The break-even price for Permian basin tight oil plays is about $61 per barrel. That puts Permian plays among the lowest cost significant supply sources in the world. Although that is good news for U.S. tight oil plays, there is a dark side to the story.
Just because tight oil is low-cost compared to other expensive sources of oil doesn’t mean that it is cheap. Nor is it commercial at current oil prices.
The disturbing truth is that the real cost of oil production has doubled since the 1990s. That is very bad news for the global economy. Those who believe that technology is always the answer need to think about that.
Through that lens, Permian basin tight oil plays are the best of a bad, expensive lot.
Not Shale Plays and Not New
The tight oil plays in the Permian basin are not shale plays. Spraberry and Bone Spring reservoirs are mostly sandstones and Wolfcamp reservoirs are mostly limestones.
Nor are they new plays. All have produced oil and gas for decades from vertically drilled wells. Reservoirs are commonly laterally discontinuous and, therefore, had poor well performance. Horizontal drilling and hydraulic fracturing have largely addressed those issues at drilling and completion costs of $6-7 million per well.
Permian Basin Overview
The Permian basin is among the most mature producing areas in the world. It has produced more than 31.5 billion barrels of oil and 112 trillion cubic feet of gas since 1921. Current production is approximately 1.9 million barrels of oil (mmbo) and 6.6 billion cubic feet of gas (bcfg) per day.
The Permian basin is located in west Texas and southeastern New Mexico. It is sub-divided into the Midland basin on the east and the Delaware basin on the west, separated by the Central Basin platform.
The first commercial discovery in the Permian basin was made in 1921 at the Westbrook Field. It was followed in 1926 with the 2 billion barrel (bbo) Yates Field (San Andres & Grayburg reservoirs), the 2.1 bbo Wasson Field (Glorieta and Leonard reservoirs) in 1936, and the 1.5 bbo Slaughter Field (Abo and Clear Fork reservoirs) also in 1936. Reservoirs were chiefly high-quality limestones although the Wasson and Slaughter fields also produced from mixed sandstones and limestones that are equivalent to reservoirs in today’s Bone Springs tight oil play.
The Spraberry Field (1949) was the first discovery whose primary reservoir was among the present tight oil plays. Its ultimate production before horizontal drilling was estimated at 932 mmbo. The field had low recovery efficiency of 8-10% and was only marginally commercial prior to the recent phase of tight oil drilling.
Tight Oil Plays
I evaluated the three main tight oil plays. The Trend Area-Spraberry play is located mostly in the Midland basin while the Wolfcamp and Bone Spring plays are located mainly in the Delaware basin.
The Wolfcamp play has produced the most oil and gas—205 million barrels of oil equivalent (mmBOE)*—and has the largest number of producing wells, followed by the Trend Area-Spraberry and Bone Spring plays. All of the plays produce considerable associated gas and only the Trend Area-Spraberry is technically an oil play. The Wolfcamp and Bone Spring are classified as gas-condensate plays based on liquid yield.
The Bone Spring play is the most commercially attractive of the tight oil plays with an estimated $49 per barrel of oil equivalent (BOE) break-even price for the top 5 operators. The Spraberry play has a break-even price of $55 per BOE for the top 5 operators but considerably higher well density and, therefore, lower long-term potential. Results from the Wolfcamp play are mixed with an average break-even price of $75 per BOE for the top 5 operators but $61 per BOE excluding one operator with poorer well performance.
Trend Area-Spraberry Play
I evaluated the 5 key operators in the Trend Area-Spraberry play with the greatest cumulative production and number of producing wells: Pioneer (PXD), Laredo (LPI), Diamondback (FANG), Apache (APA) and Energen (EGN).
I did standard rate vs. time decline-curve analysis for those operators. The matches with production history were generally good.
Much of the gas production in the Permian basin is irregular because of periodic flaring so matching gas production history was sometimes difficult. Oil reporting in Texas is by lease rather than by well so there are periodic upward excursions of oil production as new wells on the same lease come on line. For these reasons, I feel that the decline-curve analysis results are probably optimistic.
The average Trend Area-Spraberry well EUR (estimated ultimate recovery) for the 5 operators is approximately 265,000 BOE using an economic value-based conversion of natural gas-to-barrels of oil equivalent of 15-to-1. The break-even oil price for that average EUR is approximately $55 per BOE. Laredo has the best average well performance with a break-even oil price of about $43 per BOE and Apache has the poorest well performance and highest break-even price of almost $92 per BOE.
