Anatomy of Japan’s Nuclear Crisis

The massive 9.0 magnitude earthquake that hit the northeast coast of Japan March 11, 2011 and the awesome tsunami it generated created a nuclear crisis for Japan and nuclear power worldwide. The release of dangerous radioactivity¹ from damaged reactors at Fukushima Dai-ichi (Fukushima-I) nuclear power plant is of particular concern. In the following I try to explain what may have happened to and in the reactors, and examine some potential outcomes.

Figure 1. Fukushima Dai-ichi plant, pre-earthquake. Tokyo Electric Power Co.

 

Fukushima-I, one of the world’s largest nuclear power plants (installed capacity 4,696 megawatts), consists of 6 reactors (Fig. 1) located close to the ocean for convenient access to cooling water. In Fig. 1 the reactor buildings are box-like structures, No. 4 is the closest building in the photograph with Nos. 5-6 in order at the far end. Tokyo Electric Power Company.

As our previous blog explained, the northeastern coast of Japan is a subduction zone, where the Pacific plate is being shoved under the North American plate, occasionally giving rise to major earthquakes.² The earthquake epicenter was about 109 miles off-shore, northeast of Fukushima.³ It caused many minutes of severe earth-shaking⁴ in a coastal belt that extended southward to Tokyo. In the first week alone, the area also experienced three aftershocks of magnitude 7 or greater, and 49 of magnitude 6 or greater, adding to the potential for additional shaking and tsunami damage.⁵

The earthquake automatically shut down three operating Fukushima-I plant reactors (Nos. 1-3) by inserting control rods to stop the nuclear fission chain reaction (http://www.answers.com/topic/chain-reaction). The remaining 3 reactors (Nos. 4-6) had been shut down before the earthquake for maintenance. Whether shut down or not, continuing to cool the reactors is essential because radioactive materials in the fuel rods, produced prior to shut down, will continue to decay and produce heat. The temperature of the fuel will continue to rise unless cooled.⁶ Waste spent-fuel⁷ rods stored in on-site pools also require constant cooling.

But the shock of the earthquake disconnected the plant from the regional electrical grid, preventing it from receiving AC power. Damage from the huge tsunami following the initial shock further disrupted connections to the national power grid, causing “a station blackout”—loss of external power to the entire plant. The tsunami also flooded the plant’s backup power generators, compromising its cooling systems. Backup battery power lasted only about 8 hours, inadequate for a weeks-long loss of principal power sources. When cooling water stopped flowing, fuel rods in the shut-down reactors and in the spent fuel ponds began overheating.

Figure 2. Cut-away view of Fukushima-I reactor type. Blue color represents cooling water. Wikimedia Commons

A diagram of the Fukushima-I type of reactor and its housing in Fig. 2 shows the various components involved in this disaster: the reactor vessel contains the active fuel rods and nuclear reactions; primary containment is a free-standing steel container drywell, orange line; secondary containment is a concrete shield wall surrounding the reactor vessel; and the spent fuel pool holds used-fuel rods. The wetwell or torus, is probably steel-walled and may be part of the primary containment, and the reactor building is what you see from outside. All these components provide the heat that generates electricity in turbines, housed nearby in turbine halls.

The fuel rods consist of ceramic pellets of materials made of easily-split (fissionable) atoms. Fukushima-I reactors 1, 2, and 4-6 fuel rods contained uranium, but rods in reactor 3 contained mixed-oxide (MOX) of uranium plus plutonium. The rods were surrounded by a sheath (or cladding) of a stable zirconium (metal) alloy. So long as cooling water flowed through the reactor, the sheath did not overheat and so contained the fuels and fission products.

When the Fukushima-I reactors lost power, cooling water stopped flowing, so water in the reactor vessels heated to boiling and turned to steam. The water levels fell, exposing at least the upper parts of hot fuel rods. The zirconium alloy sheath then chemically interacted with steam to form zirconium oxide and hydrogen, causing the sheath to break down. This chemical interaction is highly exothermic, releasing large amounts of heat and raising the fuel temperature even more rapidly. In a positive feedback loop, greater heating speeds the deterioration of zirconium alloy sheaths,⁸ releasing hydrogen and radioactive fission products.

