Pumped Hydro Storage (PHS)

Preface. This is the only commercial way to store energy now (CAES hardly counts with just one plant and salt domes to put more in existing in only 5 states). Though of course hydropower is only in a few states as well, 10 states have 80% of hydropower, and PHS needs to go far above existing reservoirs. There are very few places this could be done.

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report

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Pumped hydro storage generates power by using electrically powered turbines to move water from a lower level at night uphill to a reservoir above.

During daylight hours when electricity demand is higher, the water is released to flow back downhill to spin electrical turbines. Locations must have both high elevation and space for a reservoir above an existing body of water.

Pumped hydro uses roughly 20–30 % more energy than it produces, with more electricity required to pump the water uphill than is generated when it goes downhill. Nonetheless, pumped hydro enables load shifting, and is important to balance wind and solar power.

Appearances can be deceiving: Pumped hydro is not a Rube Goldberg scheme. Many of you have used a kilowatt or two of pumped hydro yourself. PHS accounts for over 98 % of what little current energy storage exists in the United States, and is the only kind of commercial storage that can provide sustained power over 12 hours (typically, the other 12 hours are spent pumping the water up).

Existing PHS facilities store terawatts of power annually, but account for less than 2 % of annual U.S. power generation. This isn’t likely to increase much, since like hydroelectric dams, there are few places to put PHS. Only two have been built since 1995, for a grand total of 43 in the U.S., with most of the technically attractive sites already used (Hassenzahl 1981).

Existing PHS in the U.S. can store 22 GW, with the potential for another 34 GW more across 22 states, though high cost and environmental issues will prevent many from being built. Additionally, saltwater PHS could be built above the ocean along the West coast, but so far the high cost of doing so, shorter lifespan due to saltwater corrosion, distance from the grid, and concerns of salt seepage into the soil have prevented their development. Underground caverns and floating sea walls are other possibilities, but also aren’t commercial yet.

PHS has a very low energy density. To store the energy contained in just one gallon of gasoline requires over 55,000 gallons to be pumped up the height of Hoover Dam, which is 726 feet high (CCST 2012).

In 2011, pumped hydro storage produced 23 TWh of electricity across the U.S. However, those plants consumed 29 TWh moving water uphill, a net loss of 6 TWh.

So, how many PHS units would it take to give the U.S. that one day of electricity storage, 11.12 TWh? Over 365 days, our 43 existing pumped hydro plants produced two days of energy storage (23 TWh). Thus, the U.S. would need more than 7800 additional plants (365/2 * 43). Rube Goldberg, I can imagine what you would make of this.

References

CCST. 2012. California’s energy future: electricity from renewable energy and fossil fuels with carbon capture and sequestration. California: California Council on Science and Technology.

Hassenzahl, W.V. ed. 1981. Mechanical, thermal, and chemical storage of energy. London: Hutchinson Ross.

Posted in Dams, Energy Production, Pumped Hydro Storage (PHS) | Tagged , , , , | 1 Comment

The 10 countries with the most endangered species in the world

I don’t know whether to go to these countries to see these beautiful creatures before they’re extinct, or to spend my money on countries like Costa Rica and Tanzania that have set aside a quarter or more of their land to preserve biodiversity.

An excessive number of people using half the land and what it produces on the planet is what’s driving exitinction. Interesting how many of these nations where species are going to be permanently extinct don’t allow abortions and getting birth control can be difficult. So I’ve added whether a nation allows abortion and has birth control to the statistics.

One of the first acts of the Trump administration in January 2017 was to cut the funding for abortions and contraception, which has made it hard for hundreds of thousands of women to get birth control

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity, XX2 report

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Madden, D. 2019. Ranked: the ten countries with the most endangered species in the world. Forbes.

Industry, pollution, agriculture, deforestation, air travel and decreasing habitats are conspiring to make it very hard for thousands of species to survive, let alone flourish. And that truth stretches to every corner of the world, be it forest, mountain, reef, ocean, city or savannah.

The International Union for Conservation of Nature (IUCN) Red List has been the world’s foremost information source on the global conservation status of animal, fungi and plant species since 1964. It currently lists an astounding 27,000 species as at risk of extinction, which is an even more astounding 27% of all species we currently know about. 

  • 40% of all amphibians
  • 34% of conifers
  • 33% of reef corals
  • 31% of sharks and rays
  • 27% of crustaceans
  • 25% of mammals
  • 14% of birds

#1 Mexico: 665 endangered species

71 birds, 96 mammals, 98 reptiles, 181 fish, 219 amphibians

Why? Mexico has one of the highest deforestation rates in the world to make more farmland available to feed an ever growing population, which may double by 2050.  This is because of restrictions on abortions in most states, and abortion not being decriminalized until 2007 and contraceptives prohibited until the late 1960s (Wiki 2019)

#2 Indonesia: 583   191 mammals, 160 birds

Contraception is only available on the black market and abortion in back alley clinics for many women. A legal abortion is hard to obtain (GI 2008)

#3 Madagascar: 553  

Abortion is illegal.

#4 India: 542  

Despite six decades of family planning promotion, contraceptive prevalence rate in India remains poor, particularly in the three North Indian states where 18 percent of the population lives

#5 Columbia: 540  

Only allows abortion for rape, incest, or the mother is at risk, and hard to get. But birth control is available.

#6 USA 475  

#7 Ecuador: 436  

Only allows abortion if the mother is at risk, illegal even in cases of rape, incest, and severe fetal impairment. But birth control is available.

#8 China: 435  

#9 Brazil: 414

Abortion is prohibited in all circumstances, though a woman who was raped or whose life is in danger won’t go to jail.  Birth control is legal.

#10 Peru: 385

Only allows abortion if the mother is at risk. If a woman has an illegal abortion she may spend up to 2 years in prison, and the person who performed the abortion from 1 to 6 years.  Birth control is available. It’s hard to get the morning after pill, and it was discovered that 25% of them are fake.

References

GI. 2008. Abortion in Indonesia. Guttmacher Institute.

Wiki. 2019. Abortion in Mexico and Women in Mexico.

Posted in Biodiversity Loss, Deforestation | Tagged , , , | 1 Comment

Peak Helium

Preface. Turns out helium is needed for a lot more than party balloons, and like all resources, it is in decline. I learned that Stuff Runs Out early in life when we visited dozens of abandoned gold and silver mining towns on family vacations to the Southwest.

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity, XX2 report

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Scientists are worried. Helium is the workhorse of chemistry, and shortages are forcing some experiments to shut down.  There is no substitute, or way to synthesize it, though some can be extracted as a byproduct of natural gas.

At the rate we’re consuming helium, it will be gone in less than 200 years, or even sooner since the current administration plans to privatize the federal helium supply, hastening its depletion. We’re undoing the planets billions of years of helium production in just a few decades.

How the universes second most common element could have a shortage is bewildering, but that’s because when an underground field is discovered, it’s hard to trap and store, usually escaping.  It’s hard to stockpile helium because of its inevitable escape from most containers.  The best way to keep that from happening is to store it in a layer of dolomite over 3,000 feet below ground, where there’s a thick layer of salt keeping it in place.

There are very few locations it’s likely to be found, mainly the U.S. Qatar, and Algeria. 

It takes hundreds of millions of years to produce any substantial quantities of helium underground. They build up where veins of these elements have been deposited, and lead to enormous underground reservoirs of helium. Once it’s extracted, we’d have to wait hundreds of millions of years again for these stores to replenish themselves.

Helium uses:

  • MRIs
  • Nuclear magnetic resonance
  • Deep sea diving
  • Airbags
  • cryogenics
  • Semiconductor industry
  • Fiber optics
  • Super-conducting magnets
  • Development of pharmaceutical drugs
  • NASA to separate fuels in rockets
  • Radiation-detecting sensors
  • Particle accelerators
  • Coldest substance in the world: minus 450 F, useful for cooling applications

References

Baig, E., et al. 2019. Not just balloons: helium shortage may deflat MRIs, airbags, and research

Murphy, H. 2019. The global helium shortage is real, but don’t blame party balloons. New York Times

Pflum, M. 2019. Not just party city: why helium shortages worry scientists and researchers. CBS News.

Siegel, E., et al. 2019. Humanity is thoughtlessly wasting an essential, non-renewable resource: Helium. Forbes.

Posted in Important Minerals | Tagged , | 4 Comments

How much oil left in America? Not much

If you think no worries because we can get arctic oil, think again. We can’t because icebergs knock the drilling platforms down, and massive amounts of new infrastructure — roads, rail lines, platforms, buildings — are needed to set up drilling in Alaska, since the permafrost soil heaves and sinks like a bucking bronco trying to shake them off.

It’s kind of dumb to be in this situation. In the first two oil shocks in the 1970s, many intelligent people proposed we should buy oil from other nations to keep ours in the ground when foreign oil declined. But hell no, Texas, Oklahoma, and other oil states said we need jobs and huge fat profits for shareholders more than national security as long as possible. I would guess this makes war a likely outcome in the future, which wouldn’t have occurred if we’d kept our oil in the ground.

The source material for this post is: Jean Laherrère, Updated US primary energy in quad (April 30, 2019) https://aspofrance.files.wordpress.com/2019/04/updateduspe2019-3.pdf

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report

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Philippe Gauthier. May 3, 2019. US Oil Exploration Drops by 95 Percent. Resilience.org

It is well known that oil discoveries are in continuous decline worldwide in spite of ever-increasing investments. What is less known, however, is that spending on oil exploration is fast dropping in the United States. Exploratory drilling has been decreasing year after year and now stands at only five percent of its 1981 peak. In other words, once the currently producing shale oil wells are gone, there won’t be much to take their place.

According to figures derived from US Energy Information Agency (EIA) data by French oil geologist Jean Laherrère, oil exploration has already peaked twice in the United States. The first time was in the mid-1950s, with just over 16,000 wells drilled in a single year. The second major peak dates back to 1981, with 17,573 exploration wells. This number fell to only 847 in 2017.

Another even more revealing phenomenon is the decrease in NFWs. New field wildcats are exploration wells drilled in areas that have never produced oil, as opposed to wells drilled simply to help better delineate already known oil sectors (shown as red and greenlines in the graph). NFWs also declined by 95%, from 9,151 in 1981 to just 450 in 2017. According to Laherrère, this means that the United States have been almost entirely explored for oil and gas since 1859 and that few sites are worth drilling anymore. “There are only a few unexplored areas left offshore”, he notes.

In comparison, the number of operating wells (used to pump oil from previously known fields) was 646,626 in 1985, 597,281 in 2014, and 560,996 in 2017. However, nearly 400,000 of these wells are very old and produce at a marginal rate – fewer than 15 barrels a day and sometimes as little as one. They are described as marginal wells in the graph above.

It should be noted that the number of operating wells – a figure sometimes used to suggest that the oil industry is still running strong – does not account for this sharp decrease in exploration. Once shale oil production starts to decline – and Laherrère expects this to happen within a couple of years – there will remain few reserves to support US production.

