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    Venezuela's Deteriorating Oil Quality Riles Major Refiners (Thursday, 19 October 2017)

    19 Oct 2017, 11:00 pm

    Venezuela’s state-run oil firm, PDVSA, is increasingly delivering poor quality crude oil to major refiners in the United States, India and China, causing repeated complaints, canceled orders and demands for discounts, according to internal PDVSA documents and interviews with a dozen oil executives, workers, traders and inspectors.

    The disputes involve cargoes soiled with high levels of water, salt or metals that can cause problems for refineries, according to the sources and internal PDVSA trade documents seen by Reuters.

    The quality issues stem from shortages of chemicals and equipment to properly treat and store the oil, resulting in shutdowns and slowdowns at PDVSA production facilities, along with hurried transporting to avoid late deliveries, the sources said.


    U.S. refiner Phillips 66 (PSX.N) canceled at least eight crude cargoes because of poor oil quality in the first half of the year and demanded discounts on other deliveries, according to the PDVSA documents and employees from both firms. The canceled shipments - amounting to 4.4 million barrels of oil - had a market value of nearly $200 million.

    Another key buyer of Venezuelan crude - India’s Reliance Industries Ltd (RELI.NS), operator of the world’s largest refinery - has repeatedly complained about oil quality, a PDVSA employee told Reuters. State-run firm China National Petroleum Corp (CNPC) also complained earlier this year about excessive water levels in oil cargoes, a former PDVSA employee said.

    The deterioration of PDVSA crude is the latest symptom of the firm’s ill-maintained production infrastructure, and it threatens to accelerate an already severe cash crisis at a time when Venezuela is hoarding dollars to pay some $3.4 billion to bondholders in the next few weeks. PDVSA’s financial woes radiate through the country’s recession-racked economy, which depends on oil for more than 90 percent of its export revenue.

    Venezuela’s Oil Ministry and PDVSA did not respond to requests for comment.

    An official at PetroChina Co (601857.SS), CNPC’s listed subsidiary, said he was not aware of complaints about Venezuela oil. A CNPC spokesman also said he had no knowledge of the issue.

    Phillips 66 declined to comment. Reliance did not respond to requests for comment.

    One of the PDVSA employees said quality started to drop about two years ago, and the deterioration has accelerated recently.

    “We’re refitting chemical injection points, recouping pumps and storage tanks,” the worker told Reuters. “But without chemicals, we can’t do anything.”


    Venezuela’s crude output has already plummeted to its lowest level in almost three decades because of crime at oil fields, underinvestment, mismanagement at PDVSA, and a fourth straight year of economic contraction.

    The oil firm also faces sanctions imposed by the administration of U.S. President Donald Trump, which have caused many banks to refuse to extend the letters of credit needed to complete some oil sales and purchases, leading to contract suspensions and disputes.

    For graphic of Venezuela's falling exports, see:

    The full scale and severity of PDVSA’s oil-quality problems are unclear, although industry sources reported issues in major oil-producing regions including the western state of Zulia and the Orinoco Belt in the southeast.

    PDVSA has halted output at some Zulia production facilities because it does not have enough functioning storage tanks and chemicals to process the crude being pumped up, according to two workers with knowledge of the operation.

    “This is becoming a big problem. We’re trying to get production up, but now they’re saying, ‘You have to stop pumping because I can’t handle it’,” said a PDVSA employee, adding that chemicals were scarce and many storage tanks were full.

    Compounding the problem, a growing number of PDVSA maintenance workers have fled the country amid food shortages, skyrocketing inflation and sometimes violent clashes between political protesters and the nation’s socialist government.

    Venezuela is a key source of heavy sour crude supplies for export to the United States, China, India and Europe. But in a world awash in cheap oil, customers in those regions can easily find crude elsewhere.

    “There are plenty of crude inventories available on the market, and they can switch to other providers,” one buyer of Venezuelan oil told Reuters.

    More troubling for PDVSA is that the quality issues are cutting into its ability to sell crude for cash; the firm already delivers about 40 percent of its oil to Chinese and Russian firms as payment on more than $50 billion in loans from those nations.

    Both Reliance and Phillips 66 are among PDVSA’s biggest cash-paying customers.

