Floating storage making a come back?

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An increasing amount of spot fixtures have been negotiated using so called ‘disadvantaged’ tankers thus far this year (see Tanker Operator Aug/Sept issue). 

 

In addition, several older tankers have also been fixed for operational floating storage in the timecharter market this year, due to a lack of onshore storage facilities.

However, over the last few weeks, a notable shift toward inventory drawdowns from refiners has been observed, reducing the need for this type of floating storage, McQuilling Services reported in an industry note.

As one cause for floating storage is abating, a new one may be emerging: the recent strengthening of the US dollar amid ‘Brexit’ has pressured spot crude prices more than forward levels, revealing short-term arbitrage opportunities conducive to floating storage.

According to McQuilling’s daily analysis of remotely-sensed vessel position data, a marked build-up of offshore floating storage was seen in April and May. For example, the average number of anchored VLCCs with cargo on board reached 51 per day in May, compared to only 21 in the beginning of the year.

The Middle East and Southeast Asia remained the top anchorage zones, accounting for 88% of the VLCC floating storage fleet throughout 2016 to date.

In the Middle East, the number of Iranian VLCCs storing oil remained steady at around 18 tankers during the year, and for the time being, they have not significantly impacted on tanker freight rates, since they are not actively participating in the spot market.

Not surprisingly, we’ve witnessed a very active short-term timecharter market for VLCCs this year, McQuilling said. Thus far in 2016, around 13 tankers have been fixed for less than three months, compared to only two in the first half of last year.

As the majority of these VLCCs have been deployed or geared for deployment in the Arabian Gulf and Singapore regions, their use for storage purposes is probable.

Similar to the larger tankers, the number of Suezmaxes involved in floating storage also experienced an increase from the beginning of April. The most significant rise was in Southeast Asia, where the number of floating tankers climbed to six by the end of April.

In addition, McQuilling recorded five Suezmaxes anchored with cargo on board off West Africa and the Mediterranean during the same period.

However, the situation has changed notably since the start of June, as the total number of floating storage tankers dropped around 32% within 30 days. By the end of June, the consultancy counted 37 VLCCs and seven Suezmaxes operating as storage facilities.

This decline could be partly due to the crude price increases since the third week of May when Brent rose to over $50 per barrel. Charterers are likely to prioritise offloading crude from floating storage or drawdown land-based inventories to mitigate against rising crude prices.

As a result, there was a slowdown in cargo demand and continuous oversupply of VLCC tonnage throughout June.

During this period, the AG/Far East and AG/Southeast Asia spot fixture activity saw a significant decline from 83 in May to 69 in June. The average freight rates for VLCC AG/Far East also dropped nearly WS8 points month-on-month.

Timecharter rates followed the spot market, with VLCCs falling to their lowest level since March, 2015.

By the end of June, one year VLCC timecharter rates had dropped to $38,000 per day, a 32.7% decline since January 2016, while recently, the 1999-built ‘Plata Glory’ was fixed for 30 days at $22,000 per day, with an option to extend the period twice at $26,000 per day and $29,000 per day, respectively.

Taking into consideration the falling timecharter rates and the short term pressure on spot crude prices, McQuilling believed that this recent fixture may be a prelude to more deals. Supporting this view is the widening short-term contango.

According to JBC energy, the one month spread for Brent crude reached $0.56 per barrel on 5^th July, more than double the figure seen at the beginning of June. The two month spread also widened to $1.08 per barrel.

Quantifying the incentive to currently employ floating storage, the ‘Plata Glory’s’ charterer is probably earning a net income of nearly $9,300 per day for 30 days if the cargo owner brought M1 Brent and sold M2 Brent futures on 5^th July, or $6,150 per day for 60 days if sold M3 Brent futures.

Given that a VLCC can load around two million barrels of crude oil and consume an average of $2,500 worth of bunkers each day, the breakeven price to timecharter a VLCC will be around $34,800 per day for 30 days and $33,500/day for 60 days of current contango levels.

Assuming that tax and other expenses represent an additional 10% of the overall costs, the breakeven price was adjusted to around $31,300 per day for 30 days and $30,150 per day for 60 days.

In July month-to-date, the VLCC weighted TCE average stands at only $23,400 per day, a 60% decline compared to the same period last year. This figure is also much lower than the current breakeven price to conduct offshore floating storage, thereby solidifying expectations for an increase in short-term timecharters.