Hydrogen and steam were building up in the reactor vessels, threatening to reach pressures that could rupture them, so the plant operators chose to vent some of these gases to the atmosphere. Hydrogen is highly explosive, so the plant was designed to carry hydrogen and steam through pipes and vent some distance from the plant. Instead hydrogen accumulated within the reactor buildings and eventually exploded. Hydrogen explosions caused severe damage to the unit 1 reactor building on March 12, to unit 3 on March 14, and to units 2 and 4 on March 15.⁹

There are two potential sources for the hydrogen:  fuel rods in the reactor vessels and spent fuel rods in cooling pools. Hydrogen coming from reactor vessels would mean either that a breach had opened up in the primary containment releasing hydrogen, steam, and radioactive fission products into the reactor buildings, or disruption to the buildings’ internal venting systems by earthquake shaking. In contrast the spent fuel pools, also dependent on the failed cooling systems, are outside the primary containment (Fig. 2). If their cooling water levels dropped sufficiently to expose the rods, they could emit hydrogen, steam, and radioactive fission products directly into the reactor buildings. A buildup of hydrogen in the buildings needed only a spark to detonate the flammable gas mixture.

Various experts have suggested ways that primary containment might have breached, including potential weaknesses in piping, decay of organic seals, and disturbance of the steel containment vessel’s seal (Fig. 2).¹⁰ Other suggestions include the possibility of fractures in and melting through containment structures. The processes of sheath deterioration, hydrogen production, and releases of radioactive fission products from fuel rods in the reactor vessels can eventually let fuel pellets spill into the bottom of the reactor vessel without melting.¹¹ These sheath reactions are exothermic and may produce sufficient heat to melt the sheath. Whether melted or disaggregated, the radioactive fuel that gets into the bottoms of the reactor vessels is no longer affected by the fission-limiting effects of the control rods and is in danger of restarting heat-producing fission reactions.

Locating spent fuel pools inside the reactor building is a particular weakness of the Fukushima-I reactor design. The internal pools are vulnerable to earthquake disruption, with the potential for spilling cooling water and exposing the stored used-fuel rods. Once exposed, the used fuel rods would proceed to generate steam which, if hot enough will interact with the zirconium sheath, releasing hydrogen. This process might have contributed all or some of the hydrogen that exploded in the reactor buildings. Even if the pools were not principal contributors, the explosions so disrupted the reactor buildings that radioactive fission products from the spent fuel pools are now being emitted directly into the atmosphere (Figs. 3a and 3b).¹²

Figure 3a. Satellite photo of reactor buildings 1-4. Green circles identify steam plumes from reactor buildings. DigitalGlobe

Use of mixed uranium/plutonium (MOX) fuel in Reactor 3 poses a special problem with its spent fuel storage because of the high toxicity of plutonium. Small amounts of plutonium have apparently been released and contaminate nearby soil.¹³

Discovery of high levels of radioactivity in areas as far as 36 miles from the plant site has caused officials to enlarge evacuation zones, increasing public concern.¹⁴ The reactors remain unstable and cooling systems are unrestored. The initial desperate efforts to cool the reactors and spent fuel pools by dumping of seawater on the plants in air drops and from fire engine pumps has been replaced by somewhat improved cooling with imported fresh water. The large amounts of salt deposited as the seawater turned to steam remains a serious problem of clogging the cooling systems of some reactors.

This poorly controlled flooding of the reactors has resulted in radioactive waters running off to the ocean, with daily reports of increasing contamination of seawater, and seepage into groundwater.¹⁵

Figure 3b. Oblique aerial view of reactor buildings 1-4, right to left. Steam plumes are from buildings 2 and 3, as in Fig. 3a. The severe damages to reactor buildings 3 and 4 allow direct release of radioactivity from spent fuel ponds to the atmosphere

These unresolved problems and the continuing releases of radioactivity to the environment led officials on April 12 to boost the crisis rating from 5 to 7, the highest rating on an international scale of nuclear accidents.

To stabilize the reactor sites now will require removal (and disposal) of huge amounts of contaminated water. Previous disposal plans never included the construction of decontamination plants and storage facilities, so current highly contaminated waters are being dumped in the ocean to make room for even more highly contaminated waters in the limited storage now available.¹⁶

In addition, the continued reports of short-lived iodine-131 contamination in and beyond Fukushima-I carry worrisome implications. The spent fuel in pools at the time of the earthquake would not contain much iodine-131 (half-life 8 days), so its appearance suggests it is coming from either a breached primary containment or fission reactions somewhere else in the plants, which are generating iodine-131 (and other radionuclides). If derived from a breached containment, the amounts of iodine-131 should be small, and should decline significantly from the date of reactor shut down.

