David Yager – Yager Management Ltd.
Oilfield Service Management Consulting – Oil & Gas Writer – Energy Policy Analyst
April 12, 2017
The old saying goes, “Everything’s bigger in Texas”. The latest subject of this axiom is the legendary Permian Basin. The recent headlines have been eye-popping. “The Permian Basin Keeps On Giving”. “A $900 Billion Oil Treasure Lies Beneath West Texas Desert”. “Shell’s New Permian Play Profitable at $20 A Barrel”. “The World’s Hottest Oil Play”. “Permian Basin Prevails”. “The Permian Basin: An existential Threat To Canadian Oil As The War On Cost Heats Up”. “This Texas Oilfield Is Messing With OPEC”.
The articles contain analysis and commentary concluding no matter what happens in the rest of the world, the future of oil prices will be heavily influenced by U.S. light tight oil (LTO) producers and more specifically, the Permian. This is more of the popular thesis OPEC is dying or dead and the United States has replaced Saudi Arabia as the world’s swing producer.
Except it’s not true. If you believed every word you would conclude there are only two sources of oil on earth: the Permian Basin and everyone else. While the Permian is wonderful and significant mass of hydrocarbon-rich formations, its impact on world oil prices in the next few years is overstated.
A typical pro-Permian article appeared in Forbes November 21, 2016 under the title “The Permian Keeps On Giving”. It followed a report by the U.S. Geological Survey (USGS) following a new assessment of the Permian including a relatively undeveloped horizon called the Wolfcamp shale. The USGS reported some 20 billion barrels of oil was yet to be discovered and is technically recoverable; “The fact that this is the largest assessment of continuous oil we have ever done just goes to show that, even in areas that have produced billions of barrels of oil, there is still the potential to find more”.
The article defined undiscovered resources as having 50% confidence the entire 20 billion was there, a 95% chance of 11 billion barrels, and a 5% opportunity the horizon might eventually yield 31 billion barrels. That’s more oil than the Permian Basin has produced in the past 96 years.
News about new possibilities began September 7, 2016 when Apache Corp. announced it had assembled a large land position on the southern edges of the Permian and identified what Bloomberg report called, “…what could be a major new oil play at rock-bottom prices”. Apache estimated its lands hold 3 billion recoverable barrels and 75 trillion tcf of gas. Apache figured it had 2,000 to 3,000 drilling locations economic with US$50 oil and US$3 gas.
Following the USGC report Bloomberg ran a headline reading, “A $900 Billion Oil Treasure Lies Beneath the West Texas Desert”. Expanding on the Wolfcamp assessment, Bloomberg wrote, “That’s almost three times larger than North Dakota’s Bakken play and the single largest U.S. unconventional crude accumulation ever assessed. At current prices, that oil is worth almost US$900 billion”. Of course, that’s if every barrel is discovered and recovered and before any costs.
There is no doubt the Permian Basin is an amazing collection of hydrocarbon bearing rocks. Since production began in 1921 from this 75,000 square mile area, the multi-zone mammoth has yielded 29 billion barrels of oil and 75 trillion cubic feet of gas. The Texas Railroad Commission website reports it could produce that again. The Permian holds some 450,000 wellbores, only 100,000 less than have ever been drilled in Canada. While most of it is in Texas, a portion extends into New Mexico.
Despite rising land and service costs, Permian geology is certainly favorable thanks to ongoing technical advancements. Many operators claim to make money at US$50 or less. Global players like Exxon Mobil, Royal Dutch Shell, Chevron and Conoco-Phillips are looking to spend more in West Texas and less elsewhere. Two of those operators have recently sold much of their Canadian oil sands production to fund quicker returns in U.S. shale. Bloomberg’s article March 21 titled “Big Oil’s Plans To Buy Into The Shale Boom” reported Exxon Mobil Corp., Royal Dutch Shell Plc and Chevron Corp. are “…planning to spend a combined $10 billion this year, up from next to nothing only a few years ago”.
The article reinforced the idea that U.S. shale drilling, particularly in the prolific Permian, may affect world oil markets. “Big Oil’s drive into shale could weaken the hand of Saudi Arabia and other big exporters by raising U.S. output.”
Permian activity has responded to higher prices, lower service costs and new geological opportunities. The Baker Hughes weekly rig count April 7 reported nearly half the 672 U.S. rigs drilling for oil were in the Permian Basin, up 230% from a year ago. None of the other regions like Bakken or Eagle Ford have responded as strongly. The Permian is producing 2.2 million b/d, double that of 2011. Washington’s Energy Information Agency (EIA) figures the U.S. will exit 2018 with record production of 9.73 million b/d, higher than its 2015 peak of 9.61. Output from the lower 48 states will be 1 million b/d higher next year than 2016. The Permian will surely account for much of that increase.