As a number of VLCCs (likely ‘disadvantaged’) may be removed from the available tonnage list, McQuilling believed that the VLCC spot market may have bottomed out and could benefit from the possible offshore floating storage prospect.

If indeed charterers act upon this opportunity, we are likely to see steady or slightly increasing VLCC spot rates in July. However, with a steady flow of newbuildings entering the trading fleet and limited exits, this support may only keep rates from sliding further, the consultancy concluded.

2020 sulphur cap report gives clear signal

 

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A Netherlands research institute CE Delft report into the forthcoming 0.5% IMO sulphur cap published today (Friday) claimed there will be sufficient refining capacity by 2020 to produce compliant marine fuels.

 

This is primarily due to the slowing of demand for distillates from other industry sectors, the report said.

The Exhaust Gas Cleaning Systems Association (EGCSA) welcomed the institute’s findings. EGCSA director, Donald Gregory, said, “The report of CE Delft commissioned by the IMO plainly shows that availability of marine fuels is not a reason for the IMO to delay introduction of the 2020 global sulphur emissions limit. The independent assessment comes to the conclusion that there will be sufficient low sulphur marine fuel available by 2020 and that any regional shortcoming can be met by interregional transport.”

The IMO had appointed CE Delft to assess worldwide low sulphur fuel supply and demand, fuel oil market trends and any other relevant issues, as required under MARPOL Annex VI in the run-up to a ruling on the adoption of a global limit on fuel oil sulphur emissions in October, 2016.

The study was intended to evaluate the likely availability of compliant fuel, rather than consider fuel purchase price, as the critical determining factor when deciding whether or not to introduce the global 2020 sulphur emission limit.

Unease over fuel price fluctuations and unwillingness to invest make some parties want to put off introduction of sulphur emission limits until 1st January, 2025, the EGSA said. However, the association and its members expressed concern that any delay in the introduction of the 2020 sulphur emissions limit will allow the shipping industry to continue to cause health problems and damage to the environment from harmful SOx air emissions.

The group said that is was also worried that a delay would penalise early adopters of clean fuels and exhaust gas cleaning systems, as well as heighten insecurity and costs for the shipping industry, as patchwork local ECAs pre-empt the delayed global one.

Gregory said,“Putting off a decision on the 2020 global sulphur cap until another MEPC meeting in 2017 or 2018 will end up affecting introduction of the cap and is likely to lead to a delay until 2025. Without a firm decision now, the shipping industry is set to suffer from uncertainty and the world from emissions that pose a risk to health and the environment.”

Given adequate supply of 0.5% sulphur marine fuels and, as previously claimed by EGCSA, ample capacity for the manufacture and installation of marine scrubbers, the association believes shipowners have access to the necessary resources and systems to meet the 2020 limit cost-effectively.

Gregory added, “A decision in principle on introduction of the 2020 cap at MEPC 70 in October, 2016 is imperative to allow shipowners to mobilise investment and make strategic decisions in good time for 1st January, 2020 implementation. In line with MARPOL Annex VI, Regulation 14, the CE Delft study assumes that ships will use fuels with a maximum sulphur content of 0.1% in emissions control areas (ECAs) or for smaller engines, and fuels with a sulphur content of up to 0.5% outside these areas from 1st January, 2020.

“The study further presumes that roughly 3,800 ships will have installed exhaust gas cleaning systems (EGCS or scrubbers) by 2020. Capacity is expected to grow as new vendors entering the market increase the installation capability year-on-year from 2020. Our members have ample capacity to meet the numbers predicted in the CE Delft report with capacity rising with demand. The use of scrubbers will allow shipowners to be immune to low sulphur fuel market price volatility,”he concluded.

The Oil and Gas Industry in Cuba

 

http://www.cubabusinessreport.com/the-oil-and-gas-industry-in-cuba/

The island of Cuba had proven oil reserves of 124 million barrels according to 2013 figures. There are varied estimates of total crude oil reserves that rely mainly on estimations of as-yet undiscovered offshore oil deposits in the North Cuba Basin. Cuba is one of three locations in the Caribbean (Barbados and Trinidad and Tobago are the other locations) which possess oil and natural gas reserves.