Another possibility is that fission reactions are taking place in accumulations of fuel pellets that fell to the floors of reactor vessels or of spent fuel pools due to catastrophic deterioration of fuel rod sheaths, or in pools of melted fuel rods.¹⁷ The worst-case results of those potential events vary from melts burning through reactor vessels and into a water-filled torus (see Fig. 2) and either being cooled by the water (good) or causing violent steam explosions (bad).

If melts from fuel rods were to enter a dry torus, they could melt through the bases of the reactor buildings and migrate to groundwater beneath the reactors. This scenario could result in cooling of the melts by groundwater or violent steam explosions, resembling the phreatic volcanic eruptions that occur when hot rising magma (natural rock melts) encounters groundwater. The violent explosion scenarios would worsen the Fukushima disaster by orders of magnitude.¹⁸

We are all hoping for a less extreme outcome: successful stabilization of the reactors, that re-establishes controlled cooling to prevent overheating and further fuel deterioration in the reactors and spent fuel pools. Using seawater for emergency cooling of four of the six reactors has rendered them useless, so “stabilization” is merely a disaster-prevention step. It cannot be viewed as a solution to the eventual requirement to disassemble the damaged plants and their contaminated environs, and dispose of them in a manner that protects the environment and future populations for at least several hundred years. The suggested time frame allows for the decay of cesium-137 and strontium-90 to a minimal hazard level, and assumes no significant amount of plutonium-239 in the mix.

The eventual cleanup also will include removal and safe disposal of a very large amount of soil and rock in the unsaturated zone above the water table, which likely is heavily contaminated. Estimates of 30 years and $12 billion cost to scrap the damaged plants, based on very limited experience in Japan, are likely conservative.¹⁹

Acknowledgements

I have profited greatly from technical advice from Vernon Brechin, nuclear watchdog par excellence, Jane Nielson, geologist, and Ernest Goitein, former nuclear engineer.

Endnotes

¹Limited information from new reports mostly identify iodine-131 (half-life 8 days) and cesium-137 (half-life about 30 years). Many other short-lived radioisotopes likely are being produced but decay quickly. The short-lived isotopes remain problems only so long as they are being actively released. Strontium-90 (half-life about 29 years) and very small quantities (so far) of Plutonium-239 (half-life 24,100 years) also are reported. Even though Strontium-90 and Cesium-137 together dominate the reactors’ long-lived fission products, Strontium-90 is generally not being reported from Fukushima-I. One rule of thumb estimates that longer-lived radioisotopes remain hazardous for 5 times the half-lives, others use a factor of 10 to estimate the hazard lives. Thus, cesium-137 and strontium-90 are the most abundant longer-lived isotopes being released and will remain serious problems for 150 to 300 years. Plutonium-239 and its decay products will be with us beyond the foreseeable future (H.G. Wilshire, J.E. Nielson, and R.W. Hazlett, The American West at Risk: Science, Myths, and Politics of Land Abuse and Recovery (New York, Oxford University Press, 2008), Chapters 7, 10)

²Jane Nielson, Nature Bats Last, blog http://theamericanwestatrisk.wordpress.com/

³Details about location of the Sendai earthquake epicenter: U.S. Geological Survey, Magnitude 9.0 – Near The East Coast Of Honshu, Japan, 2011 March 11 05:46:23 UTC. http://earthquake.usgs.gov/earthquakes/recenteqsww/Quakes/usc0001xgp.php)

⁴Unconfirmed reports give as much as 5 minutes of severe earth shaking (David Biello, Anatomy of a Nuclear Crisis, Yale Environment 360, 21 March 2011), but a filmed record of liquifaction during the Sendai earthquake in a landfill-based Tokyo park began after liquifaction started and lasted for 3 minutes, 8 seconds. Time of activity elapsed before and after film was made is not known

⁵262 aftershocks of magnitude 5 or greater occurred within the first week, 49 of magnitude 6 or greater, and 3 of magnitude 7 or greater (National Aeronautics and Space Administration, Earth Observatory), http://www.nasa.gov/topics/earth/features/japanquake/quake-intensity.html. A 7.1 magnitude aftershock that cut power to northern Japan occurred 07 April 2011 as a reminder that the story as yet has no end.