But Permian excitement started going over the top with another article in Forbes February 12 titled, “The World’s Hottest Oil Play”. While stating all the reasons why the Permian Basin matters, the writer added, “The only conventional oilfield worldwide that is definitely producing more oil than the Permian Basin is Saudi Arabia’s mammoth Ghawar Field”, still at 5 million b/d after several decades on production. “But unlike Ghawar, Permian production is growing rapidly. This is primarily because much of the Permian consists of multiple layers of oil and gas bearing strata, some of which can boast break even costs that are lower than for most other U.S. formations”.
Comparing unconventional multi-zone opportunities in the Permian to conventional production from one big pool elsewhere is comparing apples to oranges. Discovered in 1948, Ghawar has proven to be the largest oilfield in the world by any measure. In an article published by GEO ExPro in 2010, the author highlighted what was called Ghawar’s Magnificent Five, the best wells in the field. The table has been reproduced below.
1 – Cumulative Production to 2008, millions of barrels
2 – Years on production to 2008. Uthmanihay is unknown
Source: Saudi Aramco Dimension magazine, fall 2008
One can only imagine what the initial output of these wells might have been using modern drilling and completion techniques or how little of the reservoir was perforated to unleash these huge flow rates.
After Saudi Arabia fully nationalized its oilfields in 1980 it was not always forthcoming with reserve data, therefore estimates of how much oil Ghawar holds are not consistent. The GEO ExPro article published original oil in place estimates at 250 to 300 billion barrels. In 2010 Saudi Aramco revealed Ghawar had already yielded 65 billion barrels with estimated recovery of 100 billion barrels.
This is the world’s greatest conventional reservoir by any measure. GEO ExPro wrote “Oil from Ghawar has a density of 30-34o API. The oil column in the field has been reported to be 396m (1,299 feet)”. The average depth is only about 7,000 feet or 2,150 metres.
The amount of cheap oil to come out of a reservoir is a factor of geology, not location. Last fall Calgary website BOE Report carried an article indicating there were 41 wells in Alberta that had yielded over 10 million barrels of oil each, all from classic carbonate reef pools. The best well, drilled at Golden Spike in 1948, recovered 39.7 million barrels of oil and 37.3 bcf of gas. Using public government data packaged by Petro Ninja, the article identified 15 wells drilled into conventional reefs drilled between 1948 and 1966 that had yielded over 15 million barrels of oil and from 3.2 to 64 bcf of gas.
New opportunities in the Permian Basin are completely different. USGS wrote, “The geology of the Permian Basin is rich and complex, both horizontally and vertically. The Permian Basin has commercial accumulations of oil land gas in stacked layers, at depths ranging from 1,000 feet to more than 25,000 feet.” While the Permian is indeed yielding new horizons that respond well to extended reach horizontal drilling and multi-stage fracturing, this is not conventional oil. Conventional production flows without fracturing (although carbonate reefs are frequently acidized to enhance flow through the reservoir). All conventional wells cited thus far were vertical.
LTO, on the other hand, is unlocked by capital and technology; increasingly longer horizontal wellbores into reservoirs fractured by growing quantities of high pressure fluid to create paths to the wellbore propped open by tons of frac sand. Shell reports some of its new wells go 10,000 feet down and over 5,000 feet sideways with the hydrocarbons increasingly unlocked by 50 or more separate fracs.
Another over-the-top Permian article by CNN Money March 30 was titled, “This Texas Oilfield Is Messing With OPEC”. About the Permian CNN wrote, “Some are even predicting this hotbed of shale activity could eventually surpass the colossal Ghawar field in Saudi Arabia as the world’s biggest oilfield. The Permian’s rise on the global stage couldn’t come at a worse time for OPEC”. An oil analyst added, “The Permian is the best, by far. It has established itself as the premiere oil basin the U.S. and potentially the world”. Wow.
So what’s going on in the rest of the world? The EIA estimates by the end of 2018 world oil demand will bust through 100 million b/d for the first time, some 3 million b/d higher than the first quarter of 2017. When U.S. production hits a new high in 2018, 200,000 b/d will come from offshore Gulf of Mexico. Canada will contribute another 150,000 b/d from new oil sands plants. Brazil and Russia might add 100,000 b/d. That’s it for non-OPEC oil producers. Every other OECD oil producing country will see flat production or declines.
In addition to 1.1 million b/d from North America, OPEC will increase output by about 700,000 b/d. Baker Hughes reports there were 386 rigs drilling in the Middle East in March, about the same number as the past five years. This indicates F&D costs are less than recent low prices. Because of the prolific nature of the reservoirs, 386 is all the rigs required to sustain 25 million b/d of production.