Posted in How Much Left, Peak Oil | Tagged , | 1 Comment

The carbon trap by Paul Chefurka

Preface. We are caught in the carbon trap — we utterly depend on fossils that don’t have an electric replacement. Someday people will figure this out the hard way, but Chefurka compassionately points out that there is no one to blame for our situation, and it’s not something we can do anything about.

Here are just a few ways our lives depend on fossils:

Petroleum diesel powers the transportation that matters: heavy-duty trucks, rail, and ships

Manufacturing depends on process heat and steam generated by fossil fuels    

Energy to keep the electric grid up around the clock  

The majority of people alive today should thank natural-gas based fertilizers, and oil-based pesticides, herbicides, and insecticides   

Half a million products are made out of fossil fuels and with energy from fossil fuels

The natural gas that heats homes and businesses.   

  • About 90% of homes and businesses depend on fossil fuels for heat, mainly natural gas  (EIA 2018).
  • Generating heat from electricity today is terrifically wasteful.  Two-thirds of electricity is generated by burning natural gas and coal, and two-thirds of this coal and natural gas energy vanishes as heat, plus another 6-10% is lost on the wires, so only 24 to 28% arrives at homes and businesses.  It’s far better to use fossils onsite to generate heat.

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report

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Whether we realize it or not, everyone living on planet Earth today is caught in what I have come to call the “carbon trap”. The nature of the trap is simple, and can be described in one sentence:

Our continued existence depends on the very thing that is killing us – the combustion of our planet’s ancient stocks of carbon.

This unfortunate situation was not intentional, and is no one’s fault.

The trap was constructed well outside of our conscious view or understanding.

Its design came from our evolved desires for status, material comfort and security.

We recognized its seductive promise long before we knew enough science to discover its hidden hook.

It was built with the best of intentions by well-meaning scientists and engineers, whose knowledge of the consequences was both incomplete and clouded by their own evolved desire for a better life.

Most of us, even those who are aware of our predicament, distract ourselves by creating and admiring elaborate and luxurious appointments for our carbon-clad prison.

Many who can see the bars spend their time dreaming of ways to slip through them into the world outside – a world of natural freedom that they can see but never reach.

Those who are fully aware of the trap also understand that we now need it to survive; that leaving it (if that were even possible) would be as fatal as staying inside. We are victims of what complex systems scientists call “path dependence” – where we came from and how we got here puts strict limits on what is now possible for us to do.

One of the things we can’t do is simply open the door and leave. Even the fact that our carbon-barred prison is now on fire can’t change the cold equations. We are condemned to wait here until the walls burn down, when a few soot-blackened survivors may stumble out into the blasted and barren landscape left behind by our self-absorbed construction project.

This is why I believe that the one quality most needed in the world today is compassion.

Posted in Consumption, Human Nature, Interdependencies, Other Experts | Tagged , , | 14 Comments

How Much Oil is in an Electric Vehicle? by Nicholas LePan

LePan shows how plastics, made from fossil fuels, make up so much of a car, plus lighten the weight so the car can go further on gasoline.

Since fossil fuels are finite, many assume we’ll just make them out of plants in the future. But that’s really hard, biomass has too much other junk that needs to be removed, oxygen, phosphorous, and another 20 or so elements. These need to be removed or the many of the process steps will not work and a low quality plastic produced.

To illustrate the problem, consider that the chemical composition of plants is one reason cellulosic ethanol is not yet commercial. It’s just too difficult to break lignocellulose down into fermentable sugars. Even if you came up with the perfect enzyme for corn stover to break it down, a different hybrid and very likely some other kind of planet entirely might have a dissimilar enough chemistry to keep the enzyme from being effective.

Creating plastics from biomass also has a negative energy return: you’ve got to plant, harvest, deliver biomass to the plastics plant and use it before it composts. Then you’ll need even more biomass to power the dozens of steps (since fossil fuels are finite), fabricate the plastic to the desired shape, deliver it, and install it in an auto.

Plastics are by far the hardest to make, harder than all the other components of a toaster as you can see in this post “Toasters are toast

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report

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LePan, N. May 20, 2019. How Much Oil is in an Electric Vehicle? visualcapitalist.com

How Much Oil is in an Electric Vehicle?

How Much Oil is in an Electric Vehicle?

When most people think about oil and natural gas, the first thing that comes to mind is the gas in the tank of their car. But there is actually much more to oil’s role, than meets the eye…

Oil, along with natural gas, has hundreds of different uses in a modern vehicle through petrochemicals.

Today’s infographic comes to us from American Fuel & Petrochemicals Manufacturers, and covers why oil is a critical material in making the EV revolution possible.

Pliable Properties

It turns out the many everyday materials we rely on from synthetic rubber to plastics to lubricants all come from petrochemicals.

The use of various polymers and plastics has several advantages for manufacturers and consumers:

  1. Lightweight
  2. Inexpensive
  3. Plentiful
  4. Easy to Shape
  5. Durable
  6. Flame Retardant

Today, plastics can make up to 50% of a vehicle’s volume but only 10% of its weight. These plastics can be as strong as steel, but light enough to save on fuel and still maintain structural integrity.

This was not always the case, as oil’s use has evolved and grown over time.

Not Your Granddaddy’s Caddy

Plastics were not always a critical material in auto manufacturing industry, but over time plastics such as polypropylene and polyurethane became indispensable in the production of cars.

Rolls Royce was one of the first car manufacturers to boast about the use of plastics in its car interior. Over time, plastics have evolved into a critical material for reducing the overall weight of vehicles, allowing for more power and conveniences.

Timeline:

  • 1916
    Rolls Royce uses phenol formaldehyde resin in its car interiors
  • 1941
    Henry Ford experiments with an “all-plastic” car
  • 1960
    About 20 lbs. of plastics is used in the average car
  • 1970
    Manufacturers begin using plastic for interior decorations
  • 1980
    Headlights, bumpers, fenders and tailgates become plastic
  • 2000
    Engineered polymers first appear in semi-structural parts of the vehicle
  • Present
    The average car uses over 1000 plastic parts

Electric Dreams: Petrochemicals for EV Innovation

Plastics and other materials made using petrochemicals make vehicles more efficient by reducing a vehicle’s weight, and this comes at a very reasonable cost.

For every 10% in weight reduction, the fuel economy of a car improves roughly 5% to 7%. EV’s need to achieve weight reductions because the battery packs that power them can weigh over 1000 lbs, requiring more power.

Today, plastics and polymers are used for hundreds of individual parts in an electric vehicle.

Oil and the EV Future

Oil is most known as a source of fuel, but petrochemicals also have many other useful physical properties.

In fact, petrochemicals will play a critical role in the mass adoption of electric vehicles by reducing their weight and improving their ranges and efficiency. In According to IHS Chemical, the average car will use 775 lbs of plastic by 2020.

Although it seems counterintuitive, petrochemicals derived from oil and natural gas make the major advancements by today’s EVs possible – and the continued use of petrochemicals will mean that both EVS and traditional vehicles will become even lighter, faster, and more efficient.

Posted in Automobiles | Tagged , , , , | 6 Comments

Can concentrated solar power be used to generate industrial process heat?

Preface. In the comments section, Ray Universe pointed out an excellent article, The bright future of solar thermal powered factories, about solar collectors and what they can do. Some important points:

A large share of energy consumed worldwide is by heat. Cooking, space heating and water heating dominate domestic energy consumption. In the UK, these activities account for 85% of domestic energy use, in Europe for 89% and in the USA for 61%. Heat also dominates industrial energy consumption. In the UK, 76% of industrial energy consumption is heat. In Europe, this is 67%. Few things can be manufactured without heat.

Although it is perfectly possible to convert electricity into heat, as in electric heaters or electric cookers, it is very inefficient to do so. It is often assumed that our energy problems are solved when renewables reach ‘grid parity’ – the point at which they can generate electricity for the same price as fossil fuels. But to truly compete with fossil fuels, renewables must also reach ‘thermal parity‘.

It still remains significantly cheaper to produce heat with oil, gas or coal than with a wind turbine or a solar panel.

In today’s solar thermal plants, solar energy is converted into steam (via a steam boiler), which is then converted into electricity (via a steam turbine that drives an electric generator). This process is just as inefficient as converting electricity into heat: two-thirds of energy gets lost when converted from steam to electricity. If we were to use solar thermal plants to generate heat instead of converting this heat into electricity, the technology could deliver energy 3 times cheaper than it does today.

43% of industrial heat demand in Europe is above 400 °C (752 °F). These include many of the industrial processes that we need to manufacture renewable energy sources (wind turbines, solar panels, flat plate collectors and solar concentrators) as well as other green technologies (like LEDs, batteries and bicycles). Examples include the production of glass (requiring temperatures up to 1,575 °C/2870 F) and cement (1,450 °C / 2640 F), the recycling of aluminum (660 °C / 1220 F) and steel (1,520 °C / 2770 F), the production of steel (1,800 °C / 3275 F) and aluminum (2,000 °C / 3600 F) from mined ores, the firing of ceramics (1,000 to 1,400 °C / 1830 to 2550 F) and the manufacturing of silicon microchips and solar cells (1,900°C / 3450 F ).

The author points out that solar furnaces can produce temperatures up to 3,500 °C (6,332 °F), enough to manufacture microchips, solar cells, carbon nanotubes, hydrogen and all metals (including tungsten which has a melting point of 3,400 °C). These temperatures can be achieved in just a few seconds, but then uses as an example a Odeillo in France, built in 1970, that can only generate 1 MW. If this is such a good idea, why aren’t there more of them? How can civilization be maintained on 1 MW, when the average natural gas power plant generates 500 MW? Smaller furnaces can be built, but they only produce 15 to 60 kW.

Earlier in the article the author points out that solar panels and wind turbines do not need fossil fuels to operate, but they do need fossil fuels for their production. You won’t find any factory manufacturing PV solar panels or wind turbines using energy from their own PV solar panels or wind turbines. Yet he ignores that this is an issue for solar collectors. He also ignores the transportation component of the dependency on fossils and other fossil dependencies, which I describe on my post 46 Reasons why wind power can not replace fossil fuels:

Consider the life cycle of a wind turbine – giant diesel powered mining trucks and machines dig deep into the earth for iron ore, fossil-fueled ships take the ore to a facility that will use fossil fuels to crush it and permeate it with toxic petro-chemicals to extract the metal from the ore. Then the metal will be taken in a diesel truck or locomotive to a smelter which runs exclusively on fossil fuels 24 x 7 x 365 for up to 22 years (any stoppage causes the lining to shatter so intermittent electricity won’t do). There are over 8,000 parts to a wind turbine which are delivered over global supply chains via petroleum-fueled ships, rail, air, and trucks to the assembly factory. Finally diesel cement trucks arrive at the wind turbine site to pour many tons of concrete and other diesel trucks carry segments of the wind turbine to the site and workers who drove gas or diesel vehicles to the site assemble it.

And also, how can factories be relocated to these facilities and scale up? Does all manufacturing need to be moved to within 20 degrees of the equator for maximal sunshine? Even then the peak sunshine is only a few hours a day, and Utility scale energy storage has a long way to go to make renewables possible.

