One of Canada’s top energy analysts has warned investors and geologists that “the shale revolution” will not meet conventional expectations as a so-called game-changer in energy production.
Speaking at the Denver meeting of the Geological Society of America and later at Queen’s University and an energy conference in Toronto, David Hughes challenged the assumptions of industry cheerleaders by spelling out startling depletion rates for high-cost unconventional shale and tight oil wells.
“The shale revolution has been a game-changer in that it has temporarily reversed a terminal decline in supplies from conventional sources,” said Hughes in both talks given in late October and early November. “Long-term sustainability is questionable and environmental impacts are a major concern.”
The geoscientist, who now lives on Cortes Island, has studied energy resources in Canada for four decades, including 32 years with the Geological Survey of Canada as a coal and natural gas specialist.
After reviewing data from unconventional oil wells, Hughes found that these difficult and high-cost operations deplete so rapidly that between 47 to 61 per cent of oil from plays like the Bakken, the first major tight oil play developed, is recovered within the first four years.
Hughes noted that the Bakken and Texas’ Eagle Ford plays, which currently produce two-thirds of U.S. tight oil and are supposed to take the country into energy independence territory, will actually peak in production by 2016 or 2017.
ncredibly, most tight oil wells, such as in North Dakota’s booming oilfields, will become “stripper wells” (producing less than 10 barrels a day) and be ready for abandonment within 11 to 24 years.
Shale no panacea
Shale gas wells follow a similar decline profile. In Louisiana’s Haynesville play and Pennsylvania’s contentious Marcellus fields, producing wells decline by as much as 66 per cent after the first year.
More than 3,500 wells have been drilled in the Haynesville play, which in 2012 was the top-producing shale gas play in the U.S., yet production is falling owing to the 47 per cent yearly field decline rate. The current price of gas is not high enough to justify the 600-plus wells needed annually to offset the steep field decline (each well costs between $8 to $10 million).
“The shale revolution has provided a temporary respite from declining oil and gas production, but should not be viewed as a panacea for increasing energy consumption… rather it should be used as an opportunity to create the infrastructure needed for a lower energy throughput to maximize long-term energy security,” warned Hughes.
Hughes also told investors that they can no longer ignore the real and high-cost environmental issues associated with hydraulic fracturing, including high water consumption; groundwater contamination; methane leakage; land fragmentation; air pollution and property devaluation.
“There has been a great deal of pushback by many in the general public, and in state and national governments, to environmental issues surrounding hydraulic fracturing,” he said.
Quebec, Labrador and Newfoundland have declared moratoriums on the technology of high-volume horizontal hydraulic fracturing. In addition, Canada’s largest private sector union representing a high percentage of energy works has called for a national moratorium.
Although the number of gas-producing wells in Western Canada has reached an all-time high of 230,000 wells, actual gas production has been in decline since 2006.
Hughes also noted that the quality of shale oil and gas plays varies greatly. A few are prolific because they have sweet spots, he said. These special zones are targeted first and lead to an early rise in production followed by a decline, often within five years or less.
As a result, 88 per cent of shale gas production comes from just six of 30 plays, while 70 per cent of all tight oil production comes from two of 21 plays: North Dakota’s Bakken and Texas’ Eagle Ford.
Bad omens for BC
Rapid depletion rates, high capital costs and low market prices do not bode well for British Columbia’s much-hyped plans to export shale gas to Asian markets via a liquefied natural gas (LNG) system that currently does not exist.
“In terms of B.C., the well depletion will be similar. All of the fields outside of the Horn River and Montney plays are in decline,” Hughes told The Tyee in an interview.
“The province would have to nearly quadruple gas production just to satisfy the demands of five LNG terminals.” As many as 12 terminals have been proposed for B.C. “It’s a huge scaling problem.”
The government of Premier Christy Clark has championed LNG development as the province’s new economic miracle by subsidizing geoscience, roads and water for shale gas companies.
It has also lowered royalties. Income from shale gas peaked in the province in 2006 at more than $2 billion and has since fallen to less than $400 million, excluding government subsidies.
Due to depressed natural gas prices, the shale gas industry has written down billions of dollars worth of assets and refocused drilling on more lucrative liquid rich formations. Other companies have lobbied strongly for government subsidies for LNG exports.
Rex Tillerson, CEO of Exxon Mobil, a multi-billion dollar shale gas investor, exclaimed last year that the industry was making no money: “It’s all in the red,” he said.
Royal Dutch Shell has written down $2 billion in shale assets and even put its Texas Eagle Ford properties up for sale. Meanwhile, one of its senior executives has complained that the industry has “over fracked and over drilled.”
Encana, one of the largest holders of shale gas real estate in B.C., has sold off many assets andlaid off 20 per cent of its workforce due to poor investments in uneconomic shale gas plays.
The company pioneered the transformation of landscapes across the West, with industrial clusters of wells combining horizontal drilling with multistage hydraulic fracturing. The 10-year-old mining technique blasts large volumes of water, sand and toxic chemicals into dense rock formations up to two miles underground.