    The U.S. refiner has demanded discounts due to the high salt content in the heavy blend that PDVSA sent the firm from its Orinoco Belt facilities this year, according to internal PDVSA documents seen by Reuters. It was not immediately clear whether PDVSA granted those discounts.

    PDVSA documents detail the company’s struggle to meet the supply quotas of desalted crude to Phillips 66 because of low output at its Puerto la Cruz refinery, the facility charged with desalting crude for exports.

    PDVSA said this week on state TV that it had received two new desalting units for Puerto la Cruz, with joint capacity of 80,000 barrels-per-day. The firm did not detail when they would be operational.

    High salt content can lead to corrosion in distillation towers and other refinery equipment, so many customers reject cargoes with high salt content rather than accept them at a discount.

    India’s Reliance has complained about high water and sediment content in its crude - up to 5 percent in recent months, according to the PDVSA employee, when the supply contract between the two firms says it should be limited to less than 2 percent.

    “Reliance’s executives in charge of the supply contract are angry,” the employee said. “They have complained several times, and the issue has not been solved.”


    Oil workers in Venezuela describe several layers of problems that are hurting crude quality.

    Deferred maintenance, a shortage of spare parts and equipment theft have shut down some storage tanks, where crude is left to separate from water that needs to be removed.

    PDVSA has also rushed deliveries - before the crude is properly processed, and water and sediments removed – because the firm is behind on promised deliveries to customers, two PDVSA sources told Reuters.

    PDVSA has also run short on cash to import the chemicals it needs to process crude.

    In one case, employees of the firm were caught in a scheme to steal money they had falsely claimed was used to buy chemicals, according to an internal PDVSA incident report seen by Reuters.

    Authorities recently arrested four PDVSA employees in Zulia state, according to the report, for “illicit enrichment due to phantom purchases of chemicals.”


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    Canada's Oil Sands Survive, But Can't Thrive in a $50 Oil World (Thursday, 19 October 2017)

    19 Oct 2017, 10:00 pm

    Canada’s oil sands producers are stuck in a rut.

    The nation’s oil firms are retrenching, with large producers planning little or no further expansion and some smaller projects struggling even to cover their operating costs.

    As the era of large new projects comes to a close, many mid-sized producers - those with fewer assets and producing less than 100,000 barrels of oil a day in the oil sands - have shelved expansion plans, unable to earn back the high start-up costs with crude at around $50 per barrel. Larger Canadian producers, meanwhile, focus on projects that in the past were associated with smaller names.

    The last three years have seen dozens of new projects mothballed and expansions put on hold, meaning millions of barrels of crude from the world’s third-largest reserves may never be extracted.

    Where industry groups in 2014 expected Canada’s oil sands output to more than double to nearly 5 million barrels per day (bpd) by 2030, that forecast has been knocked down to 3.7 million bpd.

    This follows a spell of consolidation that has seen foreign majors sell off more than $23 billion in Canadian assets in a year and turn to U.S. shale patches such as the Permian basin in Texas, which produce returns more quickly and where proximity to refiners means the barrels fetch a better price.

    “We cannot compete with that huge sucking noise to the south that is called the Permian. Investment dollars are spiraling away down there,” Derek Evans, chief executive of small oil sands producer Pengrowth Energy (PGF.TO) told Reuters in an interview.

    Permian production rose 21 percent in 12 months through July compared to a 9 percent increase in Alberta’s oil sands, according to Canadian and U.S. government data.


    Mid-sized producers are hurting the most, due to start-up costs that far exceed those in other major producing areas. Oil sands producers have slashed operating costs by a third since 2014, but building a new thermal project - in which steam is pumped as deep as one kilometer (1094 yards)underground to liquefy tar-like bitumen and bring it to the surface - requires U.S. crude benchmark at around $60 a barrel to break even, analysts estimate.

    The North American benchmark West Texas Intermediate crude CLc1 has traded between $42 and $55 a barrel so far this year. The U.S. Energy Information Administration forecasts it will average $49.69 a barrel in 2017 and $50.57 a barrel next year.

    There are around half a dozen thermal projects in the costly start-up phase, when engineers steadily increase steam pressure to bring a reservoir’s production up to full capacity.