In 2008 Cuba announced its reserves of crude oil amounted to approximately 20 million barrels, mostly offshore in the Cuban shelf. If these estimates prove to be accurate, then Cuba potentially has one of the top 20 crude oil reserves in the world. The country currently has three producing oil fields offshore within five kilometers of its northern coast.

Cuba’s Oil Industry

Cuba Petróleo Union, known by the trade name CUPET, is the state-owned Cuban oil company responsible for the country’s oil and gas industry. In addition to operating a chain of filling stations that sell gasoline, the company is involved in refining and distributing the country’s petroleum products. It also takes part in the exploration for and development of new oil fields, including extraction of crude oil petroleum deposits. They are working on increasing their refining capacity plus reworking currently suspended wells.

Cuba’s Oil Production

The northern region of Havana to Villa Clara provinces is where current extraction is based. CUPET jointly produces crude oil through agreements with companies from Spain and Canada as well as with the People’s Republic of China plus others. As Cuba’s state oil company, CUPET has already signed contract agreements with ten countries for further oil exploration and development. Canada’s Sherritt International produced about 20,000 barrels of oil a day with total annual revenue of $269.2 million in 2014.  Of 59 available licensed blocks, almost half are already contracted by companies from Australia, Brazil, Canada, China, India, Malaysia, Norway, Spain, Venezuela and Vietnam.

Currently about 80,000 barrels of heavy crude oil are produced daily by Cuba. Several companies have initiated oil exploration in Cuba over the last 15 years, discovering new deposits along the 80 mile stretch of coast in the provinces of Havana and Matanzas in the northwest. CUPET also has a cooperation agreement to import oil with the Venezuelan government. In exchange for Cuban doctors and “missions”, Venezuela provides Cuba with cheap oil.

Cuba’s Oil Exploration

CUPET began partnerships with Repsol-YPF of Spain when both parties determined that the island’s off-shore reserved should be able to produce a minimum of 4.6 billion barrels of oil. By 2010 Cuba’s leasing program for the north and west ocean floor blocks began. This leasing is taking place regardless of the fact that these fields are near the tourist areas of both Cuba itself and Florida.  Cuba has no capability to handle a major oil spill and nobody wants another disaster like the BP spill of 2010.

Three deep-water exploratory wells were drilled in 2012 by the platform Scarabeo 9 from Italy for various oil companies, one of which was Spain’s Repsol. These test wells were completed in May, August and October of that year and all, to everyone’s disappointment, none discovered a commercial quantity of gas or oil. Due to this, Repsol relinquished its Cuban concessions. The deep-water drilling rig they were using was removed, postponing more detailed exploration programs for several years.

Both state-owned firms and private companies from Vietnam, Venezuela, Spain, Russia, Norway, India and Brazil have obtained leases. Due to their country’s current embargo against Cuba, no companies from the United States have participated.

New Partnerships and Future Exploration

Though Cuba’s deep-water exploration was halted in 2012, interest has never waned. MEO Australia qualified as a shallow water and on shore operator in Cuba in early 2013 and has been working to secure a Production Sharing Contract with Cuba since then. In mid 2015 MEO Australia obtained an agreement for Block 9 which covers 2,380 square kilometers (919 square miles) of northern coast farmland about 130 kilometers (81 miles) to the east of Havana. Australian incorporated company Petro Australis acquired a back-in option on the same block last September. This contracted Block is close to the vast Varadero oil field. These companies have committed to an initial exploration sub-period of 18 months to examine existing data on Block 9. Depending on what’s discovered, the company will decide whether or not to continue oil exploration.

The French oil and gas company Total signed a deal with Cuba in May of 2015 to explore for offshore oil with CUPET.

In late 2015 Leni Gas Cuba Limited (London Ticker: ISDX:CUBA), a business incorporated in the British Virgin Islands, acquired 15 percent of Petro Australis Limited as an entry point for the company into the Cuban oil and gas industry.  Leni Gas Cuba signed a Cuba Block 9 Production Sharing with CUPET in September 2015.  These companies all feel that Cuban oil is a good investment though current prices are depressed.

Angola thinks in the same vein as the above mentioned companies. Its state-run company Sonangol is working with the Cuban oil company to restart deep-water exploration in Cuba. Sonangol contracted for four blocks close to the United States’ maritime border in the Gulf of Mexico. The two countries will begin work on two of them in 2016.

Until Congress lifts the US Cuban embargo, American companies are not interested and cannot participate. Cuba has extended “an open invitation” to the US.  Irregardless, there is sure to be heightened interest when the embargo is over.