PITTSBURGH (AP) — In at least four states that have nurtured the nation’s energy boom, hundreds of complaints have been made about well-water contamination from oil or gas drilling, and pollution was confirmed in a number of them, according to a review that casts doubt on industry suggestions that such problems rarely happen.
The Associated Press requested data on drilling-related complaints in Pennsylvania, Ohio, West Virginia and Texas and found major differences in how the states report such problems. Texas provided the most detail, while the other states provided only general outlines. And while the confirmed problems represent only a tiny portion of the thousands of oil and gas wells drilled each year in the U.S., the lack of detail in some state reports could help fuel public confusion and mistrust.
The AP found that Pennsylvania received 398 complaints in 2013 alleging that oil or natural gas drilling polluted or otherwise affected private water wells, compared with 499 in 2012. The Pennsylvania complaints can include allegations of short-term diminished water flow, as well as pollution from stray gas or other substances. More than 100 cases of pollution were confirmed over the past five years.
Just hearing the total number of complaints shocked Heather McMicken, an eastern Pennsylvania homeowner who complained about water-well contamination that state officials eventually confirmed.
“Wow, I’m very surprised,” said McMicken, recalling that she and her husband never knew how many other people made similar complaints, since the main source of information “was just through the grapevine.”
The McMickens were one of three families that eventually reached a $1.6 million settlement with a drilling company. Heather McMicken said the state should be forthcoming with details.
Wyoming has a well capping and reclamation fund shortfall. 19,000 idle wells, 58,000 total. That’s one state. The area around Gillette is covered with wells. Why so many? The excessive depletion. In order to keep the gas coming, wells have to be drilled at a very high rate. That increases costs. Some drillers go bust. And increasingly, that leaves the state on the hook for remediation costs.
http://content.govdelivery.com/attachments/WYGOV/2013/12/10/file_attachments/256827/DRAFT%2BPLAN%2BORPHAN%2BIDLE%2BWELLS.pdf
Sorry for the long URL, but this PDF is pay dirt. Everyone should view it if they care and have some time.
Well I’m sort of back, but in insomnia mode as a function of jet lag…
Just from reading investment articles on Seeking Alpha, i gather these drillers will pull their drilling equipment out of a well that’s not yet expended in order to use that equipment somewhere else down the road. I’ve forgotten why they do this, but I’m speculating it has to do with accounting tricks or time requirements in mineral leasing contracts. Or in other words the abandonment of a well may not have only to do with its local economic worth or productivity; or lack there of. If the price of gas jumps significantly, they or someone else can come back later and re-tap wells. Also it should be noted that in some instances they can reclassify the stuff their pulling up for accounting purposes: one day they’ll classify it a gas, the next day, oil.
Just examining the graph above, it’s declining a bit slower than if it were obeying a first order decay, but since i’m too lazy to try to roughly model multiple wells coming online in a spread sheet program, I’ll pretend its decline has some elegance to it:
the elimination rate constant of one well looks to me to be about [ln7500 – ln3750]/8months or 0.086units/month.
So if in a hypothetical situation where they drilled a new well every 1 month then their maximum productivity would be 7500/[1-e^(-0.086*1)] = around 91,000 units of production and the minimum production would be 7500*[e^(-0.086*1)]/(1 – e^(-0.086*1)) = around 84,000 units of production.
So imagine a curve that has a shark’s teeth effect where the points of the teeth are 91k and the troughs between the teeth are 84k.
If they drilled a new one every 15 days, then their max production is 178,000 units of production and the troughs are 170,000 units of production. And if they did it every 2 months their max is 47,000 and min is 40,000. So you can see how significantly the rate in which they start a new well effects their production max and minimums.
All these numbers are on the low end because the decline is actually slower than a simple math formula can model it.
I like this comment. It does paint an interesting and informative picture, and without becoming a seventeen-part gallop filled with quotes and obfuscatory links. I’m not going to spend the day trying to “check the math”, because it looks good to me at first glance. Thank you, Andrew Hope you recover from the jet lag soon—-I’m fighting “dumb old guy getting up lag” myself this a.m.
Thanks oldguy – yeah, my back-of-the-envelope method isn’t as good as marking down coordinates off the graph, loading them into a spreadsheet and copy and pasting the data with prescribed lags then summing them to get a more accurate picture, but what becomes clear in my example is:
1) if they are making new wells at a steady rate then there is a defined maximum in productivity. The only way to continuously increase production after a steady state is reached is to accelerate new drilling: a new well every 30 days, 25 days, 20 days,…,1 day, 1/2 day, 1/4th day…
2) this implies an accelerated capital expenditure. The companies will have to reinvest revenue at an accelerated rate or suffer lack of organic revenue growth. In the end they’re going to have a lot of drill rigs, a bunch of torn up earth, and a need to sell those rigs off to another company in a game of musical chairs (or musical drill rigs). I’m sure they have lots of smart folks that know how to chase the curve back down so I’m hyperbolizing the situation with a simple summary, but someone in the future will eventually get stuck with having to sell that equipment at a loss.