⁶Euan Mearns, Fukushima Dai-ichi Status and Slow Burning Issues, The Oil Drum, 25 March 2011. http://www.theoildrum.com/node/7706#more; Biello, Anatomy of a Nuclear Crisis

⁷Unfortunately, the industry term ‘spent fuel’ is misleading. The fuel starts out having quite low levels of radioactivity. The longer the fuel spends in an operating reactor the more highly radioactive fission products build up in it. Fuel that has been in the reactor for two years may be twice as radioactive as fuel that’s only been in the reactor for one year. So as the fuel becomes increasingly more spent it’s radioactivity increases. Once removed from the reactor the radioactivity decreases rapidly in an exponential curve so that its level of radioactivity may be considerably down a year later when the next load of partly irradiated fuel is removed from the reactor. A month after the removal of the recent fuel load, its radioactivity may still be ten times greater than the fuel that’s been aging in the spent fuel pool for a full year (Vernon Brechin, written communication, April 2011)

⁸Arjun Makihajani, Post-Tsunami Situation at the Fukushima Daiichi Nuclear Power Plant in Japan: Facts, Analysis, and Some Potential Outcomes, Institute for Energy and Environmental Research, 14 March 2011; Euan Mearns, Fukushima Dai-ichi Status and Potential Outcomes, The Oil Drum, 17 March 2011. http://www.theoildrum.com/node/7675#more

⁹Jenna Fisher, The Christian Science Monitor, TEPCO To Decommission Fukushima Reactors: Japan Nuclear Timeline, 30 March 2011. http://www.csmonitor.com/World/Asia-Pacific/2011/0315/TEPCO-to-decommission-Fukushima-reactors-Japan-nuclear-timeline; Fukushima 1 Nuclear Accidents, Wikipedia. http://en.wikipedia.org/wiki/Fukushima_I_nuclear_accidents

¹⁰Dave Lochbaum, Possible Cause of Reactor Building Explosions, Union of Concerned Scientists, 18 March 2011; Euan Mearns, Fukushima Dai-ichi Status and Pronosis, The Oil Drum, 31 March 2011, http://www.theoildrum.com/node/7722#more

¹¹A description of the fuel rods disintegration in the reactor core as “catastrophic disintegration of the cladding structural integrity” rather than melting is given in Euan Mearns, Fukushima Dai-ichi Status and Potential Outcomes

¹²In testimony before Congress, Gregory B. Jaczko, Chairman, U.S. Nuclear Regulatory Commission, stated the Commission’s belief that there had been a hydrogen explosion in Reactor 4 [March 15] due to uncovering of fuel rods in the spent fuel pool. This destroyed the secondary containment. In the Commission’s opinion, the spent fuel pool was dry (http://www.nrc.gov/about-nrc/organization/commission/comm-gregory-jaczko/0317nrc-transcript-jaczko.pdf). Subsequently, TEPCO claimed that the spent fuel pools have been filled with water, but high radiation levels prevent access for verification. The vulnerability of spent fuel storage facilities is well known: Makhijani, Post-Tsunami Situation at the Fukushima Daiichi Nuclear Power Plant; National Research Council, Safety and Security of Commercial Spent Fuel Storage: Public Report, National Academies Press, 2006; Keith Bradsher and Hiroko Tabuchi, Danger of Spent Fuel Outweighs Reactor Threat, New York Times, 17 March 2011; Robert Alvarez, Safeguarding Spent Fuel Pools in the United States, Institute for Policy Studies, 21 March 2011

¹³Justin McCurry and Suzanne Goldenberg, Fukushima Soil Contains Plutonium Traces, According to Japanese Officials, The Guardian, 29 March 2011. The reported distinction between plutonium from atmospheric weapons testing and that originating in the MOX fuels of the power plant is apparently based on ratios of Pu-238/Pu-239, low in bomb tests, higher in MOX fuels (Vernon Brechin, written communication, 30 March 2011)

¹⁴Aerial surveys of radiation around Fukushima-I revealed hot spots as far as 36 miles from the plant with radiation levels that exceed international standards for immediate evacuation (Jim Smith, A Long Shadow Over Fukushima, Nature, 472 (7), 5 April 2011). Very high levels of cesium-137 will require evacuation for a very long period of time.

¹⁵Contamination of groundwater about 50 feet below the Fukushima-I reactors was reported on March 31, giving values for iodine-131 of 10,000 times the legal limit. TEPCO, the facility owner, reports on contaminant concentrations have been severely criticized; the company claims the iodine-131 value was checked and is correct, but is not sure of values for other contaminants. Since the location of the plant is so close to the ocean it is probable that groundwater in the surficial unconfined aquifer flows directly to the ocean. It is also likely that contaminants in the unsaturated zone in soils above the water table will migrate to the water table and then to the ocean over time. The rates of migration are not known (see Wilshire, H.G., Nielson, J.E., and Hazlett, R.W.,The American West at Risk: Science, Myths, and Politics of Land Abuse (New York, Oxford University Press, 2008),, Chapters 7, 13).