Nigerian Oil Militants Claim 5 Attacks in Blow to Cease-Fire

 

http://www.bloomberg.com/news/articles/2016-07-03/nigerian-oil-militants-claim-5-attacks-in-blow-to-cease-fire

Niger Delta Avengers, a militant group operating in Nigeria’s southern oil-producing region, said it attacked five crude-pumping facilities overnight Sunday, dealing a blow to the government’s effort to enforce a cease-fire.

The targets included Chevron Corp.’s oil wells 7 and 8 and three trunk lines belonging to Nigerian Petroleum Development Corp., the exploration unit of the state oil company, according to tweets from an account claiming to represent the militants. The Twitter account hasn’t been verified.

“As a matter of long-standing policy, we do not comment on the safety and security of our personnel and operations,” Isabel Ordonez, a Chevron spokeswoman based in Houston, said in an e-mailed response to a request for comment. Garba Deen Muhammad, the spokesman of the state-owned Nigerian National Petroleum Corp., didn’t answer two calls made to his mobile telephone.

Attacks on oil facilities this year helped to cut Nigeria’s monthly oil production to about 1.4 million barrels a day in May, the lowest in almost three decades, according to the International Energy Agency. The supply interruptions have contributed to an increase of more than 80 percent in oil prices since benchmark Brent crude slid to a 12-year low in January. Brent ended 64 cents higher at $50.35 a barrel on Friday in London trading.

Petroleum Minister Emmanuel Kachikwu said on June 27 that a cease-fire agreement reached with the group has allowed repairs and restoration of output to about 1.8 million barrels a day.

Oil Trader Trafigura Profits From Growing U.S. Crude Exports

Oil Trader Trafigura Profits From Growing U.S. Crude Exports

[Bloomberg] - Over nearly 45 years, the oil tanks at Milford Haven on the U.K. west coast have stored dozens of crude varieties: from North Sea Brent to Nigeria’s Bonny Light and almost everything in between. Now, for the first time, they are holding U.S. crude too.

Trafigura Group Pte. is using Milford Haven, which can hold about 9 million barrels of crude and refined products in its 54 tanks, as a back-stop in a supply chain stretching about 8,000 kilometers (5,000 miles) from the oil ports of Texas to the refineries in north-west Europe, including the Rotterdam trading hub.

Since Washington lifted a 40-year-old ban on U.S. crude overseas sales in late 2015, Trafigura has been sending tankers across the Atlantic. Its recent pace of two to three 700,000-barrel-capacity Aframax tankers a month makes the trader one of the top exporters alongside BP Plc.

"It’s a growing business for Trafigura," Ben Luckock, the company’s global head of crude-oil trading, said in an interview at the terminal in southwest Wales. "We are in further discussions with a number of refiners for more U.S. crude."

Atlantic Crossing

The Advantage Avenue was the latest Aframax to make the Atlantic crossing, arriving in Milford Haven on July 8 with about 750,000 barrels of Eagle Ford shale oil loaded in Corpus Christi, Texas, according to ship-tracking data compiled by Bloomberg.

Its journey is only possible because the shale boom reversed decades of decline in American oil output. The U.S. imposed a ban on most crude exports after the 1973 to 1974 oil embargo by Arab members of the Organization of Petroleum Exporting Countries stoked fears about the nation’s growing dependence on imports. Those concerns have eased as a new generation of drillers used hydraulic fracturing to blast apart shale rocks, lifting the nation’s output to a 30-year high in June 2015.

Although output has dropped 12 percent in the past year as the industry was hit by the global price slump, U.S. exports rose to a record 660,000 barrels a day in May. Crude is flowing into Canada, China, Curacao, France, the Netherlands and the U.K., according to data from U.S. Census and the Energy Information Administration.

In addition to Trafigura, other independent traders such as Vitol Group BV and Gunvor Group Ltd. have exported U.S. crude. Gunvor used a similar technique to Trafigura for the export, relying on a terminal in Panama it co-owns as a back-stop for the shipment.

Milford Haven

The Milford Haven site started life as an Amoco refinery in the 1970s, receiving shipments of crude and selling refined fuels into the local market. Puma Energy BV, in which Trafigura owns a 49 percent stake, purchased the facility a year ago, shut down the crude-processing plant and transformed it into a storage terminal. Trafigura also has a Mediterranean hub -- nearly 6 million barrels of crude-storage capacity under long-term lease in tank farms operated by the Eilat Ashkelon Pipeline Co. Ltd in Israel.

