million.


Crude stockpiles at Cushing slid 1.36 MMbbl, or 6.2%, to 20.5 million in the week ended June 27, the lowest level since Nov. 14, 2008, according to U.S. Energy Information Administration data. They were 41.8 million in January. Supplies in PADD 3, which includes the U.S. Gulf Coast, have climbed 19% this year to 204.8 MMbbl.


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Monday, 15 September 2014

ZEiTECS completes first commercial rigless retrieval of cable deployed ESP

ZEiTECS has announced the world’s first rigless installation and retrieval of the NAUTILUS ESP, a cable-deployed electric submersible pump system (ESP), in a customer well in West Texas.


The system was deployed on December 19, 2013, and ran for 139 days until planned shutdown on May 7; the system was retrieved successfully on May 9.


The ESP was retrieved using ZEiTECS’ Launch and Recovery System (LARS). LARS is a compact, rigless injector-based system that eliminates the need for a rig or heavy coiled tubing unit to replace failed ESPs.


The NAUTILUS ESP system was deployed on a high-strength DC coaxial cable and converts DC power to AC power downhole to drive any standard inverted ESP. The system was set at 2,600 ft. and retrieved in only 40 minutes using the LARS, at an average rate of 65 ft. per minute.


The rigless ESP operation was completed using a 400 series Baker Hughes inverted ESP deployed inside 5.5” tubing, producing 900 bbl of fluid per day. The NAUTILUS ESP system can be used as a permanent production system, as well as a temporary well intervention system for well testing and well clean-up purposes.


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Saturday, 13 September 2014

Brent set for first weekly drop of Iraq crisis as output spared

Brent headed for the first weekly drop since violence erupted in Iraq amid speculation that oil output would remain safe in OPEC’s second-biggest producer. West Texas Intermediate was steady in New York.


Futures were little changed in London and down 1.2% from June 20, the biggest weekly drop since April. Iraqi forces held the Baiji refinery in the north after repelling the latest attack by Islamist militants. Fighting hasn’t spread to the south, home to more than three-quarters of the nation’s oil production. U.S. crude stockpiles increased last week for the first time since May, according to the Energy Information Administration.


“Right now we are focusing hard on the situation in Iraq, although concern may have been a bit inflated,” Jens Pedersen, an analyst at Danske Bank A/S in Copenhagen, said by email. “The short-term risks to the oil market are limited.”


Brent for August settlement was at $113.37 a barrel on the London-based ICE Futures Europe exchange, up 16 cents, at 1:12 p.m. London time. The volume of all futures traded was about 48% below the 100-day average for the time of day. Prices have climbed 2.3% this year.


WTI for August delivery was little changed after earlier sliding as much as 36 cents to $105.48 a barrel in electronic trading on the New York Mercantile Exchange. Prices are down 1.3% this week. The U.S. benchmark crude was at a discount of $7.48 to Brent on ICE, compared with $7.98 on June 20.


Iraq Conflict


Brent has gained 3.6% in June as fighters from the Islamic State in Iraq and the Levant captured the northern city of Mosul and advanced south toward Baghdad. Iraq pumped 3.3 MMbopd last month, trailing only Saudi Arabia in the Organization of Petroleum Exporting Countries, data compiled by Bloomberg show. Iraq’s crude exports will accelerate next month, Oil Minister Abdul Kareem al-Luaibi said on June 25.


“Markets are beginning to position for the likelihood that insurgents will be contained from any further incursions to the south, allowing oil exports to be maintained,” Ric Spooner, a chief strategist at CMC Markets in Sydney, said in a note.


WTI may rise next week because of the risk that fighting could still spread south, according to a Bloomberg survey. Thirteen of 33 analysts and traders, or 39%, estimated futures will gain through July 3, while eight respondents predict a drop.


In the U.S., crude inventories expanded by 1.74 MMbbl last week to 388.1 million, the EIA, the U.S. Energy Department’s statistical arm, reported on June 25. A 1.7 million decrease had been projected in a separate Bloomberg survey.


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Thursday, 11 September 2014

INPEX unloads first modules for Ichthys LNG Project processing facilities

The INPEX-operated Ichthys LNG Project is preparing for the next phase of its onshore construction effort, following the unloading of its first large pre-fabricated modules on June 29. The modules will be used to construct the Project’s LNG processing facilities at Bladin Point near Darwin, Australia.


Ichthys LNG Project Managing Director Louis Bon said the safe arrival of the first of more than 200 modules was an important milestone for the Project and marked the next phase for its onshore construction effort.