But this article does a good job of explaining why electricity isn’t enough to make an energy transition with.

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Derrick Jensen, Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report

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Kurup, P., et al. 2015. Initial Investigation into the Potential of CSP Industrial Process Heat for the Southwest United States. National Renewable Energy Laboratory.

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report

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Industries use enormous amounts of fossil fuels to generate heat and electricity to make products like steel, cement, chemicals, glass, and refine petroleum, with nearly three-quarters of energy used in the form of heat. Industry uses 30% of all energy, and 83% of that energy is generated by fossil fuels mainly to create process heat directly, indirectly with steam heat, or to generate electricity at the factory for reliability and to operate machine drive equipment (EI 2010).

This image has an empty alt attribute; its file name is CSP-to-generate-high-heat-needed-by-industry.jpg

It is possible for a Parabolic Trough collector (PTC), which looks like a giant upended cattle trough, to make some of this industrial heat and replace some of the fossil fuels used (mainly natural gas).

But the industrial uses this concentrated solar power collection is most useful for are heat applications from 110 to 220 C (230 – 430 F), especially those processes that use pressurized water or steam.

So that leaves quite a few very important industries out, since they use 2000 F heat or more, such as iron, steel, fabricated metals, transportation equipment (cars, trucks), computers, electronics, aluminum, cement, glass, machinery, and foundries.

Industries where solar industrial process heat (SIPH) might be used are paper, dairy, food, beer, chemicals, and washing/cleaning.   No doubt some processes within other industries like plastics and rubber, textiles, and others also have a need for industrial process heat that’s less than 430 F.

NREL isn’t proposing gigantic, billion dollar concentrated solar power collectors like the ones that take up miles of land in the deserts of California, Nevada, and Arizona.

Rather they suggest that much smaller facilities could be built.  Have been built actually, Frito Lay set aside 5 acres to use heat to fry potato chips in Modesto, California.  Prestage Foods in North Carolina also has 7 acres of PTC to heat 100,000 gallons of water a day for their turkey processing operations.  Currently there are 16 other SIPH plants (9 food & dairy, 4 breweries, 2 desalination & water treatment, 1 subway washing).

Another reason these plants need to be small and local is that unlike electricity, it’s too hard to transfer hot fluids like steam more than a few hundred meters, while electricity can be sent for hundreds of miles.  So solar collectors need to be next to the manufacturing plant. 

But SIPH can barely make a dent in the industrial process heat required.  In 2013 a German study found that solar heat generation could only replace 3.4% of overall industrial heat demands.  This 3.4% would require 16 Terawatt hours (TWh) a year, which would require 46 Nevada Solar One plants.  This plant cost $266 million, so that’s $12.2 billion for this small fraction of manufacturing.

Like all electricity generating contraptions, PTC and other concentrated solar power collectors can’t outlast the age of oil, since their life cycle depends on fossil fuels from beginning to end — from mining, ore crushing, metal smelting and fabrication, transportation by diesel trucks, ships, and trains, and finally delivery with een more diesel. If solar collectors were good at generating the 3000 F temperatures needed by iron, steel, and aluminum, or the 2700 F needed by cement these contraptions, then they’d come closer than wind or solar PV towards replacing fossils and being able to make themselves from their own energy, but that simply isn’t the case.

Just look at the materials needed for a 1 Gigawatt Parabolic trough collector:

                                                                High heat

Material               Tons                      > PTC  can generate

Water            12,000,000

Rock                 1,300,000

Iron                        650,000 Yes

NaNO3                 340,000

Cement                                250,000 Yes

Steel                      240,000 Yes

Sodium Nitrate 220,000

Limestone           170,000

Glass                     130,000 Yes        

Silicon sand           92,000

Table 1. Materials needed per GW for a parabolic trough collector (Pihl 2012)

In addition thousands of tons of Copper (3200), Chromium (2200), Foam glass (2500), Magnesium (3000), Manganese (2000), Rock Wool (4700), Soda Ash (18,000), and hundreds of tons of Aluminum (740),  Fibreglass (310), Molybdenum (200), Polypropylene (500), Zinc (650) and many more materials as well.

The years of reserve life for many aren’t far off Iron (33), Copper (39), Manganese (48), Chromium (16), Nickel (49), Molybdenum (43), Niobium (48), and Silver (25), so solar collector contraptions, if not limited by oil, natural gas, and coal for their construction will be limited by their materials.

References

EI. 2010. Manufacturing Energy and Carbon Footprint Sector: All Manufacturing (NAICS 31-33). Energetics Incorporated for the U. S. Department of Energy

Pihl, E., et al. 2012. Material constraings for concentrating solar thermal power.

Related posts:

Posted in Concentrated Solar Power, Energy | Tagged , , , , , | 7 Comments

Concentrated Solar Power can only exist in deserts and use too much water

What follows is my summary of:

Bracken, N., et al. 2015. Concentrating solar power and water issues in the U.S. Southwest. U.S. department of energy, National renewable energy lab.

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Derrick Jensen, Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report

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Concentrated Solar Power plants can only be built in desert regions with huge amounts of direct sunlight.  But these are usually the most water scarce regions in the nation and nearly all of them are in the deserts of Arizona, California, and Nevada. 

CSP requires water in construction, the steam cycle, process cooling, and cleaning of solar collectors or mirrors.

If the grid were ever to become 100% renewable, CSP would play a key role, because it can be built with thermal storage to keep the grid up long after the sun goes down.

However, only one CSP plant of 39 has thermal storage, so this probably won’t happen.  And at a billion dollars per plant not many more are likely to be built either (i.e. the 392 MW Ivanpah cost $2.2 billion on 3,600 acres). At $7,100/kW per CSP plant, it’s much cheaper to build natural gas ($1,100), Solar PV ($2,900), or coal ($3,600) electricity generating facilities.

No wonder only 0.03% of electricity is generated using CSP.

Yet CSP in a fossil-free world will be essential to generate the very high heat needed in manufacturing, much of it steam heat which requires enormous amounts of water.  The only other source of non-fossil, renewable high heat is charcoal from wood. 

The following industries need heat of up to 3275 F: Chemicals, Forest products, Iron and Steel, Plastics & Rubber, Fabricated metals, Transport Equipment, Computers, electronics & equipment, Aluminum, Cement, Glass, Machinery, Foundries. For most of these products, there is no alternative electric process.

The only industries that can get by without high heat are the food, beverage and textile industries. 

Though water alone is a showstopper, it’s also equally unlikely that industries across America would move to the desert Southwest to build factories even if there were plentiful water.

It is also questionable how sustainable this is. How long would these aquifers last? There would be very little recharge at just a few inches of rain a year, limiting how much water can be withdrawn sustainably.

Siting a CSP plant is difficult, because most of the suitable land is federal, and it can take quite a long time to get permission to build on protected federal land. It’s also hard to get permits for water in these dry regions, since cities and agriculture are usually considered to be more important and CSP competes with agriculture for level land with less than a 1% slope.  CSP locations are far from rivers and lakes, making groundwater the only possible source of water.  In Arizona, it is hard to get permission to obtain groundwater without a grandfathered water right on that land or get a special permit in many regions.

Current estimates indicate that operational CSP plants use at least 620 acre-feet per year.   That’s 765,000 cubic meters of water, 202 million gallons in the desert regions of the Southwest (Arizona, California, and Nevada). 

CSP facilities with wet cooling can consume more water per unit of electricity generated than traditional fossil fuel facilities using wet cooling.

If all of the expected CSP projects are completed, most will be wet-cooled and require 221,000 acre feet a year, with dry-cooled using 18,000 acre feet per year.  Because wet-cooled plants use so much more water than dry-cooled, California and Nevada have tried to limit them, and Arizona may well do so as well.  So 9 of the 15 future CSP projects under construction will be dry-cooled, hybrid-cooled, or use reclaimed water.

But wet-cooled plants are more efficient than dry-cooled, and dry-cooled electricity generation drops off at temperatures above 100°F when generation is needed the most to meet summer peak electricity demand.  Dry-cooled plants also need to employ massive cooling fans to remove heat from the pipe array since air has far less ability to lower heat than water does.  These fans consume electricity being generated at the CSP plant, which not only subtracts from the amount of energy generated, it reduces the thermal efficiency of the steam turbines.

If significant amounts CSP power generated were transmitted to other states, the result would be a virtual export of scarce water to other states.   

Related post:

Concentrated Solar Power: Water Constraints

References

CRS. 2009. Water Issues of Concentrating Solar Power (CSP) Electricity in the U.S. Southwest. Congressional Research Service.

USGAO. September 2012. ENERGY-WATER NEXUS. Coordinated Federal Approach Needed to Better Manage Energy and Water Tradeoffs GAO-12-880 U.S. Government Accountability Office.

Posted in Concentrated Solar Power, Electricity | Tagged , , , | 1 Comment

Saudi oil infrastructure at risk from drone attacks

Preface. This NYT article was published 4 months ago, and its warning just came true. Quite prescient!

Drones make it pretty easy to anonymously attack the thousands of miles of pipelines across the Arabian peninsula, oil tankers, pumping stations, and refineries. The Saudis counter that they’ve spent quite a bit to protect their infrastructure, but now that drones can be launched 1,000 miles away to accurately hit targets, whatever protections they have may not be enough, because they can evade the kingdom’s main air defenses, which are intended to repel missiles and aircraft rather than smaller objects.

At least as great a threat is Iran or some other nation using cyber warfare to damage the petroleum infrastructure of Saudi Arabia and its neighbors.

Peak oil production can not only happen for geological reasons. Politics (war) can also bring peak production about, making the collapse of civilization happen that much sooner, and perhaps a lot of oil left in the ground, which climate activists should love.

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report

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Reed, S. May 17, 2019. Saudi Oil Infrastructure at Risk as Small Attacks Raise Potential for Big Disruption. New York Times.

Saudi Arabia spent heavily to protect its oil production lines but rapid changes in technology may mean ports and pipelines are increasingly exposed in the turbulent region.

Across the Arabian peninsula, thousands of miles of pipes run above and below the desert in one of the world’s most sophisticated production lines for pumping oil from the ground and distributing it around the world. This vast system of oil fields, refineries and ports has largely run like clockwork despite political turbulence across the region.

Then a drone strike claimed by Houthi rebels this week forced the Saudis to temporarily halt the flow of a crucial oil artery to the west side of the country. The assault came a day after mysterious incidents damaged two Saudi tankers and two other ships in a key port in the United Arab Emirates.

These were perhaps the most serious attacks on the kingdom’s oil infrastructure since Al Qaeda militants were thwarted trying to blow up a key Saudi facility at Abqaiq in 2006.

While American officials are still trying to determine whether Iran was behind these incidents, the question for the oil market is how well the Saudi and Persian Gulf infrastructure is protected and whether, with tensions building in the region, it could survive a conflict with Iran.

Analysts and executives of Saudi Aramco, the national oil company, say the kingdom has spent heavily to protect the industry that is its lifeblood. Key Saudi installations are tightly guarded and protected by missile batteries and other weaponry. “Security systems were bulked up in the 2000s amid the Al Qaeda threat, including the 2006 attack on the Abqaiq facility,” said Ben Cahill, manager for research & advisory, at Energy Intelligence, a research firm. “The country’s oil fields, refineries and pipelines are blanketed by surveillance and remote sensing.”