The terminals allow cargoes to make a temporary stop if Trafigura doesn’t immediately have a buyer. When future prices are higher than current levels -- a structure called contango -- a brief period of storage can even boost profits because the final value of the sale increases. The facilities also allow the trader to blend high-quality U.S. oil with other grades, tailoring the crude to meet the exact needs of refiners, or split cargoes into smaller batches.

Cheaper Pipelines

Trafigura is benefiting from two trends to build its U.S. crude-export business. First, pipeline and railway fees to move oil from fields in Texas and Oklahoma to the ports of the U.S. Gulf of Mexico have become cheaper as U.S. production fell following the global price slump. The second is the discount of U.S. crude futures to international prices, which allows traders to make a profit moving oil from one shore of the Atlantic to the other.

"The level that seems to open the U.S.-to-Europe export arbitrage is about $1 a barrel between Brent and West Texas Intermediate,” Luckock said.

Brent futures for September delivery traded 69 cents a barrel above the same contract for West Texas Intermediate at 8:07 a.m. Monday on the London-based ICE Futures Europe exchange. The price difference, which reached a peak of $27.81 a barrel in late 2011, has narrowed as U.S. production declines. While the WTI discount has averaged 73 cents this year, it was wider than $1 for much of February and April.

The shipments from the U.S., together with an alliance with Russian state-owned Rosneft, have helped Trafigura to become the world’s second-largest independent oil trader, handling 4 million barrels a day of crude and refined products.

Markets - VLCC soft sentiment continues

 

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After the peak last week, the VLCC market saw rates drop by a point each day, as the softer sentiment continued. 

 

Charterers continued to drip feed the market, picking newbuilds and vessels coming out of drydock for their most recent requirements. With these vessels cleared out of the way, the list still looks ample for the current cargo flow, Fearnleys reported.

However, with more delays in China and a Typhoon due to hit South China next week, things might turn, but for now the summer months are really taking a toll on the market for the time being.

West African Suezmaxes saw activity easing off at the beginning of last week, with only a few ships being fixed.

At time of writing (Wednesday), we experienced steady cargo inquiry in the last couple of days for the 3rd decade out of WAFR, resulting in more tonnage getting absorbed without rates really going anywhere, due to the previous quiet period and tonnage build-up, Fearnleys said.

In the Med and Black Sea, last week proved to be busy with a combination of steady fixing and replacement jobs, which has pushed rates up in this area.

North Sea and Baltic both experienced another downward correction as the end/early rush came to a conclusion. Both markets seem to have bottomed out, and should be moving sideways at current levels for the week to come.

Med and Black Sea also saw a steady downward correction with rates bottoming at WS92.5. For the remainder of the week, it is likely that this rate will be repeated.

However, we expect that the market will firm up again, due to the number of cargoes scheduled to come out of CPC from the 20^th of this month, the question is - when and who will start the race, Fearnleys queried.

Among the fixtures reported by brokers recently were the 2012-built Suezmax sisters ‘Densa Whale’ and ‘Densa Orca’ thought taken by Stena Bulk for 12 months at $23,000 per day each.

Hindustan Petroleum was said to have fixed the 2003-built LR1 ‘Jag Padma’ for 12 months at $17,150 per day, while ST Shipping was thought to have fixed the 2007-built LR1 ‘United Ambassador’ for six months at $19,000 per day and Shell was reported to have taken the 2016-built Aframax ‘Lyric Mongolia’ for two to six months at $18,500 per day.

In the MR sector, Frontline was believed to have taken the 2012-built ‘Miss Benedetta’ for six months at $14,750 per day, while STI was said to have fixed the 2013-built ‘Zefyros’ for 12 months, option 12 months at $14,500 per day for the first period.

Reliance was thought to have fixed the 2004-built Handysize ‘Hafnia Adamello’ for 12 months at $15,650 per day, while STI was said to have taken the 2011-built Handy ‘Atria’ for six months for $13,500 per day. 

In the S&P market, Winson was believed to have purchased the 2000-built VLCC ‘BW Ulan’ at an unknown level. New Shipping was said to have spent $26 mill on the 2008-built Aframax ‘TH Sonata’, while the 2011-built Aframax ‘Nissos Kythnos’ was said to be on subjects to unknown buyers at $39 mill. 