“Much of the work we have been doing to transform Bladin Point has been leading up to this event -- we have been setting the foundations to prepare for their arrival and installation at site,” he said


A modularized approach to construction is now common in Australia. For the Ichthys LNG Project, this approach involved having components of its onshore facilities assembled in modules at fabrication yards and tested before transporting them to site.


Designing and constructing modules in this way was a key part of delivering the global project on schedule and on budget, Bon said.


“The Ichthys LNG Project’s onshore facilities were designed so that some elements would be modularized while others could be stick-built on site in Darwin,” Bon added.


The Ichthys LNG Project’s pre-fabricated modules are being built at four yards in China, the Philippines and Thailand. Over the next 18 months, about 60 module shipments are scheduled to arrive in Darwin. The largest modules can weigh more than 6,000 tonnes.


Transported on large, custom-made marine vessels, module shipments will travel past Darwin on the way to the Project’s module offloading facility (MOF) at Bladin Point. The MOF supports the offloading of the large modules and oversized equipment that is too large to be transported to site by road.


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Tuesday, 9 September 2014

GeoPark finds new oil field in Chile

GeoPark Limited has announced the discovery of a new oil field in Chile. The Primavera Sur 1 well marks the first discovery of an oil field on the newly-acquired Campanario Block in Tierra del Fuego, Chile. GeoPark operates and has a 50% working interest in the Campanario Block, in partnership with Empresa Nacional de Petroleo de Chile (ENAP).


GeoPark successfully drilled and completed the Primavera Sur 1 well to a total depth of 8,025 ft.  A test conducted in the Tobifera formation, at approximately 7,750 ft, resulted in a production rate of approximately 215 gross bopd of 39.9° API. Further production testing will be required to determine stabilized flow rates and the extent of the reservoir.


Surface facilities and infrastructure have already been put into place in order to produce and commercialize the produced crude oil from this well. Seismic interpretation of the Primavera Sur prospect indicates the opportunity for further development drilling following further testing.


James F. Park, CEO of GeoPark, said, "Our new discovery on the Campanario Block demonstrates the exploration and growth potential of our new Tierra del Fuego acreage, where  our team has identified over 30 new prospects and leads to be drilled on our Isla Norte, Campanario and Flamenco Blocks. The quick cycle time from drilling a well to selling production also reflects the attractive operations and economics of the region. We are pleased to be working with ENAP on these blocks and look forward to further results from our approximately $150 million work program in Chile in 2014."


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Sunday, 7 September 2014

Ithaca completes successful Stella test

Well 30/6a-B1Z (“B1”) is the third development well drilled on the Stella field. The well was drilled to a total measured depth subsea of 16,185 ft, with a 2,147 foot gross horizontal reservoir section completed in the Palaeocene Andrew sandstone reservoir. The well intersected high quality sands across a net reservoir interval of 2,034 ft, equating to 95% net pay.  This compares to 1,312 ft and 2,514 ft in Stella wells A1 and A2, respectively.


As with the previous two Stella development wells, a clean-up flow test has been performed on the B1 well in order to effectively remove the drilling fluids used to complete the well and gain additional reservoir data and fluid samples. The well flowed at a maximum rate of 12,492 boepd on a 48/64-inch choke, with the full production potential of the well limited by the capacity of the well test equipment on the drilling rig. Fluid samples show that the oil is of high quality, approximately 45° API.


The maximum flow rate of 12,492 boepd comprised 7,565 boepd and 29.6 MMscfpd of gas.  This compares to the results of the A1 and A2 wells that achieved maximum flow rates of 10,835 boepd and 10,442 boepd, respectively.


The test results achieved on the first three Stella development wells have served to de-risk the initial annualised production forecast for the Greater Stella Area hub of approximately 30,000 boepd 100%, 16,000 boepd net to Ithaca.


The B1 well is in the process of being suspended.  The suspension configuration is such that the well can be brought on to production without the requirement for any further well intervention activity once the FPF-1 is on location and hooked up.  Following completion of the well suspension operations the ENSCO 100 will move on to drilling of the fourth Stella development well from the same drilling centre location.  It is anticipated that the well will be completed around the end of the third quarter of 2014.


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Friday, 5 September 2014

Exxon reports fire, oil spill at Nigeria terminal

Exxon Mobil Corp. said thunderstorms caused a tank fire June 27 and an oil spill today, June 29, at the Mobil Producing Nigeria Qua Iboe Terminal it operates in Akwa Ibom state.