In light of that security effort, Mr. Cahill and other analysts concede that it was eye-opening, even shocking, that a drone apparently launched from as far as 500 miles away in Yemen, managed to cross deep into Saudi Arabia and cause damage.

It was also worrisome and even embarrassing that someone managed to damage tankers in waters off Fujairah, a vital port in the United Arab Emirates where ships take on fuel and provisions on their way in and out of the Gulf.

Despite the security spending of the last decade, rapid changes in technology may mean that the Saudi infrastructure is more exposed than previously thought, analysts say. United Nations experts have estimated, for instance, that drones used by the Houthis have a range of nearly 1,000 miles allowing them to reach well into Saudi Arabia. “The simple fact that they managed to reach tankers and a pipeline” is meaningful, said Riccardo Fabiani, a geopolitical analyst at Energy Aspects, a market research firm. “It means they could strike at the heart of Saudi interests if they wanted to.”

Iran is well-placed for inflicting pain in the no-war-no-peace existence in the region. Analysts say it is proficient at using relatively cheap unconventional weapons like drones and speed boats, and at covering its tracks. It can also make use of proxies including the Houthi rebels, who claimed responsibility for the pipeline attack.

Analysts say that drones could prove to be a nuisance for producers like the Saudis. It would be difficult if not impossible to protect an entire pipeline system, and even concentrating air defense units around key points like pumping stations, which were hit this week, would mean taking these defenses from somewhere else.

Drones may also be able to evade the kingdom’s main air defenses, which are intended to repel missiles and aircraft rather than smaller objects. Jeremy Binnie, a Middle East and Africa defense specialist at Jane’s Defense Weekly, said that satellite imagery showed that the key Saudi export terminal at Ras Tanura was guarded by batteries of sophisticated United States-made Hawk surface-to-air missiles. But these weapons “might not be able to engage the UAVs (drones) that Iran has developed with small radar cross sections,” he said.

Another concern is that Iran, which is regarded as skilled in digital hacking, could use cyber warfare to damage the petroleum infrastructure of Saudi Arabia and its neighbors.

At Saudi Aramco, activities like drilling wells, pumping oil to the surface, and loading the fuel on tankers can all be monitored and managed remotely. Such sophistication, though, may also create openings for attack. “A lot of those movements are run out of a central command center at Saudi Aramco headquarters,” said Phillip Cornell, a fellow at the Atlantic Council, a Washington-based research institution, who previously worked at Aramco as a senior corporate planning adviser.

Mr. Cornell said that Aramco officials suspected Iran was responsible for a cyber attack earlier in this decade and that “there has been a lot of investment to reinforce those cyber security defenses.”

However, analysts say the cyber vulnerabilities remain a major worry. “I think cyber is the really underappreciated risk,” said Helima Croft, an oil analyst at RBC Capital markets, an investment bank.


Posted in Middle East, Oil & Gas, Peak Oil | Tagged , , , | Leave a comment

Why “fracked” shale oil and gas will not save us

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Preface. As early as 2011 experts were questioning how large fracked natural gas reserves were.

The latest IEA 2018 report predicts shale oil/gas could start to decline by 2025, and all global oil as soon as 2023. 

Shale oil and gas might not even exist without super low interest rates making it quite easy to borrow money, as Bethany McLean writes in her book “Saudi America”.  And even though these companies are $300 billion in debt, as long as they can get money, they’ll continue to drill.  Some day the dumb middle-class money will be surprised that their 401K and other high interest mutual funds and bonds have crashed after the next economic crash.

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report

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Cunningham, N. 2019. The Shale Boom Is About To Go Bust. oilprice.com

The shale industry faces an uncertain future as drillers try to outrun the treadmill of precipitous well declines.

For years, companies have deployed an array of drilling techniques to extract more oil and gas out of their wells, steadily intensifying each stage of the operation. Longer laterals, more water, more frac sand, closer spacing of wells – pushing each of these to their limits, for the most part, led to more production. Higher output allowed the industry to outpace the infamous decline rates from shale wells.

In fact, since 2012, average lateral lengths have increased 44 percent to over 7,000 feet and the volume of water used in drilling has surged more than 250 percent, according to a new report for the Post Carbon Institute. Taken together, longer laterals and more prodigious use of water and sand means that a well drilled in 2018 can reach 2.6 times as much reservoir rock as a well drilled in 2012, the report says.

That sounds impressive, but the industry may simply be frontloading production. The suite of drilling techniques “have lowered costs and allowed the resource to be extracted with fewer wells, but have not significantly increased the ultimate recoverable resource,” J. David Hughes, an earth scientist, and author of the Post Carbon report, warned. Technological improvements “don’t change the fundamental characteristics of shale production, they only speed up the boom-to-bust life cycle,” he said.

For a while, there was enough acreage to allow for a blistering growth rate, but the boom days eventually have to come to an end. There are already some signs of strain in the shale patch, where intensification of drilling techniques has begun to see diminishing returns. Putting wells too close together can lead to less reservoir pressure, reducing overall production. The industry is only now reckoning with this so-called “parent-child” well interference problem.

Also, more water and more sand and longer laterals all have their limits. Last year, major shale gas driller EQT drilled a lateral that exceeded 18,000 feet. The company boasted that it would continue to ratchet up the length to as long as 20,000 feet. But EQT quickly found out that it had problems when it exceeded 15,000 feet. “The decision to drill some of the longest horizontal wells ever in shale rocks turned into a costly misstep costing hundreds of millions of dollars,” the Wall Street Journal reported earlier this year.

Ultimately, precipitous decline rates mean that huge volumes of capital are needed just to keep output from declining. In 2018, the industry spent $70 billion on drilling 9,975 wells, according to Hughes, with $54 billion going specifically to oil. “Of the $54 billion spent on tight oil plays in 2018, 70% served to offset field declines and 30% to increase production,” Hughes wrote.

As the shale play matures, the field gets crowded, the sweet spots are all drilled, and some of these operational problems begin to mushroom. “Declining well productivity in some plays, despite application of better technology, are a prelude to what will eventually happen in all plays: production will fall as costs rise,” Hughes said. “Assuming shale production can grow forever based on ever-improving technology is a mistake—geology will ultimately dictate the costs and quantity of resources that can be recovered.”

There are already examples of this scenario unfolding. The Eagle Ford and Bakken, for instance, are both “mature plays,” Hughes argues, in which the best acreage has been picked over. Better technology and an intensification of drilling techniques have arrested decline, and even led to a renewed increase in production. But ultimate recovery won’t be any higher; drilling techniques merely allow “the play to be drained with fewer wells,” Hughes said. And in the case of the Eagle Ford, “there appears to be significant deterioration in longer-term well productivity through overcrowding of wells in sweet spots, resulting in well interference and/or drilling in more marginal areas that are outside of sweet-spots within counties.”

In other words, a more aggressive drilling approach just frontloads production, and leads to exhaustion sooner. “Technology improvements appear to have hit the law of diminishing returns in terms of increasing production—they cannot reverse the realities of over-crowded wells and geology,” Hughes said.

The story is not all that different in the Permian, save for the much higher levels of spending and drilling. Post Carbon estimates that it the Permian requires 2,121 new wells each year just to keep production flat, and in 2018 the industry drilled 4,133 wells, leading to a big jump in output. At such frenzied levels of drilling, the Permian could continue to see production growth in the years ahead, but the steady increase in water and frac sand “have reached their limits.” As a result, “declining well productivity as sweet-spots are exhausted will require higher drilling rates and expenditures in the future to maintain growth and offset field decline,” Hughes warned.

7/29/2017 ASPO newsletter: Last week a $2 billion private-equity fund heavily invested in oil and gas wells went bust, raising the question of whether this is about to happen to other investors. With oil prices in the $40s, many drilling operators are losing money with every barrel of oil they produce. These losses ultimately flow back to the investors that acquired their oilfield assets back when oil was selling for over $100 a barrel.

If spectacular increases in US oil production are to come in the five to eight years, most analysts say it must come from the Permian Basin which is the only shale oil play currently experiencing rapid growth. The Eagle Ford and Bakken shale oil deposits peaked four years ago and have not enjoyed much growth recently and without a substantial increase in investment, there is little hope that there will be substantial growth in the Gulf of Mexico oil fields.

This leaves the Permian Basin as the one oil play that could give America “energy dominance” by pushing up US shale oil production from 5.5 million b/d to 12 million. For this to happen, there must be enough oil in the Permian oil play that can be exploited at prevailing prices. A recent analysis of likely Permian reserves by Arthur Berman concludes that the total recoverable oil in the Permian Basin is likely to be on the order of 3.7 billion barrels and not the 160 billion barrels that the CEO of Pioneer Natural Resources recently was claiming could be recovered from the Permian. The two leading producers of Permian shale oil are anticipating peak production in 2019, which is not that far away.

3/19/2015 ASPO newsletter: Reining in overseas drilling for shale oil: After spending more than five years and billions of dollars trying to re-create the US shale boom overseas, some of the world’s biggest oil companies are starting to give up amid a world-wide collapse in crude prices. Chevron Corp., Exxon Mobil Corp. and Royal Dutch Shell PLC have packed up nearly all of their hydraulic fracturing wildcatting in Europe, Russia, and China. The reasons vary from sanctions in Russia, a ban in France, a moratorium in Germany and poor results in Poland to crude prices below what it can cost to produce a barrel of shale oil.

Here are just a few of many articles on this topic:

  1. 2016-4-30 Australian Public Broadcaster ABC unable to look at oil statistics
  2. May 10, 2015. Einhorn’s Fracking Concerns Are Nothing New, But They Matter For Investors (Part 1). SeekingAlpha.com
  3. R. Heinberg. Chapter 5 of How Fracking’s False Promise of Plenty Imperils Our Future: The Economics of Fracking: Who Benefits? October 2013.
  4. Hall, C. Are we Entering the Second Half of the Age of Oil? Some epirical constraints on optimists’ predictions of an oil-rich future. 2013 Geological Society of America.
  5. Richard Heinberg. 12 Nov 2012. Museletter #246: Gas Bubble Leaking, About to Burst.
  6. Gail Tverberg. 17 Oct 2012. Why Natural Gas isn’t Likely to be the World’s Energy Savior.
  7. Jeff Goodell. 1 Mar 2012. Politics: The Big Fracking Bubble: The Scam Behind the Gas Boom. Rolling Stone.
  8. James Howard Kunstler. 19 Nov 2012. Epic Disappointment.
  9. David Hughes. 29 May 2011. Will Natural Gas Fuel America in the 21st Century?
  10. James Stafford. 12 Nov 2012. Shale Gas Will be the Next Bubble to Pop – An Interview with Arthur Berman.
  11. Peter Coy. 12 Nov 2012. U.S. the New Saudi Arabia? Peak Oilers Scoff.  Bloomberg.
  12. Kelly, S. 29 Apr 2013. Faster Drilling, Diminishing Returns in Shale Plays Nationwide?