The 1995-built MR ‘Sriracha Trader’ was believed committed to Middle East interests for around $3-4 mill.

In the newbuilding sector, ‘K’ Line has ordered three VLCCs and two Aframaxes from domestic shipyards.

The company is to build two VLCCs at Kawasaki Heavy Industries with deliveries scheduled for 2017 and 2018, while Namura Shipbuilding is to construct the third VLCC and two Aframaxes, which are due for delivery in 2018 and 2019.

K Line said that the orders form part of its fleet upgrading plan and that the vessels have been designed to comply with forthcoming regulations, including the Ballast Water Convention.

Elsewhere, Stream Tankers has ordered two, plus two optional 19,900 dwt stainless steel IMO II chemical tankers at Fukuoka for 2018-2019 deliveries. No price was revealed. 

Satellite photos show Islamic State installing hundreds of makeshift oil refineries to offset losses from airstrikes

 

Smoke rises from an oil refinery in Baiji, Iraq, in October 2015. (Reuters)

https://www.washingtonpost.com/news/worldviews/wp/2016/07/07/satellite-photos-show-isis-installing-hundreds-of-makeshift-oil-refineries-to-offset-losses-from-air-strikes/ 

With its refineries mostly destroyed and its tanker fleet under constant attack, the Islamic State is increasingly turning to low-tech alternatives for processing oil, a vital source of revenue for the terrorist group, new satellite images reveal.

Aerial photos taken near the northern Iraqi city of Mosul show scores of tiny, makeshift refineries popping up in oil fields controlled by the Islamic State, evidence that the jihadists are finding workarounds after losing much of their oil infrastructure to airstrikes.

The micro-refineries — sometimes called “teapots” — consist of little more than a ditch or pit for storing crude and a portable metal furnace used to distill raw petroleum into fuel. Thousands of such systems have long been in operation in the Islamic State’s Syrian strongholds, but now they’re sprouting up around the more established, though heavily damaged, Iraqi oil fields, said Omar Lamrani, a senior analyst for Stratfor, a private, Texas-based intelligence company.

“In a single oil field there can be hundreds of these makeshift operations,” said Lamrani, citing aerial imagery showing a constellation of tiny furnaces around a Mosul field that was mostly just sand a year ago. “It’s not the ideal way to do it, so their revenue is going down. But it still works.” The images were provided to The Washington Post by Stratfor and AllSource Analysis, a Colorado firm that specializes in geospatial research.

[U.S. jets abandoned Syrian rebels in the desert. Then they lost a battle to ISIS.] 

 

The tiny refineries are partly offsetting huge losses in income resulting from the disruption of traditional oil production in northern Iraqi fields controlled by the Islamic State since mid-2014. After capturing the facilities, the group’s leaders initially attempted to run them as businesses, retaining enough workers to keep the refineries operating and hauling the finished products by tanker truck to independent dealers in Turkey, Syria and Iraq’s Kurdish provinces, U.S. officials say.

At its peak, the Islamic State’s oil operations were netting an estimated $50 million a month. But the group’s oil income has plummeted in recent months, through a combination of poor management and a steady drumbeat of airstrikes that have targeted refineries and storage depots as well as tanker convoys.

The proliferation of micro-refineries is the latest sign of strain in the group’s self-declared caliphate, which has lost half its territorial holdings in Iraq since late 2014. At the same time, the use of low-tech alternatives also reflects a certain resilience by an organization that also depends on self-generated oil to run its military operations and electric generators, Lamrani said. Stratfor estimates that oil contributed about $20 million a month to the Islamic State's coffers as recently as March, with much of the petroleum coming from makeshift facilities.

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There are many drawbacks to the system. The small furnaces, which heat raw petroleum to a high temperature and then capture and cool the vapors to create gasoline, produce thick clouds of black smoke and leave pools of toxic byproducts on the surface. But because they are small and scattered, the "teapot" refineries are harder to destroy from the air. And any that are destroyed can be easily and cheaply replaced, oil industry experts say.

“This is very inefficient, dirty and creates lots of waste,” said Paul Bommer, a professor of petroleum engineering at the University of Texas at Austin. And yet, he said, “it is a way to make small amounts of product at isolated locations, which I suppose could make the sites harder to find.”