Offshore production and loading of oil continue, the Irving, Texas-based company said in an emailed statement. No fatalities or injuries were reported. The amount of oil lost to the fire and spill hasn’t been calculated, the company said.


Lightning ignited the tank and the fire was extinguished by noon local time June 27, according to the statement.


Lightning knocked out power to the terminal again today, resulting in a spill. Emergency response systems were activated to contain it, shoreline restoration has begun and relevant authorities and community leaders notified, according to the statement.


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Wednesday, 3 September 2014

Petrobras $6.8 bn surprise raises share-sale specter

Petroleo Brasileiro SA’s decision to pay billions of dollars for new deepwater oil rights increases the chances that the state-run producer will sell shares to raise cash, according to Banco BTG Pactual.


Petrobras agreed to pay 15 billion reais ($6.8 billion) through 2018 to produce as much as 15 billion additional barrels from a region that holds the giant Buzios field, it said yesterday, June 24. It is considering selling assets and restructuring other projects to help shoulder the cost.


“We fear that the contract significantly increases the risk that Petrobras will call for a capital increase in 2015,” Gustavo Gattass and Andrea Cardona, analysts at BTG, said in a research report today, June 25. “This contract will weigh more on Petrobras’ stretched balance sheet.”


Petrobras shares fell the most in six weeks yesterday and Banco Bradesco SA and UBS AG lowered their ratings to the equivalents of hold from buy following the announcement. Petrobras will pay 2 billion reais this year and the rest by the end of 2018. The stock fell 1.9% to close at 17.29 reais in Sao Paulo today.


CEO Maria das Gracas Foster ruled out a share sale twice during a press conference in Rio de Janeiro yesterday. The company may sell as much as $11 billion in assets over the next five years to help make payments while other options include restructuring projects, she said. Oil and Gas Secretary Marco Antonio Almeida said yesterday the deal wasn’t designed to improve the government’s fiscal accounts.


Timing Surprise


“We were surprised by the timing of the announcement and lack of details in the deal,” UBS analysts led by Lilyanna Yang said in a research report. “Why pay upfront cash?”


Petrobras expects to start producing under the contract in 2021 and reach a peak of 1 MMbpd in 2026, Foster said.


The company has sold exploration assets in regions including the U.S. Gulf of Mexico and Africa to help finance efforts to more than double production by 2020. It has also implemented cost control programs at offshore operations.


“If Petrobras had the financial capability, we would charge 15 billion reais upfront,” Almeida told reporters in Brasilia. “We are providing Petrobras with a great oil area to explore.”


Brazil will aim for a 1.9% primary surplus target this year, the Finance Ministry said in a Feb. 20 statement. The primary surplus as a percentage of gross domestic product in the year through April was 1.87%.


Share price losses since the announcement reduced a year-to-date gain to 1.8%.


Record Offering


“Our reading of this deal is negative,” Bradesco analyst Auro Rozenbaum said in a research report. “Petrobras will need to anticipate payments from the second contract before having started production from the initial contract.”


In 2010, it paid $42.5 billion in shares and cash for the rights to produce 5 billion barrels at a section of the so- called pre-salt region that holds the Buzios field in deep waters of the South Atlantic. It was part of a $70 billion share sale, the world’s largest, that diluted minority holders.


The area holds 9.8 billion to 15.2 billion bbl of recoverable oil in addition to what Petrobras was authorized to produce under the original contract, it said in a statement yesterday.


“This is a great opportunity for Petrobras,” Foster told reporters in Rio de Janeiro. “No other company in the world has the opportunity to work with such great volumes.”


Development Struggle


Petrobras has found as much as four times the amount of crude that it’s authorized to produce at the offshore license. The company is struggling to develop all the oil it has found in other sections of the pre-salt region and investors prefer to see the company increase output than make discoveries after output has been little changed for the past four years.


The arrangement announced yesterday is the first time Petrobras is making “advanced payments” for an oil project, Foster said. The company won’t seek partners for the new area, and high well productivity will reduce the amount of platforms needed to develop the area, Jose Formigli, the head of exploration and production, told reporters.


Petrobras is investing about $100 million a day to expand its capacity to produce and refine crude, contributing to the biggest cash flow deficit of any oil company, according to data compiled by Bloomberg.


Mixed View


While the new contract gives Petrobras $15.6 billion in net present value, the payments add financial risk, Bank of America Corp. analyst Frank McGann said in a report. The project should have a 15% internal rate of return, lower than the 18% Bank of America estimates for the Libra pre-salt field where Petrobras also has a profit-sharing contract, he said.