No matter what angle you look at it from, it’s not a very good investment unless we get into a situation where an acute finiteness is universally recognized whilst no alternative is readily available, and the price of gas steadily marches upward, predictably. I would avoid it as an investment. You just can’t defeat the finiteness of the situation…
Again well said.
Those fracker’s in Wyoming also illegally hydro-frack coal seams. They don’t call it fracking though, because of its illegality; they call it ‘water enhancement’.
Ah yes, the sins we commit in the name of “enhancement” (enhancement of the pocketbooks of the out-of-control freemarketers, that is)
Yes, fracking has been going on in Wyoming since at least 2010. It was in papers spring of that year. It’s difficult to dissect oil, fracking, and gas. They all drill. In fact, in PA, they draw off some oil to get a profit that lasts longer. The same well can deliver both. In the Dakotas, the gas is a nuisance, because they want oil in the Bakken. They all get drilling subsidies. Gas is by far the most damaging to the site, because they have to drill so much to keep it going. Both tar sands and fracking are desperate last ditch measures to sustain Oruro fossil fuel addiction. There is poor oversight. I cited a u tube video where a guy said the authorities looked the other way on shale oil rail transport dangers. In Wyoming, there ain’t much. Everyone wants a paycheck. This kind of burn the chairs and table is going nowhere. They should be working on wind, solar, and insulation. Or maybe hi voltage grid.
You have the picture rights with gas at low prices, the boom turned to bust. Patriot in wy, went belly up, leaving the wells behind. Some drillers capped to wait for a better price later, but that is a tightrope with so much tied up in expensive drilling. That caught many companies in a squeeze trying to pay back the debt. Yes, there are frack wells drilled under false pretenses as coal bed methane.
And speaking of water contamination:
I’m presently in S. Charleston, WV to visit my parents and friends from my hometown. A few days ago (last Thursday), a chemical company that supplies chemicals to the coal industry encountered a leak and spill from one of their large holding tanks of 4-methylcyclohexane methanol. About 7,500 gallons spilled into the river, and just a mile downstream from that is the main water intake for the WV American Water Company that supplies the city (and towns and cities nebulous to the region) with fresh tap water.
My parents live about 2 miles from that.
About 300,000 people don’t have clean water. No showering, bathing, washing cloths, drinking, watering plants, etc… We’re looking at 2ppm of the junk in the water, which is now falling. CDC says that 1ppm is ‘safe’ but their methodology for determining that is a bit ill informed:
There are no studies showing how the stuff affects humans, but they have a LD50 for rats (825mg/kg). So they take that number, arbitrarily multiply it by 0.01, creating the number 8.25mg/kg. Then they again arbitrarily round that number down to 1mg/kg. There seems to be little scientific basis for what they are doing; they’re just saying ‘less is better’. Either that or the journalism in the area is of such poor quality that they are not properly explaining what is happening. Somehow they’re conflating 1mg/kg of body weight with 1ppm of water concentration. The material data safety sheet is pretty much blank, other than the LD50 and a small missive about skin irritation upon contact. The LD50 rat study was done by the chemical company in 1990 and is not part of peer review. The 1/2 life in water is about 2 weeks, so by 12-14 weeks hydrolysis should take care of it, though nobody is talking about what entities these things break down into, which again seems scientifically incompetent.
It rained yesterday, so I went out back and washed off with a little soap and some rain water – glad that Arctic air is somewhere else presently – ha, ha! But I can sympathize with the people whose well water in PA is affected by the fracking.
Anyway, I’m getting ready to head down to the western part of the state to visit a friend for a few days; there’s no internet there so I’ll be offline for a few days…
It’s just a few parts per million. How can it have any effect?
Yeah, what are you, an “alarmist”? Just keep drinking your bottled water and rolling in the snow to get clean instead of taking showers. It’ll be over soon, and you wouldn’t want the chemical company’s bottom line to suffer because of unwarranted hysteria, would you? It’s not like you had another Bhopal or anything (although I have read a number of studies that say W VA is where it will likely happen if we have one).
Ha! – even at somewhere under 1ppm it still smells like liquorice.
I just got back to Charleston, but whilst i was gone my folk’s area was given the OK to use the tap water after a prescribed ‘flush’ (which entailed leaving all the taps open for instructed times and running the washers empty).
I don’t plan on drinking any of that <1ppm water until my next visit, next summer, when it should be under detectable levels. It's a shame as the tap water around here was always better tasting than the bottled stuff…
Right on cue. Gas prices increase in 2013, coal increases and so does co2. So much for cheap gas being a bridge and lowering co2.
http://thinkprogress.org/climate/2014/01/13/3153671/carbon-pollution-jumped-2-percent/