¹⁶World Nuclear News, Tepco’s Plans for Water Issues, 01 April 2011; Mari Yamaguchi and Yuri Kageyama, Search for Radiation Leak Turns Desperate in Japan, Associated Press, 04 April 2011

¹⁷Accidental restarting of nuclear fission chain reactions long after reactor shutdown may be causing formation of very short-lived chlorine-38 (half-life 37 minutes) by neutron absorption of stable chlorine-37 in seawater pumped into the reactors (F. Dalnoki-Veress, with an introduction by Arjun Makhijani, What Caused the High Chlorine-38 Radioactivity in the Fukushima Daiichi Reactor #1?, Asia-Pacific Journal , 30 March 2011, http://www.ieer.org/)

¹⁸Justin Elliott, Japan’s Nuclear Danger Explained, Salon, 18 March 2011

¹⁹Shigeru Sato, Yuji Okada and Tsuyoshi Inajima, Tepco’s Damaged Reactors May Take 30 Years, $12 Billion to Scrap, Financial News, 29 March 2011, http://hotstocksforyou.com/2011/03/tepcos-damaged-reactors-may-take-30-years-12-billion-to-scrap/; see also, Yamaguchi and Kageyama, Search for Radiation Leak, 04 April 2011

Nature Bats Last …

Here’s an updated list of the world’s largest earthquakes (there are 16 because I added Sendai to the USGS top-15 list. The size is given by the moment magnitude (MMagnitude), which measures the energy released by the main shock.

Many of us elders can recall the no. 2 quake in 1964, which struck Anchorage and wiped out the major port of Valdes.  It was the first really big quake to hit a part of the highly developed world. The magnitude originally given that quake was 8.9.  The magnitude scales have been extensively revised since then. And note that the Sendai quake was revised to a MMagnitude 9.0, now tied for 4th place, with the 1952 Kamchatka quake.

Rank	Date	Location	MMagnitude
1.	1960	Chile	9.5
2.	1964	Prince William Sound, AK	9.2
3.	2004	W of N Sumatra Undersea	9.1
4.	1952	Kamchatka	9.0
4.	2011	Sendai, Japan	9.0
5.	2010	Maule, Chile Offshore	8.8
6.	1906	Coast of Ecuador Offshore	8.8
7.	1965	Rat Islands, AK	8.7
8.	2005	N Sumatra, Indonesia	8.6
9.	1950	Assam / Tibet	8.6
10.	1957	Andreanof Islands, AK	8.6
11.	2007	S Sumatra, Indonesia	8.5
12.	1938	Banda Sea, Indonesia	8.5
13.	1923	Kamchatka	8.5
14.	1922	Chile-Argentina Border	8.5
15.	1963	Kurile Islands	8.5

If you get out an atlas and examine the sites of these quakes, you’ll see that all are Pacific Rim locations.¹ The Rat and Andreanof Islands are part of the Aleutian Islands.

Figure 1. Map of World Plate Boundaries

All are located above a subduction zone. The major ones are named on Figure 1, and are marked with jagged teeth on the map, top of Figure 2.² At subduction zones, ocean crustal rocks (oceanic plate) are being shoved beneath an overriding mass of continental crustal rocks (continental plate), or beneath oceanic crustal rocks of a different tectonic plate (also oceanic plate), as shown in Figure 2.

Continental rocks also can be forced underneath a continental plate — for example, India — formerly attached to Antarctica — currently is at the end of a continental mass being forced against (and locally under) the huge continental mass of Eurasia.

The cramming of a mass of rocks under and against another mass of rocks is the most dramatic geologic example of the irresistible force meeting an immovable object. The 1950s song on that theme said “somethin’s gotta give” — and when that “somethin’” gives, we experience an earthquake. The bigger the opposing forces, the bigger the potential earthquake.

Figure 2. Plate Tectonics Process

Above the world’s subduction zones that involve at least one colliding ocean plate, lines of explosive volcanoes either rise directly from the ocean (Aleutians) or erupt through a nearby continent (Andes, Cascades) or island chain (Japan). That volcanic activity is caused when the subducting plate heats up enough to melt, as shown in the lower part of Figure 2.

Not all volcanoes are formed by subduction, however. Hawaii’s volcanoes, for example, do not lie above a subduction zone. They generally are not as explosive and have largely different average compositions than subduction zone volcanoes.

Plates form along volcanic ridges, generally under the sea, but also in Continental rifts, such as the Rift Valley of East Africa. These volcanic rift zones are another type of plate boundary.