The top 5 producers in the Wolfcamp play are Cimarex (XEC), Anadarko (APC), EOG, Devon (DVN) and EP (EPE).
The average Wolfcamp well EUR for the 5 operators is approximately 228,000 BOE. The break-even oil price for that average EUR is approximately $75 per BOE. That is because of poor well performance by Devon and EP whose break-even oil prices are more than $100 per BOE.
By eliminating EP from the calculations, the average EUR for the play is approximately 303,000 BOE and the associated break-even price is about $61 per BOE.
Anadarko has the best average well performance with a break-even oil price of about $45 per BOE and EP has the poorest well performance and highest break-even price of almost $177 per BOE.
Bone Spring Play
The top 5 producers in the Bone Spring play are Cabot (COG), Devon (DVN), Cimarex (XEC), Energen (EGN) and Mewbourne.
The average Bone Spring well EUR for the 5 operators is approximately 294,000 BOE. The break-even oil price for that average EUR is approximately $49 per BOE.
Cimarex has the best average well performance with a break-even oil price of about $42 per BOE and Mewbourne has the poorest well performance and highest break-even price of almost $78 per BOE.
Commercial Play Areas
I made EUR maps for the 3 Permian basin tight oil plays using all wells with 12 months of production. I then used the average play EUR to determine commercial cutoffs for $45 and $60 per BOE oil prices using the economic assumptions.
Using the calculated EUR-cutoffs for the two oil-price cases, 26% of Permian tight oil place well break even at $45 per BOE, and 40% break even at $60 per BOE price.
Current well density was calculated by measuring the mapped area of the $60 commercial area and dividing by the number of producing wells within those polygons. The Wolfcamp has the lowest well density of 1,269 acres per well and, therefore, the most development potential. The Bone Spring also has considerable infill potential with 725 acres per well.
The Trend Area-Spraberry has additional development potential but a comparatively lower current well density of 281 acres per well because there are more than 6,000 vertical producing wells within the $60 commercial area defined by horizontal well EUR. These vertical wells have produced 203 MMBOE to date, approximately equal to the 206 MMBOE for all horizontal wells both inside and outside of the commercial area.
Operators routinely stress the large number of potential infill locations in their investor presentations and press releases based on very close well spacing of, for example, 40 acres per well. Although well density is important for determining play life, I doubt that well spacing of much less than 100 acres per well is economically attractive because of potential interference between wells that are drilled horizontally and hydraulically fractured.
Investors should understand that more wells is not better. Superior economics result from drilling thefewest number of wells necessary to optimize production.
Operators also stress the potential for additional potential reservoirs within the same play reservoir. That is undoubtedly true but those are not yet discovered and are, therefore, resources and not reserves of any category based on the SPE Petroleum Resources Management System. If they are so attractive, why haven’t they been drilled and produced already?
*I use a 15 cubic feet per barrel equivalent conversion based on the price of natural gas and crude oil. The conversion based on energy content is approximately 6:1 and is used by most producers to calculate BOE EUR. The EUR reported by producers are, therefore, higher than those shown in this study especially for plays and wells with high gas-oil ratios.
Posted in The Petroleum Truth Report on June 19, 2016
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After the OPEC+ club met on September 1st, and confirmed that it would be sticking to its plan of increasing its crude supply by 400,000 b/d a month through December, China made a rather unusual announcement. It announced that it was going to release some crude oil from its strategic petroleum reserves, selling it to domestic refiners that were grappling with crude’s heady price rise over 2021. The release of strategic oil reserves isn’t news in itself. What is news is that the usually secretive China did it and did it publicly.
And it did it to send a message to OPEC+: attempts to create artificial scarcity to maintain crude prices will not be tolerated. China has a right to feel that way. Even though great strides have been made to ease the effects of the Covid-19 pandemic worldwide, the virus is still exerting major effects on the global economy. Not least a massive ripple through the health of global supply chains that has seen the price of almost everything – plastics, semiconductors, agricultural commodity, lumber, steel – spike due to supply issues. In some cases, the prices of raw materials are at historic highs. Crude oil is still nowhere near its peak of above US$100/b, but it is high enough to be concerning, especially since it is happening within a major inflationary environment. And for a manufacturing-heavy economy like China, that matters. That matters a lot. So China’s National Food and Strategic Reserves announced that it would be releasing some of the country’s crude stocks to ‘better stabilise domestic market supply and demand, and effectively guarantee the country’s energy security’, a month after the country’s producer price inflation – ie. the cost of manufacturing – hit a 13-year high.