October 29, 2013 Tom Whipple. The Peak Oil Crisis: The Shale Oil Bubble.  Falls Church News-Press.

“fracked oil is very expensive, requiring circa $80 a barrel to cover the costs of extraction. Production from fracked oil wells drops off quickly, so new wells have to be drilled constantly to maintain production. Until recently information about just how fast our fracked oil wells were depleting was hard to come by, so the hype about the US becoming energy independent and a major oil exporter became conventional wisdom for most.

Nearly all of the growth in U.S. onshore crude production these days is coming from North Dakota’s Bakken field and Texas’s Eagle Ford. They account for nearly 2 million of the 2.4 million b/d increase in oil production that the US has seen in recent years. It sure looks as if the increase in production in these fields will keep up with the rate of decline within the next 12 to 18 months and that US shale oil production will no longer be growing. While it is possible that a surge of investment will increase the drilling to keep up with declines in production from the older wells, this is expensive, and for now it looks as if oil prices are heading for a level where fracked oil production is not profitable. Outside geologists with access to proprietary data on decline rates have been forecasting for some time now that as the number of wells increases and their quality declines, the shale boom will be coming to an end in the next two years. The release of EIA data seems to confirm these predictions.”

David Hughes at the 2013 Geological Society of America: These are heady times for U.S. oil bulls, with projections of production from tight oil rising to five million barrels per day, or more, by 2019, from essentially nothing just a few years ago. This compares to total U.S. oil production of less than seven million barrels per day as recently as 2008. Declarations of near term “energy independence” are commonplace in the main stream media.

Notwithstanding the substantial contribution of this new supply made possible by the combination of multi-stage hydraulic fracturing and horizontal drilling, the U.S. burns more than 18 million barrels per day. Even five million barrels per day of tight oil production is highly unlikely to free the U.S. from the need for imported oil. Furthermore, tight oil fields are characterized by high decline rates and the need for continual high rates of drilling to maintain production levels. The long term sustainability of tight oil production is thus of paramount concern.

An analysis of the Bakken Field, of North Dakota and Montana, and the Eagle Ford Field, of Texas, which together comprise more than half of projected tight oil production, reveals static field production declines of about 40 percent annually. Moreover, these fields are far from homogenous in terms of well productivity, with “sweet spots” of high productivity comprising a small proportion of the touted productive area. These sweet spots are targeted first resulting in the spectacular ramp up in production observed in these plays, but the steep decline rates inevitably take their toll. Production in the Bakken Field, which is the poster child for tight oil, has plateaued in the past few months, and requires 120 new wells each month to maintain production. The Eagle Ford is still growing rapidly, with 3000 new wells added each year, but it is only a question of time before the sweet spots are exhausted.

Tight oil is an important contributor to U.S. energy supply, but its long term sustainability is questionable. It should be not be viewed as a panacea for business-as-usual in future U.S. energy security planning.

December 11, 2013   California shale.  Tom Whipple.

[Note: the US EIA states that this California shale has 65% of the total recoverable shale oil resource base in the country, with 400 billion barrels of oil and 15 billion barrels using today’s technology.  But it doesn’t look like that will work out].

We now have a second look at the Monterey shale and things don’t look so rosy. First, the geology of California is similar to a bowl of spaghetti with the earth squeezed into folds and steep inclines, not the 20,000 sq. miles of flat-laying shale deposits found in North Dakota. The Monterey shales are thick and complex, and do not lend themselves to drilling the long horizontal wells that can be fracked so productively in other places. Much of the shale oil in California appears to have drained over the years into conventional oil reservoirs and has already been extracted by many of the 238,000 oil wells that have been drilled in the state during the last century.

Our new study by an experienced Canadian geologist, who has already examined the productivity of other shale oil formations in the US, concludes that the government and its contractor’s study is absurdly optimistic about the prospects for shale oil production in California. Despite the use of all the latest drilling and production techniques, oil production in California has fallen from 1.1 million b/d 30 years ago to 500,000 b/d today. It is highly unlikely that this will be turned around given the geology of the region.

The Department of Energy’s report starts with the assumption that California’s shale is much like that in Texas and North Dakota. It posits that the oil industry will only have to drill 28,000 new wells, each yielding ridiculously large 550,000 barrels of oil, to extract California’s shale oil. This is simply not supported by the recent history of drilling in the state and is unlikely to happen. We will be lucky if California’s oil production does not continue to decline, for its geology is simply not the same.

D. Rogers. Feb 2013. Shale & Wall Street: Was the Decline in Natural Gas Prices Orchestrated?

Excerpts from a 32-page report:

Leases were bundled and flipped on unproved shale fields in much the same way as mortgage-backed securities had been bundled and sold on questionable underlying mortgage assets prior to the economic downturn of 2007.

In 2011, shale mergers and acquisitions (M&A) accounted for $46.5 B in deals and became one of the largest profit centers for some Wall Street investment banks. This anomaly bears scrutiny since shale wells were considerably underperforming in dollar terms during this time. Analysts and investment bankers, nevertheless, emerged as some of the most vocal proponents of shale exploitation. By ensuring that production continued at a frenzied pace, in spite of poor well performance (in dollar terms), a glut in the market for natural gas resulted and prices were driven to new lows. In 2011, U.S. demand for natural gas was exceeded by supply by a factor of four. It is highly unlikely that market-savvy bankers did not recognize that by overproducing natural gas a glut would occur with a concomitant severe price decline. This price decline, however, opened the door for significant transactional deals worth billions of dollars and thereby secured further large fees for the investment banks involved. In fact, shales became one of the largest profit centers within these banks in their energy M&A portfolios since 2010. The recent natural gas market glut was largely effected through overproduction of natural gas in order to meet financial analyst’s production targets and to provide cash flow to support operators’ imprudent leverage positions.

Wall Street promoted the shale gas drilling frenzy, which resulted in prices lower than the cost of production and thereby profited [enormously] from mergers & acquisitions and other transactional fees.

U.S. shale gas and shale oil reserves have been overestimated by a minimum of 100% and by as much as 400-500% by operators according to actual well production data filed in various states.

Shale oil wells are following the same steep decline rates and poor recovery efficiency observed in shale gas wells.

The price of natural gas has been driven down largely due to severe overproduction in meeting financial analysts’ targets of production growth for share appreciation coupled and exacerbated by imprudent leverage and thus a concomitant need to produce to meet debt service.

Due to extreme levels of debt, stated proved undeveloped reserves (PUDs) may not have been in compliance with SEC rules at some shale companies because of the threat of collateral default for those operators.

Industry is demonstrating reticence to engage in further shale investment, abandoning pipeline projects, IPOs and joint venture projects in spite of public rhetoric proclaiming shales to be a panacea for U.S. energy policy.

Exportation is being pursued for the differential between the domestic and international prices in an effort to shore up ailing balance sheets invested in shale assets

It is imperative that shale be examined thoroughly and independently to assess the true value of shale assets, particularly since policy on both the state and national level is being implemented based on production projections that are overtly optimistic (and thereby unrealistic) and wells that are significantly underperforming original projections.

for more than a decade the largest oil and gas producers (the “Majors” as they are collectively called) have not been able to materially expand their reserve replacement ratios.14 In fact, approximately one quarter of their reserve growth has come from acquisitions rather than the drill bit, such as ExxonMobil’s acquisition of XTO Energy. This constitutes consolidation rather than organic growth.

To give another example, in 2010 Chevron replaced less than one fourth of the oil and gas it had sold the prior year.  This is highly problematic for the future share price of these companies and explains the exuberant share repurchase programs which they have engaged in recently, buying back shares in excess of as much $5 billion a quarter in the case of ExxonMobil. This is, of course, highly problematic for the future health of global economies. It is also problematic for the share prices of the individual fossil fuel companies.

Further, there are various grades and types of hydrocarbons, some much more efficient as fuels than others. Additionally, some hydrocarbons simply require such an expenditure of energy to extract and produce that their use becomes questionable.

In order for a publicly traded oil and gas company to grow extensively, it must manage not only its core business but also the relationship it enjoys with its investment bankers. Thus, publicly traded oil and gas companies have essentially two sets of economics. There is what may be called field economics, which addresses the basic day to day operations of the company and what is actually occurring out in the field with regard to well costs, production history, etc.; the other set is Wall Street or “Street” economics. This entails keeping a company attractive to financial analysts and investors so that the share price moves up and access to the capital markets is assured. “Street” economics has more to do with the frenzy we have seen in shales than does actual well performance in the field.

Before the mortgage crisis, once the extent of the appetite was realized for credit default swaps, representatives of the capital markets worldwide embraced the new products. The fees generated were immense. It was similar with shale. Land was bid up to ridiculous prices with signing bonuses reaching nearly $30,000/acre and leases on unproven fields being flipped for as much as $25,000/acre, multiples of original investment.  There seemed an unending appetite.

In another example of parallels: credit default swaps were not traded on any exchange, so transparency became a paramount issue. It proved very difficult to accurately measure the underlying fundamentals with such a lack of transparency. It was the same with shales. Due to the new technology of hydrofracture stimulation, shale results could not be verified for a number of years. There simply was not enough historical production data available to make a reasonable assessment. It wasn’t until Q3 of 2009 that enough production history on shale wells in the Barnett had been filed with the Texas Railroad Commission that well performance could be checked.24 What emerged was significantly different from the operators’ original rosy projections. Of further interest is the fact that once numbers could begin to be verified in a play, operators sold assets quickly. This has followed in each play in the U.S. as it matured. The dismal performance numbers were recognized as a potential drag on company share prices. A good example would be the operators in the Barnett play in Texas. The primary players were Chesapeake Energy(significant portion of assets sold or jv’ed), Range Resources (all Barnett assets sold), Encana,( all Barnett assets sold) and Quicksilver Resources (company attempting to monetize all Barnett assets via MLP or asset sale since 2011. In that time frame, stock has plunged from about $15/share to $2.50/ share).

The issue of well performance disclosure has continued to mask problems in shale production. States such as Pennsylvania and Ohio do not release well performance data on a timely basis, which makes it very difficult to get a true picture of actual well history.

WRITE-DOWNS

In the lead up to the mortgage crisis, there were hints of things to come in the form of asset write downs.

Similar hints have been emerging with regard to shale (several examples listed)

This is of particular interest. Pipeline projects are expensive and require that a steady and consistent stream of gas or oil can be counted on for a long period of time in order to recoup initial capital outlay. Once initial capital is recouped, however, they tend to be cash cows. Given the steep decline curves for shale oil that are now readily apparent, it appears that operators  recognize that the Bakken will not be a long-term play. As such, they are not prepared to invest the needed capital upfront for a pipeline: again, a distinct lack of confidence in the long term viability of shales.

December 2013. DRILLING CALIFORNIA. A Reality Check on the Monterey Shale By J. David Hughes

it is not clear that hydraulic fracking techniques like those used on the Bakken and Eagle Ford will work on the Monterey shale.