For California residents, southern, central, and the lower part of northern California (south of Cape Mendocino) DO NOT lie above a subduction zone. Earthquakes in the coastal area are related to movement along the San Andreas Fault, where rocks of the Pacific tectonic plate are being pushed along (and against) the western edge of the North American tectonic plate (the North American plate is moving westward). This is the third type of plate boundary.

I won’t discuss any additional general details here, but many web sites provide clear and complete information. One of my favorites is the ETE site.

North of Cape Mendocino, there are several subduction zones, including one that generates the Cascades Range volcanoes. Geologic studies of coastal Washington State have shown a record of numerous prehistoric inundations, believed due to earthquakes along the subduction zone, where the Juan de Fuca plate, the remnant of the now-totally subducted East Pacific plate, is being forced beneath the North American tectonic plate.

So something like Sendai could happen along the coast of northernmost CA, Oregon, and Washington, and also along other subduction zones to the north and west, where Pacific plate rocks are being shoved under the western end of the North American plate (Figure 1), creating volcanoes in southern Canada, and southwestern Alaska, site of the world’s second largest earthquake, in 1964.

Pacific-under-North America subduction zones also lie under the Aleutian Islands (1957, 1965), Kamchatka (1923, 1952) and the Kurile Islands (1963) — and, yes northern Japan. The subduction under Japan is very complex. See more detail at this more professionally oriented website.

The double whammy of monster Sendai earthquake and tsunami is educating us to the vulnerabilities of a highly populated and developed subduction-zone coastline. President Obama’s statement that recovery would be easier for Japan than Haiti, due to its high level of development missed the fact that modern development separates populations from food production zones, and modern services depend on extensive, complex systems that collect and deliver energy and water resources, and that coordination of food and resources deliveries depend on long communication and travel lifelines.

The Sendai events also are validating those who opposed building nuclear plants along the San Andreas fault, and on the coast north of far northern California, and of Oregon, Washington State, and southern Canada, above the Juan de Fuca subduction zone. Alaska and the Aleutian Islands are also bad spots for siting nuclear reactors.

Of course, big offshore earthquakes generate tsunamis, and the Sendai quake’s first devastating tsunami is the main cause for such total devastation as we’re now seeing on the news. ALL of coastal California is an earthquake hazard zone, and also vulnerable to Pacific subduction zone tsunamis, as we can see from the damage to harbors at Crescent City, and Santa Cruz, CA. It is even more vulnerable to tsunamis from the Juan de Fuca subduction zone, and tsunamis that might be generated from the Aleutians subduction zone.

Both government and members of the public MUST scrutinize building proposals for extensive energy and water-delivery systems that lie in or would cross the many hazard-prone areas, with the images from northeastern Japan in mind. They illustrate like nothing else what Paul Hawken and co-authors meant when they wrote: “Nature bats last, and owns the stadium.”

1. When this website comes up, scroll down to see the map of plate tectonic boundaries.

2. On this website, scroll to the item “Super Earths Will Have Plate Tectonics.”

Bakken: Cold Facts on Shale Oil

Our blogs on the Bakken Formation of Montana and North Dakota, and other “tight” or “bound” petroleum-bearing units, have addressed the fantasy that such shale oil and gas sources will provide the United States (and in some versions, the WORLD) an unending energy bonanza. The unfavorable comments tend to contain put-downs, some couched in a rather personally antagonistic tone. This tends to happen when the commenting parties lack the data to back them up. The comments generally miss the mark, however.

We do NOT say that the U.S. has no extensive oil fields able to keep on producing petroleum for U.S. consumption, nor have we implied that some of the known fields are not currently economic. We do say that the aggregate production will not make up for the steep production declines at a majority of the oil fields that once fueled the U.S. economy and military. As a result, as long as the U.S. economy remains tied to petroleum, we will continue to rely on imports from Canada and beyond.

Industry and government data supporting our position are exhibited and discussed on many websites. We cite a few of them in what follows.

World Energy Consumption (horizontal scale) in billions of barrels, Compared to National Incomes (vertical scale) in billions of dollars

So what keeps Bakken and other shale oil sources from being our salvation? One part of the answer is that the U.S. is one of the world’s leading petroleum consumers. In our book we wrote (p 313): “By 2000 Americans represented less than 5% of the world’s population but consumed about one-third of its annual energy supplies.” To meet our demand requires finding new oil at a rate many times higher than the current rate of new U.S. petroleum discoveries. This “new finds” deficit (in terms of the estimated resource available in the newly discovered fields) has been developing since 1930, and grows larger with every passing year.