China made good on that promise, releasing 7.38 million barrels from its stockpile to domestic bidders on September 24 with more tranches expected. This was the first ever recorded release from China’s Strategic Petroleum Reserves (SPR), which began back in 2009 in serendipitous response to crude oil prices exceeding the US$100/b mark for the first time in 2008. But curiously, it may not have been the first ever release. So secretive is the SPR that China does not reveal the size of the reserve, although analysts have estimated it at some 300-400 million barrels with total capacity of 500 million barrels using satellite imaging. It has been speculated that batches of crude from the SPR have been released before on the quiet. But this is the first time China has gone public. Compared to the country’s overall oil consumption, 7.38 million barrels is small, almost tiny. And even if additional supplies are released, it will not make a major impact on China’s oil balances. But the message is what is important.
It is a message that China is not alone in sending. US President Joe Biden has already called on OPEC+ to accelerate its supply easing plans, given indications that the crude glut built up over 2020 has been all but erased. It is a notion that would be supported by some OPEC+ members – Russia, Mexico, the UAE – but so far, the discipline advocated by Saudi Arabia has held. The US too has attempted to release of its own crude reserve stocks – the largest in the world with a capacity of 727 million barrels – but this was also in response to the devastating impact of Hurricane Ida. India, China’s closest analogue to size and stage, has been complaining too. As a major oil importer and with a shakier economic situation, India is particularly sensitive to oil price swings. US$70/b is way above what New Delhi is comfortable with. But since India’s appeals to OPEC+ have fallen on deaf ears, it is attempting domestic directives instead. India’s state refiners have been ordered to reduce crude purchases from the Middle East, but with supply tight, there aren’t many other people to buy from. India has also been selling oil from its strategic reserve – officially stated to be for clearing space to lease storage capacity to refiners – although since India is more transparent about these announcements, the announcement isn’t as surprising.
Will it work? At least immediately, no. Crude prices did come under pressure in the wake of China’s announcement, but then recovered with Brent hitting US$75/b. But the fact that China timed the announcement of the September 24 auction to coincide with peak global trading time and with a lot of details (again an unusual move) shows that Beijing is serious about wielding its strategic reserves as weapons. If not to moderate crude prices, then to at least stabilise it. But this is a war of attrition. China may very well have a planned schedule to release more crude reserves over 2021 and 2022 if prices remain high, but its supplies are finite. And they will have to eventually be replenished, possibly at an even higher cost if the attempt to quell crude price inflation fails. Thus far, the details of the SPR release hint that this is a tentative dip in the pool: the volume of 7.38 million barrels was far lower than the 35-70 million barrels predicted by some market participants. And because successful bidders can lift the oil up to December 10, it seems unlikely that a second auction for 2021 is in concrete plans at this point.
But, at the very least, the message has been sent. Beijing has a tool that it can wield if crude prices get out of hand, and it is not afraid to use it. The first step might have been small, and it is a giant leap in what mechanics are available to influence crude prices. And as history has proven, China can be very quick to scale up and very single-minded in its approach. Over to you, OPEC+.
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In 2021, the makeup of renewables has also changed drastically. Technologies such as solar and wind are no longer novel, as is the idea of blending vegetable oils into road fuels or switching to electric-based vehicles. Such ideas are now entrenched and are not considered enough to shift the world into a carbon neutral future. The new wave of renewables focus on converting by-products from other carbon-intensive industries into usable fuels. Research into such technologies has been pioneered in universities and start-ups over the past two decades, but the impetus of global climate goals is now seeing an incredible amount of money being poured into them as oil & gas giants seek to rebalance their portfolios away from pure hydrocarbons with a goal of balancing their total carbon emissions in aggregate to zero.
Traditionally, the European players have led this drive. Which is unsurprising, since the EU has been the most driven in this acceleration. But even the US giants are following suit. In the past year, Chevron has poured an incredible amount of cash and effort in pioneering renewables. Its motives might be less than altruistic, shareholders across America have been particularly vocal about driving this transformation but the net results will be positive for all.