    One of those is Athabasca Oil Corp’s (ATH.TO) Hangingstone project. It was originally conceived as a 80,000 bpd project, but instead will bring output to only 12,000 bpd from the current 9,000 bpd. The project can break even with U.S. crude prices of at least $53 a barrel, meaning right now Athabasca keeps losing money on Hangingstone production. Size is crucial in the oil sands; the more bitumen a company can squeeze out of a plant, the lower fixed costs per barrel will be.

    “(Athabasca) was a company built when oil was $100 a barrel. In those days we were going to find funding for joint ventures and build greenfield projects to a massive size. The reality is the world changed,” chief executive Rob Broen told Reuters.


    Quarterly filings show why smaller players are struggling. Transportation and marketing costs at Hangingstone, along with the cost of natural gas used to produce steam to extract oil, and other operating costs are much higher compared with Cenovus Energy’s (CVE.TO) Christina Lake project, one of the highest-quality and biggest bitumen reservoirs in the oil sands.

    Pengrowth’s development plans are on hold as well, Evans said, because the company needs U.S. crude to stay at $55 for a sustained period to justify investment in its 14,000 bpd Lindbergh thermal project, at one point intended to grow as large as 40,000 bpd.


    Large producers have pulled back in response to lower global prices as well. For example, Suncor Energy’s (SU.TO) 194,000 bpd Fort Hills mine, due to start producing oil by the end of this year, is the company’s last megaproject.

    Canadian Natural (CNQ.TO) restarted construction on its 40,000 bpd Kirby North project last November, one of a handful of smaller projects to start producing in 2019.

    Other companies like MEG Energy (MEG.TO) are planning expansions at existing sites in 20,000 bpd “modules” rather than starting large new projects from scratch. But even such more modest investments are out of reach for smaller companies like Athabasca and Pengrowth.

    “It’s very hard (for a small company) to drag itself out of the financing black hole it would have to get in to build a project to start with,” said Nick Lupick, an analyst at AltaCorp Capital. “A large company can take that on their balance sheet without having to leverage too highly.”


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    Gulf of Mexico Oil Spill Triggers BSEE Panel Investigation (Thursday, 19 October 2017)

    19 Oct 2017, 8:00 pm

    BSEE Gulf of Mexico Region Director Lars Herbst initiated a Panel Investigation Monday into an oil release from subsea infrastructure located about 40 mi southeast of Venice, La., in water 4,463 ft deep. The flowline release, which began Wednesday morning in an area identified as Mississippi Canyon 209, was reported by offshore oil and gas operator LLOG Exploration Offshore, LLC.

    “BSEE places great emphasis on making certain all oil and gas operations on America’s Outer Continental Shelf are safe,” said Herbst. “This panel investigation is a critical step in ensuring BSEE determines the cause, or causes, of the incident and develops recommendations to prevent similar events from occurring in the future.”


    The five-member panel is made up of inspectors, engineers and accident investigators. At the conclusion of their investigation, the panel will issue a report that will contain findings, make recommendations and identify any potential violations for consideration by BSEE enforcement staff.

    LLOG reported to BSEE that they isolated the pipeline leak and stopped the leak on Thursday morning and estimated the unaccounted for oil volume to be in the range of 7,950 to 9,350 bbl. BSEE inspectors traveled to LLOG’s Delta House platform Friday to begin an initial inspection and investigation and the BSEE panel will continue coordinating with LLOG and the U.S. Coast Guard to complete the investigation.


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    Deepwater Rigs Sent to Junkyard as Daily Losses Mount (Thursday, 19 October 2017)

    19 Oct 2017, 6:00 pm

    Transocean Ltd. is finally sending Pathfinder to its grave, after two years in a Caribbean purgatory that cost about $15,000 a day.

    The move by the world’s biggest offshore-rig operator signals just how bleak the future looks for deepwater drilling. Pathfinder is the most famous of six floating rigs the company is scrapping in burials that will add up to a bruising $1.4 billion write-off. Competitors are going the same route, jettisoning more rigs in the third quarter than have ever been trashed in a 90-day stretch, according to Heikkinen Energy Advisors analyst David Smith.

    That’s how bad it is, with predictions crude prices won’t go much higher than $60/bbl in the next year compared with around $50 recently. “Deepwater is going to be playing a much-reduced role on the global oil-supply stage relative to what the industry expected as recently as three years ago,” said Thomas Curran, an analyst at FBR Capital Markets in New York.