Bakken/Eagle Ford

  • Deposits less than a few hundred feet thick
  • Flat and gently dip
  • Bakken: 20,000 square miles
  • Eagle Ford: 8,000 Square miles

Monterey

  • Complex and unpredictable
  • Much thicker deposits of up to 2,000 feet
  • Much deeper – anywhere from the surface to 18,000 feet down
  • 2,000 square miles
  • 1,363 wells have been drilled in shale reservoirs of the Monterey Formation. Oil production from these wells peaked in 2002, and as of February 2013 only 557 wells were still in production.3 Most of these wells appear to be recovering migrated oil, not “tight oil” from or near source rock as is the case in the Bakken and Eagle Ford plays.

The EIA/INTEK report assumed that 28,032 tight oil wells could be drilled over 1,752 square miles (16 wells per square mile) and that each well would recover 550,000 barrels of oil. The data suggest, however, that these assumptions are extremely optimistic for the following reasons:

  • Initial productivity per well from existing Monterey wells is on average only a half to a quarter of the assumptions in the EIA/INTEK report. Cumulative recovery of oil per well from existing Monterey wells is likely to average a third or less of that assumed by the EIA/INTEK report.
  • Existing Monterey shale fields are restricted to relatively small geographic areas. The widespread regions of mature Monterey shale source rock amenable to high tight oil production from dense drilling assumed by the EIA/INTEK report (16 wells per square mile) likely do not exist.

Thus the EIA/INTEK estimate of 15.4 billion barrels of recoverable oil from the Monterey shale is likely to be highly overstated. Certainly some additional oil will be recovered from the Monterey shale, but this is likely to be only modest incremental production—even using modern production techniques such as high volume hydraulic fracturing and acidization. This may help to temporarily offset California’s longstanding oil production decline, but it is not likely to create a statewide economic boom.

Art Berman: There is about eight years’ worth of shale gas supply available in the United States. The math: If you divide the “technically recoverable resource” of about 1,900 Tcf (trillion cubic feet) of gas, as identified by the Potential Gas Committee’s (PGC’s) report by annual U.S. consumption, you come up with 90 years. However, the PGC’s report says the “probable recoverable resource” is only 550 Tcf— 25% of the “technically recoverable resource. Then, if you divide the 550 Tcf “probable recoverable resource” by 3, which represents the amount of the resource that is actually provided by shale gas, you get about 180 Tcf. (Nov-Dec 2012. A contrarian on Shale Gas. Amerian Public Power Association.)

August 2013. Shale truth interview Arthur Berman Segments 1, 2, 3, 4, 5

Some paraphrased excerpts from these videos:

The high rate of drilling means someone is willing to spend money and there is gas, but not necessarily a lot of profit.  My concern is – what if there’s an economic contraction? They’re spending far more than their earnings, they have to find money to drill more wells. Twice as much as they’re making. A person couldn’t sustain that, and neither can they if capital goes away.  The assumption is they must be making money.  No, other reasons are to keep your leases, maintain production growth so Wall St thinks you’re a good company and stock price doesn’t go down.  If people give E&P money, they’ll spend it.  Lots of wells doesn’t persuade me they’re making money.

Question: if not profitable, then what do you think it will take for politicians and public to understand that?

Art: There’s not big money being made, but being spent.  They think that over time they’ll figure out a way to make money at it, their experts see demand growing and price increasing, especially in north America where we’ve nearly gone through our oil reserves. So our economy will be more and more NG oriented.  There is a lot of gas but most isn’t commercial, but if prices go up, then more will be profitable.  By the end it will be the Exxon, Chevron, Anardako, Apache, Statoil, with the deep pockets, to get through this non-profitable period.  Everyone is losing money right now.  I’ve looked at all their balance sheets, none are making money.  If you’re making money it ought to show up in the SEC filings.  Chesapeake for 2012 is clearly the shale gas leader, they started it, have the most land, the 2nd largest reserves of natural gas after Exxon, but their SEC filing is a train wreck, they lost a Billion last year, had to write down reserves, 3/4 of earnings are from asset sales, not operations.  If CHK is a paragon, then we’re in trouble.   Forget about reserves, resources — clearly no one is making any money.

Q: We hear about a GLUT of shale NG?

No, it’s been flat since Dec 2011, for 15 months flat. do we have an oversupply? Not really, we have an equilibrium that’s keeping prices somewhat low, though they’ve doubled since April.  The question is how long will it take until there’s less NG than we demand, then price will come up.  I think it’ll be sooner than the others are predicting.  over the past 7 decades we’ve had 5 complete fiascos based on predictions everyone agreed on. Now that it’s cheap forever, what about when we were building LNG to import it? Now we think the situation is reversed, no more problems.

Shale is about 35% of our NG supply. Where’s the 65%? Conventional, in terminal decline. No one is drilling those wells. 2/3 of our gas is declining, and shale is not increasing.  Barnett, Haynesville, etc.,  only the Marcellus is continuing to increase.

Q: What should we do?

Change our behavior. No silver bullet suolutions. There are no solutions. The solutions, if they are out there, are very long term. so only 2 things to do: efficiency – use the fuels we have more efficiently. The more important thing is our own behavior – how do we use energy – how many drive alone to work? Leave lights on, not enough insulation — simple things, not solar panels. People don’t feel like they need to conserve when they hear we’re energy independent. Even if we had 100 years of gas, why should we use it up fast?

Several years ago there were the real estate shenanigans, subprime, securitized mortgages, credit default swaps, and so on responsible for economic collapse.  This is similar to some of the shale gas ventures. There are some striking comparisons. We’re told it’ll get better and bigger forever and ever, that S&P/Moody’s mortgages grade A investments but they were wrong, now all the experts say everyone’s making money in shale gas.

But look at the financial position of CHK or Enron, It’s a kind of a train wreck. Many natural gas companies are run well and expect they’ll make money -but whether we believe that – I’m just raising a cautionary note.  I believe the financial collapse had as much to do with energy as real estate. oil got to nearly $150/barrel at same time subprime reached its crescendo, that has an effect — Energy isn’t a sector separate from economics, politics – it’s what ties everything together.

 

Bill Powers: The U.S. has nowhere close to a 100-year supply.

In his new book “Cold, Hungry and in the Dark: Exploding the Natural Gas Supply Myth”, Powers concludes the USA has a 5 to 7 year supply of shale gas.  People and companies who benefit economically are behind the promotion of the shale gas myth. In reality, many corporations are taking write-downs of their reserves. (Peter Byrne. 8 Nov 2012. US Shale Gas Won’t Last Ten Years: Bill Powers. The Energy Report.)

James Howard Kunstler, 24 Sep 2012 “Duty” 

“In all the monumental yammer of the media sages surrounding the candidates they follow, and among the freighted legions of meticulously trained economists who try so hard to fit their equations and models over the spilled chicken guts of daily events, there is no sense of the transience of things. Tom Friedman over at The New York Times still thinks that the petroleum-saturated present he calls “the global economy” is a permanent condition of human life, and so does virtually every elected and appointed official in Washington, not to mention every broadcaster in Manhattan.Someone told all these clowns about 14 months ago that we will be able to keep running WalMart on shale oil and shale gas virtually forever, and they swallowed the story whole, and then force-fed it down the distracted public’s throat. In reality – that alternative universe to flat-screen America – all the mechanisms that allow us to keep running this wondrous show teeter on a razor’s age of extreme fragility.  We’re one bomb-vest or High Frequency Trading keystroke away from a possible dark age…”

Richard Heinberg (excerpt from July 2012 Museletter #242: The End of Growth Update Part 2):

whether the latest financial news is giddy or dismal, whether oil prices are up or down, the game of growing the economy by increasing the production of affordable transport fuel is now officially over. Previously, we enjoyed both a growing economy and low fuel prices, with the latter feeding the former; now we see “cheap” oil only when the economy is in a tailspin of demand destruction.

Yes, “fracking” has given America temporarily inexpensive and abundant natural gas—so why not oil? In the case of natural gas, record-high prices back in 2006-2007 (due to depletion of conventional gas deposits) led to truly heroic rates of drilling and a temporary supply glut. Gas has become so cheap in fact that the shale gas industry is imploding, starting with Chesapeake Energy, the biggest fracker of them all. Producers are losing money on each well, so they’re pulling back on drilling even if that hurts their company’s share value (which it does). Next we’ll see a consolidation of the industry, rising prices, and falling production—against nearly everyone’s recent expectations. This is all clearly and persuasively explained in David Hughes’s recent report for Post Carbon Institute, “Will Natural Gas Fuel America for the 21st Century?
 
The media-storm touting America’s energy resurgence has been truly surreal. During the past 12 months oil prices were at their highest sustained level in history, while the rate of world crude oil production has been flat-lined for seven years. Available oil exports are disappearing from world markets as exporting countries use ever more of their product domestically. The data shout “Peak Oil!” but news markets demand happy talk. And so pundits seize upon a temporary production increase in North Dakota achieved by fracking oil-bearing shale as a “game changer.” Once again we’re told that technology will save us!
 

In reality, virtually all the easy, cheap oil has already been found and put into production; what’s left to find and produce will be hard, nasty, and expensive. Oil-bearing shales have been known to geologists for decades, and fracking has been part of the technical arsenal of the industry since the 1980s, but the cost of development was considered too high. Meanwhile, despite its “miraculous” growth in domestic oil production, the United States saw its trade deficit in oil increase to $327 billion in 2011, accounting for 58 percent of the total trade deficit, the highest-ever annual share.

Not necessarily. As the economy tanks, that will cut demand for oil and the price will fall below the new-supply break-even level; when that happens, companies will cancel or delay new projects (as they did in late 2008 when the per-barrel price fell to $40). But if, for the moment, the economic news looks good, demand will grow and oil prices must inevitably return to levels that justify new supply. And those price levels are just high enough to begin undermining economic growth, as a spate of recent economic research has shown.

Huffington Post, 27 Mar 2013: Deep water and tight oil (like what comes from the Bakken and Eagle Ford) have extremely high depletion rates.

Deep water wells deplete about 10-20 percent a year. Tight oil depletes at about 40 percent annually the first few years. Think about that latter number, where most of our new oil extraction is coming from. What if you had a part-time job but within two years you would only be making about a quarter of your current income. Probably need a new part time job, right? But that one does the same thing. Before you know it, you need 40,000 part time jobs. But even that doesn’t help, because they’re all still depleting at 40 percent. Give a thought to how much you would have to work to maintain your original income after five years, then ten years, then twenty years…  Source: The Reward for Being Right About Peak Oil: Scorn Heaped With Derision

ASPO newsletter 19 Nov 2012:

The International Energy Agency 2012 World Energy Outlook forecast that US shale oil production would continue to grow more rapidly than expected for the rest of the decade, leading to the US becoming the world’s largest oil producer by 2012 and largely energy independent (though not for oil) by 2035.

The world’s press trumpeted the energy crisis was now way in the future and that all would be well for the next 20 years. The few writers that consulted people in the peak oil community buried their skeptical comments at the bottom of their stories.