Another part of the answer involves the difference between “shale oil” petroleum resources, like Bakken, and the bonanza “conventional” oil resources of 100 years ago. In those early days, petroleum gushed out of relatively few holes drilled into very large underground pools, driven by dissolved gases. Many fewer holes were needed to extract most of the recoverable oil from those large pools of yesteryear than are now required to extract oil from Bakken.

Some of the shale oil is in small dispersed “pools,” but much of what’s there is attached (“bound”) to the rock and must be coaxed out the ground, using varied techniques such as “fracking.” The dispersed pools and need for injecting “fracking” fluids mean that the Bakken developers will drill many, many holes and use a lot of energy to get the petroleum out and process it into fuel. As a result, the NET ENERGY[1] for producing this oil will be a lot less per drill hole compared to even 40 years ago, when U.S. petroleum production was at its highest point.

There is no currently known domestic oil bonanza that will keep supplying current U.S. petro-thirst far into the future, and certainly no supply that will support unending consumption growth. There is equally no petroleum bonanza beyond U.S. borders that can supply unending growth in worldwide consumption.

As Kurt Cobb wrote in a Resource Insights article[2]: “In the United States alone the new process could mean 2 million barrels a day by 2015 from … fields once thought too difficult to develop ….” (But note that the U.S. consumes more than 20 million barrels of petroleum a day.) And Cobb continues: “[I]f … the projections are correct, then oil flows from tight oil in the United States will represent about 2 percent of world production in 2015. And if the more pessimistic estimates of the U.S. Energy Information Administration come closer to actual U.S. tight oil production in 2015, [it] will represent about 0.5 percent of world production. Neither amount is enough to move the price of oil ….”

But Cobb also notes, “There is reason, to doubt the claims … for tight oil supplies … beyond the fact that the companies making them are often publicly traded and therefore have incentive to manipulate their stock prices … The original shale gas promoters believed that natural gas would be uniformly available from the giant shale basins found in the United States. They were wrong. Only a few sweet spots have been profitable. As humans have done throughout the age of oil, tight oil developers will target the sweet spots first since they are the cheapest and easiest to exploit. Then, they’ll move on to areas that are progressively harder and thus more expensive to exploit. Over time tight oil won’t become easier to get; it’ll become harder to get just like shale gas.”

Gail Tverberg’s blog[3] has addressed the contention that advanced “new” techniques will add vast amounts to U.S. Geological Survey estimates of the Bakken resource, contrary to Bill Bergseid’s assertion in his recent comment on our Bakken blogs.

Says Gail: “… this is not really a new drilling technique … hydraulic fracturing was first used in the United States for oil and gas wells in 1947. It was first used commercially in 1949. Directional drilling, including horizontal drilling is almost as old, but … not widely used until downhill motors and semicontinuous surveying became possible. The techniques have gradually been refined …. A major reason we are using these techniques is because much of the easy-to-extract oil has already been extracted. Horizontal drilling and hydraulic fracturing are more expensive, but can be used to get out oil that would be inaccessible otherwise. The hope is that oil prices will be high enough to make these techniques profitable.”  At present, natural gas prices do not provide much profit.

Gail also agrees with Kurt Cobb about the potential for disappointing results: “There are several reasons why the hoped for [2 million barrels per day] might not be realized … [o]ne is … inadequate infrastructure [that could] prove to be a roadblock to meeting ambitious production goals … currently oil is being transported to market by rail and truck, and drilling companies have erected camps for workers. … What tends to happen when there isn’t adequate transportation for the oil is the selling price of the oil tends to be depressed, relative to other types …”

But then high oil prices “tend to send the economy into recession, so world prices may not rise as much as hoped–they may oscillate instead, rising, then putting the economy into recession and falling again …”

Too much optimism before drilling, such as now being spread on the web, also can be a trap — Gail again: “It is natural for those who are trying to get others to invest in these ventures to base their assumptions on an optimistic view of the future. If experience with shale gas in Texas is any clue, once realities start setting in, the level of drilling may decline, and overall production, after an initial run-up, may decline.”

U.S. Crude Oil Production since 1985

But here’s the bottom line — that is, the thin to very thin blue line at the bottom of the chart at left (Gail’s Figure 4). She explains: “If we look at a graph of countrywide US oil production, it has been decreasing prior to an uptick in 2009 and 2010. Bakken oil production (in ND +MT) is shown near the bottom of Figure 4. It appears as a thin blue line that was a bit thicker back in the late 1980s, became thinner for many years, and now is a bit thicker (reaching an average of about 370,000 barrels a day in 2010). Getting that line, or that line plus some other areas that are only starting up, to increase by 2 million barrels a day, to 2,370,000 per day by 2015, would be a tall order.”