    For all that, it could have been worse, in one way, for Transocean. It has been the most aggressive in an unprecedented experiment with what’s called cold-stacking for big drillships. After oil prices cratered in 2014, the company didn’t send all of its unwanted rigs out to sea in the time-honored temporary holding pattern where engines keep running and a crew remains on board -- something know as warm stacking, naturally, that runs up a daily bill of some $40,000. Instead, Transocean dropped anchor on nine high-tech ships 12 mi off the coast of Trinidad & Tobago and simply shut the motors off. So far the savings are in the neighborhood of $90 million.

    New generation

    This hadn’t been tried before with the new generation of finely tuned, computer-driven giants never intended for long-term parking. Equipped with derricks towering 220 ft above the platform and able to drill in 10,000 ft of water, the vessels had been in demand since birth. The big question was whether one could be shut down so solidly and later switched back on at a reliable cost. Rival Ensco brought its DS-4 drillship back from cold stack, but it wasn’t mothballed as long as Transocean’s rigs and was tied to a dock, allowing it access to more auxiliary power while parked.

    With Pathfinder, and a cousin called the GSF Jack Ryan that’s also being scrapped after its Caribbean cold stacking, Transocean will never know for sure. The Vernier, Switzerland-based company declined to comment for this story.

    For Transocean and the others that went the cold-stacking route, “this has been a very painful process,” said Greg Lewis, an analyst at Credit Suisse in New York. He doesn’t disagree with the company’s decision. Cold-stacking Pathfinder was only a $5 million-a-year expense, and with that “you’re basically paying for a call option on a recovery in the market.”

    Older rigs

    At the moment, seven other Transocean offshore rigs continue to bob in the Caribbean. Most if not all of them may never drill again, according to analysts at Heikkinen and Sanford C. Bernstein & Co. The older a rig is, and the longer it’s parked, the more likely it will get passed up by customers for more capable competitors.

    The offshore-drilling business enjoyed the highest of highs when oil topped $100/bbl a few years ago. Companies including BP and Anadarko Petroleum could lease out an advanced ship for more than $600,000 a day. An army of boats and helicopters took workers and supplies out to these rigs, where meals often included steak and shrimp, and carved ice sculptures adorned lunch rooms.

    Now it’s one of the most beaten-up sectors. E&P companies are focusing on lower-cost shale-oil drilling on land, in places such as Texas and New Mexico. There’s a glut of offshore equipment. Only about half the global supply of deepwater rigs is working today; back in 2013 almost every single one was running at full speed. The latest projections call for a modest offshore recovery around 2019, or maybe 2020, according to Wells Fargo Securities.

    In the meantime, what to do with these crazy-expensive rigs ordered years ago?

    Sunk cost

    “It’s very hard to ignore the sunk cost, but you have to,” said Chris Beckett, the former chief executive officer of Pacific Drilling, which kept the engines on a pair of drillships running for a couple of years off the coast of Aruba, waiting for contracts that so far haven’t come. “Compared to the cost of having to buy or build a new one, the option cost of keeping it in a condition that you can reactivate it for a sensible price is relatively inexpensive.”

    That’s what Curran of FBR Capital Markets expects will happen: Once oil prices rise and explorers get back to some bit of offshore work, it will be just enough to keep hope alive. The problem, Curran said, is this will leave an overhang, keeping rig rents from rising.

    “The normal reaction will be to cling dearly to whatever you have and kick off a new game of chicken when it comes to retirements,” he said. “Ideally, you want to emerge when the music starts to play again as the offshore driller who sacrificed the least. That’s the game they’re all trying to play."


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    Subsea 7 to Buy Normand Oceanic (Thursday, 19 October 2017)

    19 Oct 2017, 2:00 pm

    Subsea 7 will become the sole owner of the Normand Oceanic, a flex-lay and heavy construction vessel that is being managed by Solstad Farstad while under long-term contract to a third party.

    The company will take ownership of the vessel by acquiring the remaining 50% shareholdings in its equity accounted joint ventures, Normand Oceanic and Normand Oceanic Chartering,

    @onlinelaw@from Solstad Farstad for a nominal cash consideration, Subsea 7 said in an 18 October statement. The group will assume all obligations related to an outstanding loan of approximately $100 million, and Normand Oceanic and Normand Oceanic Chartering will become wholly-owned subsidiaries of the group.