The issue is how much longer shale oil production can continue to grow at the spectacular rates of the past few years before it too peaks and starts to decline. Oil production from the Bakken Shale in North Dakota is about 660,000 b/d, Eagle Ford in Texas about 600,000 b/d and growing. Some say the 2 fields will produce 2 million b/d in the next year or so. The IEA seems to be saying that tight oil production in the US will peak at about 5 million b/d around 2020.

Most people in the peak oil community who have looked into the issue have major problems with these forecasts, believing that a peak in shale oil production around 3 million b/d is more realistic. Remember, demand is increasing at about 750,000 b/d each year, so 8 years from now an additional 6 million b/d of new production will be required worldwide plus another 3-4 million b/d will be needed to replace the depletion from existing fields every year.

The first problem with the IEA’s estimate is the rapid depletion of fracked oil wells. Despite limited experience with this relatively new technology, some are calculating that production from many of these wells is dropping by over 40% or more a year.

We know the average daily production from North Dakota’s 4,630 producing wells is currently 143 b/d. If we assume that the Bakken oil fields are to produce 2.5 million b/d by the end of the decade then it will need some 18,000 wells, each producing the average of 140 b/d. While this is a not an inconceivable number, when one takes into account that most, if not all of these wells will have be redrilled twice in the next 8 years, the number becomes improbable. We shall have to drill more and more wells just to maintain the same level of production.

The second problem with the optimism over tight oil is the very high cost of the horizontal drilling and fracking of these wells, which may run 3 to 4 times that of a conventional well. Some people put the cost of producing a barrel of oil from the Bakken at $80-90, which is just about where oil is currently selling in the region. Should the global economy continue to contract, the selling price of fracked oil could well fall below the cost of production, bringing a marked slowdown to further drilling.

Roger Blanchard: A Closer Look at Bakken and U.S. Oil Production:

  • Oil production outside of Texas and North Dakota has actually declined in the last few years
  • Bakken extends over a large area of North Dakota, Montana and Saskatchewan, but just 4 counties in North Dakota are 80.8% of all the oil production. Even within that area, some spots are better than others.
  • “Oil wells in the Bakken region decline rapidly. From data I’ve seen, the average decline in the first year is ~60%. The only way to maintain or increase Bakken oil production is to rapidly increase the number of wells. As the industry has to drill in less fruitful areas, being able to maintain production will become an increasing challenge.”
  • “I expect oil production in the Bakken to peak in 2013 to 2015. I expect Texas oil production to have a secondary peak around 2014 (Texas oil production peaked in 1972 at 3.57 mb/d while it’s presently ~1.5 mb/d). If oil production in both Texas and North Dakota begins to decline around 2015, I expect U.S. oil production as a whole to begin to decline in that same time frame.” (my comment: Blanchard also says that oil production is declining now in the Gulf of Mexico!)

ASPO Newsletter Nov 26, 2012   Who do you believe, Likvern or North Dakota official?

Rune Likvern

  • performed an in-depth analysis of data from fracked wells in North Dakota and concluded that the fracked wells are depleting so fast production from the region is unlikely to get much beyond 600,000-700,000 b/d.
  • the average Bakken well produces 85,000 barrels of oil in its first year
  • production steady due to accelerating rate of drilling at about 143 b/d. September to september # of wells: 590 2009-2010  1010 2010-2011  1762 2011-2012
  • Each well costs $10 million – how long can that be sustained?
  • Hess oil costs was $13 million per well drilled/fracked
  • Unless the geology is significantly different, what happens in the Bakken over the next few years will be similar to Texas shales. A recent study of 1000 wells in the Eagle Ford, Texas field shows that each well will produce about 120,000 barrels over its lifetime. This is a long way from the 600,000 barrels North Dakota claims each well will yield.

Director of the North Dakota Oil & Gas Division:

  • production may reach any where from 900,000 to 1.2 million b/d in the next 3 years and sustain this level until 2020 or even 2025 before tapering off to 650-700,000 b/d by 2050.
  • the average Bakken well produces 329,000 barrels of oil in its first year
  • Predicts a revenue 3 times higher over the lifetime of a well than Likvern:Over a 45-year lifetime, each well will produce 615,000 barrels of oil, easily covering the $9 million it costs to drill and frack. if avg prd is 329,000 barrels first year, even spectacular rates of depletion allows a well to produce 600,000 barrels in 5 or 6 years. If Likvern is right and the average well yields 85,000 barrels the first year, then it would only 200,000 barrels.
  • Platts estimates each well generates $20 million in profits

An energy expert (I don’t have permission to give attribution) on oil and gas shales:

  • Barnett (once our great natural gas savior) has peaked (at least for now)
  • Haynesville has peaked
  • Montana Bakken oil has peaked and is half way down
  • North Dakota is increasing rapidly but gets most of its oil out of two sweet spots — Bakken is not nearly as big as it appears on maps… so far all the oil drilling is concentrated in 3 sweet spots: Parshall, Nesson anticline and Elm Coulee Montana. These areas, about 5-10 percent of of the Bakken area on the map, are packed with oil wells and there are essentially none in other areas and according to USGS those other wells produce little oil.
  • The question is: is it all only about sweet spots? How many more sweet spots are there? …early estimate of the EROI of these sites is about same as US oil now (~10:1) FOR THE SWEET SPOTS only.
  • Also from a Texas oil man: “Few are making profits in Eagle Ford. Its a vast Ponzi scheme

Chris Nelder: “… the decline rates of shale gas wells are steep. They vary widely from play to play, but the output of shale gas wells commonly falls by 50% to 60% or more in the first year of production. This is why I have called it a treadmill: you have to keep drilling furiously to maintain flat output.

In the U.S., the aggregate decline of natural gas production from both conventional and unconventional sources is now 32% per year, so 22 bcf/d of new production must be added every year to keep overall production flat, according to Canadian geologist David Hughes. That’s close to the total output of U.S. shale gas, after nearly a decade of its development. It will require thousands more shale gas and tight oil wells to keep domestic gas production flat.”

American Geophysical Union conference 2012: TITLE: The Future of Fossil Fuels: A Century of Abundance or a Century of Decline?

ABSTRACT: Horizontal drilling, hydraulic fracturing, and other advanced technologies have spawned a host of new euphoric forecasts of hydrocarbon abundance. Yet although the world’s remaining oil and gas resources are enormous, most of them are destined to stay in the ground due to real–]world constraints on price, flow rates, investor appetite, supply chain security, resource quality, and global economic conditions. While laboring under the mistaken belief that it sits atop a 100–]year supply of natural gas, the U.S. is contemplating exporting nearly all of its shale gas production even as that production is already flattening due to poor economics. Instead of bringing “energy independence” to the U.S. and making it the top oil exporter, unrestricted drilling for tight oil and in the federal outer continental shelf would cut the lifespan of U.S. oil production in half and make it the world’s most desperate oil importer by mid–]century. And current forecasts for Canadian tar sands production are as unrealistic as their failed predecessors. Over the past century, world energy production has moved progressively from high quality resources with high production rates and low costs to lower quality resources with lower production rates and higher costs, and that progression is accelerating. Soon we will discover the limits of practical extraction, as production costs exceed consumer price tolerance. Oil and gas from tight formations, shale, bitumen, kerogen, coalbeds, deepwater, and the Arctic are not the stuff of new abundance, but the oil junkie’s last dirty fix. This session will highlight the gap between the story the industry tells about our energy future, and the story the data tells about resource size, production rates, costs, and consumer price tolerance. It will show why it’s time to put aside unrealistic visions of continued dependence on fossil fuels, face up to a century of decline, and commit ourselves to energy and transportation transition.

Bill Powers: “There is production decline in the Haynesville and Barnett shales. Output is declining in the Woodford Shale in Oklahoma. Some of the older shale plays, such as the Fayetteville Shale, are starting to roll over. As these shale plays reverse direction and the Marcellus Shale slows down its production growth, overall U.S. production will fall.  At the same time, Canadian production is falling. And Canada has historically been the main natural gas import source for the U.S. In fact, Canada has already experienced a significant decline in gas production — about 25%, since a peak in 2002 — and has dramatically slowed its exports to the United States.”

Art Berman: in 2011 published a report showing industry reserves had been overstated by at least 100% based on detailed review of both individual well and group decline profiles for Barnett, Fayetteville, and Haynesville Shale plays.

 

Ian Urbina. 25 Jun 2011. Insiders Sound an Alarm Amid a Natural Gas Rush. New York Times.

[Natural] gas may not be as easy and cheap to extract from shale formations deep underground as [energy] companies are saying, according to hundreds of industry e-mails and internal documents and an analysis of data from thousands of wells.

In the e-mails, energy executives, industry lawyers, state geologists and market analysts voice skepticism about lofty forecasts and question whether companies are intentionally, and even illegally, overstating the productivity of their wells and the size of their reserves. Many of these e-mails also suggest a view that is in stark contrast to more bullish public comments made by the industry, in much the same way that insiders have raised doubts about previous financial bubbles.

“Money is pouring in” from investors even though shale gas is “inherently unprofitable,” an analyst from PNC Wealth Management, an investment company,  wrote to a contractor in a February e-mail. “Reminds you of dot-coms.

The word in the world of independents is that the shale plays are just giant Ponzi schemes and the economics just do not work,” an analyst from IHS Drilling Data, an energy research company,  wrote in an e-mail on Aug. 28, 2009.

Company data for more than 10,000 wells in three major shale gas formations raise further questions about the industry’s prospects. There is undoubtedly a vast amount of gas in the formations. The question remains how affordably it can be extracted.

The data show that while there are some very active wells, they are often surrounded by vast zones of less-productive wells that in some cases cost more to drill and operate than the gas they produce is worth. Also, the amount of gas produced by many of the successful wells is falling much faster than initially predicted by energy companies, making it more difficult for them to turn a profit over the long run.

If the industry does not live up to expectations, the impact will be felt widely…if natural gas ultimately proves more expensive to extract from the ground than has been predicted, landowners, investors and lenders could see their investments falter, while consumers will pay a price in higher electricity and home heating bills.

There are implications for the environment, too. The technology used to get gas flowing out of the ground — called hydraulic fracturing, or hydrofracking — can require over a million gallons of water per well, and some of that water must be disposed of because it becomes contaminated by the process. If shale gas wells fade faster than expected, energy companies will have to drill more wells or hydrofrack them more often, resulting in more toxic waste.

The e-mails were obtained through open-records requests or provided to The New York Times by industry consultants and analysts who say they believe that the public perception of shale gas does not match reality.

Studying the Data

Ms. Rogers, a former stockbroker with Merrill Lynch, said she started studying well data from shale companies in October 2009 after attending a speech by the chief executive of Chesapeake, Aubrey McClendon. The math was not adding up, her research showed that wells were petering out faster than expected.

In May 2010, the Federal Reserve Bank of Dallas called a meeting to discuss the matter after prodding from Ms. Rogers. One speaker was Kenneth B. Medlock III, an energy expert at Rice University, who described a promising future for the shale gas industry in the United States. When he was done, Ms. Rogers peppered him with questions.

Might growing environmental concerns raise the cost of doing business? If wells were dying off faster than predicted, how many new wells would need to be drilled to meet projections?