“The transaction is very mixed in our view,” McGann said. “This is likely to be viewed as one more sign of a heavy government involvement in the company, which is likely to offset any potential long-term benefits.”


Production under the contract will add an additional 1 MMbpd to the company’s production, Foster said. There are no limits on how much Petrobras can produce under the profit-sharing contract, Formigli said.


While the initial payments will put a strain on Petrobras, the project probably will be profitable in the long term, Luana Helsinger, an oil and gas analyst at brokerage GBM Grupo Bursatil Mexicano SA, said by phone from Rio.


Mosdor Global Estates, providing support in the buying and selling of crude oil, other petroleum products. Publishing news and reviews in the oil and gas plus real estate industry online.

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Monday, 1 September 2014

Libyan rebels say two oil ports reopened after yearlong blockade

Rebels who helped decimate Libyan oil production by blockading eastern ports said the nation’s largest and third-largest export facilities can ship crude again, in a gesture of support for the newly elected parliament.


Es Sider and Ras Lanuf, which have combined capacity of 560,000 bpd, will reopen today, July 2, according to Ali Al-Hasy, a spokesman for the rebels’ Executive Office for Barqa. Libya’s state-run National Oil Corp. hasn’t been informed of the move, said Mohamed Elharari, company spokesman. The two terminals would increase Libya’s crude-export capacity almost five-fold.


The loss of Libya’s oil production boosted the price of Brent, a benchmark for half the world’s traded crude. Brent futures for August settlement fell as much as 0.7% to $111.54 a barrel today, the lowest intraday level in almost three weeks. The restart of operations at the two ports would probably send Brent down to $110 a barrel, Commerzbank AG said.


“The Petroleum Facilities Guards in Es Sider and Ras Lanuf have been instructed to allow the two ports to resume operations,” Al-Hasy said by phone from eastern Libya. “This is an initiative from the Executive Office for Barqa to welcome the newly elected parliament that includes well-known patriots, and to encourage them to fight corruption and protect the natural resources of the nation.”


The self-declared Executive Office for Barqa seeks self-rule for the eastern region of Libya known also as Cyrenaica. It occupied oil ports in the region at the end of July 2013, demanding an oil-revenue-sharing agreement to make up for the neglect the area experienced under Muammar Qaddafi’s 42-year rule.


Brent Falls


Libya is now producing about 320,000 bpd, or about a fifth of its output before Qaddafi was overthrown in 2011, according to state-run National Oil Corp. “We will lift the state of force majeure in Es Sider and Ras Lanuf when we receive confirmation of this agreement from the government,” said Elharari. Force majeure is a legal step that protects a company from liability when it can’t fulfill a contract for reasons beyond its control.


The premium of the front-month Brent contract over the second month, a structure called backwardation that signals tight near-term supplies, narrowed to as little as 7 cents a barrel on the ICE Futures Europe exchange in London today, the least since April 15. Brent’s premium to U.S. benchmark West Texas Intermediate narrowed as much as 41 cents to $6.54 a barrel on ICE.


Government representatives including Justice Minister Salah al-Mirghani and a delegation of the Barqa federalists sealed the agreement yesterday in the eastern city of Tobruk, Al-Hasy said. “The facilities in Es Sider and Ras Lanuf are in very good shape, they are ready to operate.”


‘Ready to Operate’


Es Sider has 340,000 bbl in daily loading capacity and Ras Lanuf 220,000 bbl, according to the oil ministry. The nation has a total of nine oil export terminals, of which three -- Brega, Jurf and Bouri -- are operating with a combined daily loading capacity of 145,000 bbl.


While the other terminals -- Zawiya, Mellitah, Hariga and Zueitina -- are under government control, they are not exporting because of protests at the ports or connected oilfields unrelated to those of the Barqa federalists.


The government has agreed to pay “in the next few days” the salaries of Petroleum Facilities Guard who defected to the Barqa group during the blockade and to implement a preliminary agreement reached on April 6, Al-Hasy said. The rebels handed over the oil ports of Hariga and Zueitina after this accord in exchange for amnesty and salary payments for the guards, and an audit of the National Oil Corp.’s oil sales since the overthrow of Qaddafi.


The Barqa federalists in May threatened to re-occupy Hariga and Zueitina in protest over the appointment as prime minister of Ahmed Maiteg, whom they see as allied with the nation’s Islamists. His appointment was later withdrawn, and elections were held last week for a new parliament.


Mosdor Global Estates, providing support in the buying and selling of crude oil, other petroleum products. Publishing news and reviews in the oil and gas plus real estate industry online.

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