    Jean Cahuzac, CEO of Subsea 7, said, “Our agreement to acquire Normand Oceanic reflects our strategy to own high-specification vessels that differentiate our market leading engineering and construction services to the offshore energy industry. We are focused on actively managing our fleet composition to meet our clients’ requirements and market conditions.”


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    Iran Official Backs Extension of OPEC Cuts, Dismisses Trump risk (Thursday, 19 October 2017)

    19 Oct 2017, 2:00 pm

    Iran said it would support an extension of OPEC oil-production cuts to the end of next year, and insisted its own output plans won’t be disrupted by U.S. President Donald Trump.

    “We are pleased with the way OPEC has decided to cut some production in order to bring a semblance of balance between supply and demand,” Amir Zamaninia, deputy minister for trade and international affairs at Iran’s Oil Ministry, said Tuesday. “We think that this trend will continue and we will support this trend.”

    The Organization of Petroleum Exporting Countries and its partners are debating whether to extend output cuts that are set to expire in March, in an effort to drain the global glut and shore up prices. While the curbs have shown signs of success in recent months, the market could return to surplus if the group fails to renew the accord.


    Iran targets oil production capacity of 4.7 MMbpd by 2021, Zamaninia said at the Oil & Money conference in London. It’s currently pumping 3.8 MMbpd to 3.9 MMbpd, Oil Minister Bijan Namdar Zanganeh said earlier this month.

    The country agreed to a cap of 3.797 MMbpd in last year’s OPEC accord, which became effective in January. When asked whether Iran would restrain its production if the deal is extended, Zamaninia said it will “match” its plans to expand output capacity with the policies it agrees on with OPEC.

    Iran’s energy industry has recovered following the removal of sanctions early last year, yet its oil exports face a challenge after Trump threatened last week to ditch the international agreement that lifted the trade restrictions. Trump refused to certify that Iran is in compliance with the deal, though didn’t repudiate the pact.

    Trump’s statement was characterized by “chest-beating” and has “little or no effect” on Iran’s oil plans, Zamaninia said Tuesday. Iran aims to finalize at least 10 contracts with international oil companies by the end of March, and is in talks on projects with potential partners from Europe, Asia and Russia, he said.


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    Prosecutors Consider Charges Over North Sea Oil Leak (Thursday, 19 October 2017)

    19 Oct 2017, 12:00 pm

    Charges could be brought over a leak aboard a North Sea platform.

    About 95 tonnes of oil spilled from BP's Clair facility west of Shetland in October last year.

    The oil believed to have dispersed naturally with what the firm called "minimal" impact on wildlife.


    A fault in a system designed to separate oil and water is believed to have been responsible and Clair was shut down for three weeks.

    The leak is now being examined by prosecutors in the health and safety division of the Crown Office.

    A spokesman said: "The Department for Business, Energy and Industrial Strategy has submitted a report to the Crown Office and Procurator Fiscal Service (COPFS).

    "That report is now under the consideration of the health and safety division of the COPFS".

    It is unclear at this stage who could face charges if the Crown Office decides to prosecute.


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    Tendeka Secures Trio of Middle East Contract Wins (Thursday, 19 October 2017)

    19 Oct 2017, 10:00 am

    Following a recent award by the Kuwait Oil Company (KOC) to deliver a lower completions project, Tendeka, a global leader in advanced completions and production optimization, has been awarded two further contracts in the Middle East.

    The multi-million-pound agreements with the Abu Dhabi Onshore Operations Company (ADCO) and Petroleum Development Oman (PDO) will involve the supply of a range of specialized Inflow Control technologies. These technologies enable the effective management of the reservoir in horizontal wells to increase productivity and improve oil recovery.

    ADCO’s three-year contract, with a one-year extension, will involve Tendeka’s market-leading zonal isolation products, and full range of inflow control technologies, including their market-leading FloSure Autonomous ICD to be installed across all ADCO fields.


    PDO has awarded Tendeka a multi-well trial and one-year deployment contract for the application of FloSure Autonomous ICD across Oman.

    The multi-million-pound deal with Kuwait Oil Company (KOC) will involve Tendeka installing Advanced ICD equipment in 55 horizontal wells over two years in Northern Kuwait.


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