Mr. Medlock conceded that production in the Barnett shale formation — or “play,” in industry jargon — was indeed flat and would probably soon decline.

Bubbling Doubts

Some doubts about the industry are being raised by people who work inside energy companies, too.

“In these shale gas plays no well is really economic right now, they are all losing a little money or only making a little bit of money.”  Around the same time the geologist sent this e-mail, Mr. McClendon, Chesapeake’s chief executive, told investors, “It’s time to get bullish on natural gas.

In September 2009, a geologist from ConocoPhillips, one of the largest producers of natural gas in the Barnett shale, warned in  an e-mail to a colleague that shale gas might end up as “the world’s largest uneconomic field.”
Forecasting these reserves is a tricky science. Early predictions are sometimes lowered because of drops in gas prices, as happened in 2008. Intentionally overbooking reserves, however, is illegal because it misleads investors. Industry e-mails, mostly from 2009 and later, include language from oil and gas executives questioning whether other energy companies are doing just that.

The e-mails do not explicitly accuse any companies of breaking the law. But the number of e-mails, the seniority of the people writing them, the variety of positions they hold and the language they use — including comparisons to Ponzi schemes and attempts to “con” Wall Street — suggest that questions about the shale gas industry exist in many corners.

“Do you think that there may be something suspicious going with the public companies in regard to booking shale reserves?” a senior official from Ivy Energy, an investment firm specializing in the energy sector, wrote in  a 2009 e-mail.

A former Enron executive wrote in 2009 while working at an energy company: “I wonder when they will start telling people these wells are just not what they thought they were going to be?” He added that the behavior of shale gas companies reminded him of what he saw when he worked at Enron.

Production data, provided by companies to state regulators and reviewed by The Times, show that many wells are not performing as the industry expected. In three major shale formations — the Barnett in Texas, the Haynesville in East Texas and Louisiana and the Fayetteville, across Arkansas — less than 20 percent of the area heralded by companies as productive is emerging as likely to be profitable under current market conditions, according to the data and industry analysts.

Richard K. Stoneburner, president and chief operating officer of Petrohawk Energy, said that looking at entire shale formations was misleading because some companies drilled only in the best areas or had lower costs. “Outside those areas, you can drill a lot of wells that will never live up to expectations,” he added.

Although energy companies routinely project that shale gas wells will produce gas at a reasonable rate for anywhere from 20 to 65 years, these companies have been making such predictions based on limited data and a certain amount of guesswork, since shale drilling is a relatively new practice.

Most gas companies claim that production will drop sharply after the first few years but then level off, allowing most wells to produce gas for decades.  Gas production data reviewed by The Times suggest that many wells in shale gas fields do not level off the way many companies predict but instead decline steadily.

“This kind of data is making it harder and harder to deny that the shale gas revolution is being oversold,” said Art Berman, a Houston-based geologist who worked for two decades at Amoco and has been one of the most vocal skeptics of shale gas economics.

The Barnett shale, which has the longest production history, provides the most reliable case study for predicting future shale gas potential. The data suggest that if the wells’ production continues to decline in the current manner, many will become financially unviable within 10 to 15 years.

A review of more than 9,000 wells, using data from 2003 to 2009, shows that — based on widely used industry assumptions about the market price of gas and the cost of drilling and operating a well — less than 10% of the wells had recouped their estimated costs by the time they were 7 years old.

In private exchanges, many industry insiders are skeptical, even cynical, about the industry’s pronouncements. “All about making money,” an official from Schlumberger, an oil and gas services company, wrote in  a July 2010 e-mail to a former federal regulator about drilling a well in Europe, where some United States shale companies are hunting for better market opportunities.

“Looks like crap,” the Schlumberger official wrote about the well’s performance, according to the regulator, “but operator will flip it based on ‘potential’ and make some money on it.”

David Hughes at the 2012 American Geophysical Union conference 2012: Shale Gas and Tight Oil: A Panacea for the Energy Woes of America?

ABSTRACT: Shale gas has been heralded as a game changer in the struggle to meet America’s demand for energy. The Pickens Plan of Texas oil and gas pioneer T.Boone Pickens suggests that gas can replace coal for much of U.S. electricity generation, and oil for, at least, truck transportation. Industry lobby groups such as ANGA declare that the dream of clean, abundant, home grown energy is now reality. In Canada, politicians in British Columbia are racing to export the virtual bounty of shale gas via LNG to Asia despite the fact that Canadian gas production is down 16% from its 2001 peak). And the EIA has forecast that the U.S. will become a net exporter of gas by 20213. Similarly, recent reports from Citigroup and Harvard suggest that an oil glut is on the horizon thanks in part to the application of fracking technology to formerly inaccessible low permeability tight oil plays. The fundamentals of well costs and declines belie this optimism. Shale gas is expensive gas. In the early days it was declared that continuous plays like shale gas were manufacturing operations, and that geology didn’t matter. One could drill a well anywhere, it was suggested, and expect consistent production. Unfortunately, Mother Nature always has the last word, and inevitably the vast expanses of purported potential shale gas resources contracted to core areas, where geological conditions were optimal. The cost to produce shale gas ranges from $4.00 per thousand cubic feet (mcf) to $10.00, depending on the play. Natural gas production is a story about declines which now amount to 32% per year in the U.S. So 22 billion cubic feet per day of production now has to be replaced each year to keep overall production flat. At current prices of $2.50/mcf, industry is short about $50 billion per year in cash flow to make this happen. As a result I expect falling production and rising prices in the near to medium term. Similarly,
tight oil plays in North Dakota and Texas have been heralded as a new Saudi Arabiah of oil. Growth in production has been spectacular, but currently amounts to just one million barrels per day which is less than 15% of US oil and other liquids production. Tight oil is offsetting declines in conventional crude oil production as well as contributing to a modest production increase from the 40 year US crude oil production low of 2008. The mantra that natural gas is a transition fuel to a low carbon future is false. The environmental costs of shale gas extraction have been documented in legions of anecdotal and scientific reports. Methane and fracture fluid contamination of groundwater, induced seismicity from fracture water injection, industrialized landscapes and air emissions, and the fact that near term emissions from shale gas generation of electricity are worse than coal. Tight oil also comes with environmental costs but has been a saviour in that it at least temporarily arrested a terminal decline in US oil production. A sane energy security strategy for America must focus on radically reducing energy consumption through investments in infrastructure that provides alternatives to our current high energy throughput. Shale gas and tight oil will be an important contributors to future energy requirements, given that other gas and oil sources are declining, but there is no free lunch.

2012 American Geophysical Union conference 2012: Charles A. Hall. Quantity vs quality of oil: Implications for the future economy

ABSTRACT: There has considerable interest recently in various indications of important changes in the technology of oil production and its impact on US oil production. The data indicate a clear increase in oil production for the US after 40 years of year by year decline. This has led some commentators to predict that the US will become a net oil exporter before long. Maps showing the enormous extent of e.g. the Bakken formation in North Dakota and Montana, and our ability to now exploit this oil using the new techniques of horizontal drilling and fracking, gives the impression that there are enormous new oil reserves that can satisfy our wants indefinitely. Other assessments indicate that the amount of oil still available globally is 3, 4 or more times the usual assessments of about 1 trillion barrels. But “oil” is not a single substance, but rather a suite of materials of widely varying qualities and hence utility. One important index is the energy return on investment (EROI), the ratio of energy returned from energy used to get it. EROI reflects the balance of the countervailing impacts of depletion and technology and ultimately determines the price of a fuel. This ratio is declining all around the world, and gives a practical limit to how much oil we can exploit at an energy and economic profit. Bringing quality of oil into the equation gives a much more restrictive estimate of how much oil we are likely to be able to exploit for fuel.

The “shale revolution” has been often touted as a game changer in energy production (1). Indeed, during the past few years, the increasing production trend of shale (or “tight”) gas in the US has generated a wave of optimism invading the media and the Web. However, not everyone has joined the chorus and several commentators have predicted that the trend would be short lived (see, e.g. Sorrell (2), Laherrere (3), Hughes (4), and Turiel (5)). Some have flatly stated that the effort in gas production in the US is simply a financial bubble, destined to deflate soon (see e.g. Orlov (6) and Berman (7)).  Some, such as R. P. Siegel (8) even argue that the bursting of the gas bubble might bring about a financial collapse not unlike the one of 2008.

While the optimism about the future of natural gas seems to be still prevalent, the data show that the gas bubble may be already bursting. The most recent data from EIA (9) show that that the total US gas production has not been growing for the past 1-2 years and that it shows signs to be declining. Fitted with a Gaussian curve, it shows a peak taking place around the end of 2012.

The declining trend is not yet very pronounced and specific data about shale gas production after 2011 are not available in the EIA site (9). However, since the production of conventional gas has been declining since 2007, the production of shale gas may not be declining yet, but it is surely not growing any more at the rates that were common just a few years ago.

In any case, there are data indicating that the decline of total gas production in the US was expected. Drilling rigs for gas has been plummeting down during the past few years, as shown in the following figure (data from Baker and Hughes (10)

Obviously, one can’t extract anything without having drilled first to find it. Since the lifetime of shale gas wells is of the order of a few years, it was unavoidable that the drop in the number of gas drilling rigs would generate in a production decline; which is what we are seeing today.

Basically, these data seem to confirm the interpretation that we are facing a financial “gas bubble”, rather than a robust trend of development of new resources. The gas glut produced by the rush to gas of the past few years has lowered prices to the point that companies have been extracting gas without making any profit, actually losing money in the process (7). That couldn’t last forever.

In the near future, the decline in gas production in the US may lead to an increase in prices which, in turn, may direct the industry to restart drilling for gas. But it remains to be seen if prices high enough to generate a profit are affordable for consumers. In any case, the idea of a “gas revolution” that will bring for us an age of abundance is rapidly fading.

In the end, what we are doing with gas is simply one more step along a path that we are forced to follow. With the gradual disappearance of high grade mineral resources, we must extract the minerals we need from lower grade resources, and this is more expensive and more polluting. That’s exactly what happening with gas but it is much more general. As described in the most recent report of the Club of Rome (Plundering the Planet (11)), the gradual depletion of high grade mineral resources is leading us to a world where mineral commodities will be rarer and more expensive. We will have to adapt to this empty new world.

1. http://belfercenter.ksg.harvard.edu/files/Oil-%20The%20Next%20Revolution.pdf

2. http://www.theoildrum.com/node/9327

3 http://www.theoildrum.com/node/9495

4. http://shalebubble.org/drill-baby-drill/

5. http://crashoil.blogspot.it/2010/12/un-mar-de-gas-natural.html

6. http://cluborlov.blogspot.com.es/2012/05/shale-gas-view-from-russia.html

7. http://www.youtube.com/watch?v=cDDseuvO2SM&feature=share&list=PL3yVl0q9sFIwgSJfLSBEA3pLrDsxMDMwe

8. http://www.triplepundit.com/2013/02/shale-gas-bubble-threatens-second-economic-collapse/

9. http://www.eia.gov/naturalgas/

10. http://www.bakerhughes.com/rig-count

11. http://www.clubofrome.org/?p=6166

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