Chevron’s recent efforts have focused on biomethane, through a partnership with global waste solutions company Brightmark. The joint venture Brightmark RNG Holdings operations focused on convert cow manure to renewable natural gas, which are then converted into fuel for long-haul trucks, the very kind that criss-cross the vast highways of the US delivering goods from coast to coast. Launched in October 2020, the joint venture was extended and expanded in August, now encompassing 38 biomethane plants in seven US states, with first production set to begin later in 2021. The targeting of livestock waste is particularly crucial: methane emissions from farms is the second-largest contributor to climate change emissions globally. The technology to capture methane from manure (as well as landfills and other waste sites) has existed for years, but has only recently been commercialised to convert methane emissions from decomposition to useful products.
This is an arena that another supermajor – BP – has also made a recent significant investment in. BP signed a 15-year agreement with CleanBay Renewables to purchase the latter’s renewable natural gas (RNG) to be mixed and sold into select US state markets. Beginning with California, which has one of the strictest fuel standards in the US and provides incentives under the Low Carbon Fuel Standard to reduce carbon intensity – CleanBay’s RNG is derived not from cows, but from poultry. Chicken manure, feathers and bedding are all converted into RNG using anaerobic digesters, providing a carbon intensity that is said to be 95% less than the lifecycle greenhouse gas emissions of pure fossil fuels and non-conversion of poultry waste matter. BP also has an agreement with Gevo Inc in Iowa to purchase RNG produced from cow manure, also for sale in California.
But road fuels aren’t the only avenue for large-scale embracing of renewables. It could take to the air, literally. After all, the global commercial airline fleet currently stands at over 25,000 aircraft and is expected to grow to over 35,000 by 2030. All those planes will burn a lot of fuel. With the airline industry embracing the idea of AAF (or Alternative Aviation Fuels), developments into renewable jet fuels have been striking, from traditional bio-sources such as palm or soybean oil to advanced organic matter conversion from agricultural waste and manure. Chevron, again, has signed a landmark deal to advance the commercialisation. Together with Delta Airlines and Google, Chevron will be producing a batch of sustainable aviation fuel at its El Segundo refinery in California. Delta will then use the fuel, with Google providing a cloud-based framework to analyse the data. That data will then allow for a transparent analysis into carbon emissions from the use of sustainable aviation fuel, as benchmark for others to follow. The analysis should be able to confirm whether or not the International Air Transport Association (IATA)’s estimates that renewable jet fuel can reduce lifecycle carbon intensity by up to 80%. And to strengthen the measure, Delta has pledged to replace 10% of its jet fuel with sustainable aviation fuel by 2030.
In a parallel, but no less pioneering lane, France’s TotalEnergies has announced that it is developing a 100% renewable fuel for use in motorsports, using bioethanol sourced from residues produced by the French wine industry (among others) at its Feyzin refinery in Lyon. This, it believes, will reduce the racing sports’ carbon emissions by an immediate 65%. The fuel, named Excellium Racing 100, is set to debut at the next season of the FIA World Endurance Championship, which includes the iconic 24 Hours of Le Mans 2022 race.
But Chevron isn’t done yet. It is also falling back on the long-standing use of vegetable oils blended into US transport fuels by signing a wide-ranging agreement with commodity giant Bunge. Called a ‘farmer-to-fuelling station’ solution, Bunge’s soybean processing facilities in Louisiana and Illinois will be the source of meal and oil that will be converted by Chevron into diesel and jet fuel. With an investment of US$600 million, Chevron will assist Bunge in doubling the combined capacity of both plants by 2024, in line with anticipated increases in the US biofuels blending mandates.
Even ExxonMobil, one of the most reticent of the supermajors to embrace renewables wholesale, is getting in on the action. Its Imperial Oil subsidiary in Canada has announced plans to commercialise renewable diesel at a new facility near Edmonton using plant-based feedstock and hydrogen. The venture does only target the Canadian market – where political will to drive renewable adoption is far higher than in the US – but similar moves have already been adopted by other refiners for the US market, including major investments by Phillips 66 and Valero.
Ultimately, these recent moves are driven out of necessity. This is the way the industry is moving and anyone stubborn enough to ignore it will be left behind. Combined with other major investments driven by European supermajors over the past five years, this wider and wider adoption of renewable can only be better for the planet and, eventually, individual bottom lines. The renewables ball is rolling fast and is only gaining momentum.
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