The last time only 386 rigs were operating in the U.S. production declined significantly. From a peak of 9.610 million b/d in June 2015 the EIA reports production fell 12.3% in the 13 months to a low of only 8.428 million b/d in July 2016. The 331 rigs currently drilling in the Permian will certainly increase production in the next year. But if that was the only place America drilled, the country would likely see production decline.
The fact the Permian might produce 1 million b/d more sometime next year is not particularly significant in the context of global oil markets. Canada’s oil sands will exceed 3 million b/d by 2020. If the EIA is right, by the end of next year the Permian will on account for 3% of global supply after a 50% increase from current levels. At 5 million b/d, it’s only this decade that Ghawar fell below 6%.
How can the tail of a basin that has been producing for almost a century wag the world oil dog? It can’t, and more writers and analysts should broaden their perspective.
An analysis by HSBC Bank released in September 2016 year warned of pending oil shortages due to depletion. Titled “Global Oil Supply – Will mature field declines drive the next supply crunch?”, the authors estimate average decline rates from existing production to be nearly 8% annually for non-OPEC fields and 4.2% from OPEC producing assets. As noted above, U.S output fell 12.3% in only 13 months. HSBC’s model sees slight oil shortages beginning this year (demand exceeding supply) and expanding through 2020.
The problem is the size of the recent discoveries. While a single well in Ghawar once yielded 20 to 100 million barrels and even Alberta discovered a few monsters, the Estimated Ultimate Resource (EUR) from one LTO well in the Permian is a tiny fraction of that amount. An article in Oil & Gas Financial Journal in May 2016 examined reported single well EURs from the Permian from 2012 to Q1 2016. While they improved over the period largely due to longer horizontal intervals, increased frac density and more frac sand, it will take an enormous amount drilling to move the needle on a global basis.
The wells are expensive and not big. In 2012 only 15% of the wells were likely to yield more than 600,000 barrels of oil equivalent (boe). By 2015 about 78% of newly drilled wells fell into that category thanks to better rocks, better techniques or both. In 2012 only 2% were likely to produce over 1 million boe. By 2015 that was 12%. F&D costs are indeed falling, partly because collapsed service prices and partly because of technical advances.
But going back to Ghawar, the average cumulative production per well for the Magnificent Five was 69 million barrels nine years ago. Crude oil. If the average EUR for the wells studied in the article was about 500,000 boe – with the gas/liquids ratio unpublished – that’s an average of 7/10 of one percent of the best wells in Ghawar. Many of these wells are very gassy so it’s not all crude. And the EUR is, by definition, an estimate. Only time will tell if this will translate into recovery.
But if they each yielded 400,000 barrels of oil, getting 20 billion barrels out of Wolfcamp – if this is possible – would require 50,000 new wellbores. There were only 1,572 wells permitted in the Permian in Q1 2017. Not all were drilled and of those drilled not all were competed. But drilling and service companies will be thrilled if the operators try.
Writing three months before December’s OPEC meeting, HSBC concluded, “We expect the past two years’ severe crude price weakness to result in a return to balance in the global oil market in 2017. At that stage, we expect global effective spare capacity to fall to as little as 1% of demand. Supply disruptions have had only limited impact on price in 2015-16 due to the global oversupply, but the market will be much more susceptible to interruptions post-2017. In addition, given the almost unprecedented fall in industry investment since 2014 we expect the focus to return to the availability of adequate supply.”
Higher prices because of tightening supply as demand marches on.
In early March the International Energy Agency (IEA) issued its mid-term report on global supply/demand to 2020. While acknowledging the opportunities in the Permian, the bigger problem is significant. “We are witnessing the start of a second wave of U.S. supply growth, and its size will depend on where prices go,” said Dr Fatih Birol, the IEA’s Executive Director. “But this is no time for complacency. We don’t see a peak in oil demand any time soon. And unless investments globally rebound sharply, a new period of price volatility looms on the horizon.”
That there’s more oil than previously thought in the Permian is great. That there are rigs and employees going back to work is fantastic. Having the U.S. import less oil from rogue nations because of rising domestic production is wonderful. This is not bad news. Lots of Canadian companies, both E&P and services, are enjoying growing opportunities in the Permian Basin.
So drill, baby, drill. The world will need every barrel American rigs, capital and ingenuity can unlock from this huge and secure oil rich region. But the Permian Basin alone is unlikely to yield enough new production to prevent higher prices or materially displace world oil markets for Saudi Arabia or OPEC.
About David Yager – Yager Management Ltd.
Based in Calgary, Alberta, David Yager is a former oilfield services executive and the principal of Yager Management Ltd. Yager Management provides management consultancy services to the oilfield services industry in a number of areas including M&A, Strategic Planning, Restructuring and Marketing. He has been writing about the upstream oil and gas industry and energy policy and issues since 1979.