At the same time, “US crude oil production has been headed downward for a long time–actually since 1970, not just since 1985 [as] shown on … Figure 4. If overall production is to … increase by 2 million barrels a day by 2015, it will be necessary to overcome these [other] declines, as well … What happens is that each year, more and more oil fields and oil wells within oil fields become non-economic. These are closed. Also, what is extracted is an oil-water mix, and the proportion of oil tends to fall over time. This means that if a given volume of oil-water mix is processed from a well, each year the well will yield less oil and more water.”[4]

References

---

[1] Net energy is also called EROI or EROEI (energy returned on energy invested).

[2] Kurt Cobb, The week of the game changer in oil, or was it? Resource Insights, Published Feb 13 2011 (Archived at http://resourceinsights.blogspot.com/2011/02/week-of-game-changer-in-oil-or-was-it.html)

[3] gailtheactuary (Gail Tverberg), Is “shale oil” the answer to “peak oil”? Our Finite World Posted on February 14, 2011 (http://ourfiniteworld.com/author/gailtheactuary/).

[4] gailtheactuary also contributes substantial commentary on The Oil Drum website (www.theoildrum.com).

Solar Power Plants, Water, and Climate

Solar Power Plants, Water, and Climate Change

This blog is a critique of environmental impact assessments for 17 solar power plant projects in the southwestern U.S. Thirteen of the projects are on the Department of the Interior’s fast track renewable energy developments list for public lands.¹ CEQA (for projects in California) and NEPA environmental impact assessments were fast-tracked to meet the December 31, 2010 deadline for securing stimulus funding for these expensive projects.² Data sources and annotated background information on the projects can be downloaded from our website’s Resources page as a pdf (see Endnote 2).

Whether or not enough water will be available for power plant projects in the arid southwest is a subject of controversy. The southwestern U.S.’s surface waters are already over-allocated and the various states of groundwater overdraft in many basins have not curtailed approval of further groundwater allocation for solar power plants. All of the solar projects must use water for construction in the short term, and for operations over the life of the plants. Air-cooled photovoltaic and heat-engine technologies use least, and solar thermal technologies use the most. Table 1 lists estimated water use in these categories and total use for the construction phases, which vary in duration.

Table 1. Solar Power Plant Summary of Plant Type and Projected Water Use

_________________________________________________________________________

Amargosa Farm Road. Parabolic trough, 464 MW capacity. Dry cooled, auxiliary equipment wet cooled. Operational** water use 400 acre-feet per year (afy). Construction, 39 month duration; water use, 1,950 af.

*Blythe Solar Project. Parabolic trough, 1000 MW capacity. Dry cooled, auxiliary equipment wet cooled. Operational water use 600 afy. Construction, 69 months duration; water use, 5,890 af.

*Genesis Solar Project. Parabolic trough, 250 MW capacity. Dry cooled. Auxiliary equipment wet cooling (no water use estimate given). Operational water use 218 afy total. Construction, 39 months duration; water use, 2,440 af

*Palen Solar Project. Parabolic trough, 500 MW capacity. Dry cooled, with auxiliary equipment wet cooled. Operational water use 300 afy. Construction, 39 months duration; water use, 1,500 af.

*Ridgecrest Solar Project. Parabolic trough, 250 MW capacity. Dry cooled, with auxiliary equipment wet cooled. Operational water use 150 afy. Construction, 28 months duration; water use, 1,470 af.

*Ivanpah Solar Project. Power tower, 400 MW capacity. Dry cooled, with auxiliary boiler operated during transient cloudy days or at night, water use not specified. Operational water use 100 afy. Construction, 72 months [based on assumed 6 work days/week]; water use, 2,255 af.

Rice Solar Project. Power tower, 150 MW capacity. Dry cooled. Operational water use 150 afy. Construction, 30 months duration; water use, 780 af.

*Sonoran Solar Project. Parabolic trough, 375 MW capacity. Wet cooled, 3,000 afy (assumes 25% energy production from gas co-firing); Operational water use for dry cooled alternative 150 afy (assumes 25% energy production from gas cofiring). Construction, 39 months duration, no water use estimate.

Abengoa Solar Project.  Parabolic trough, 250 MW capacity. Wet cooled. Operational water use 2,160 afy. Construction, no estimates available.

Beacon Solar Project. Parabolic trough, 250 MW capacity. Wet cooled. Operational water use 1,388 afy. Construction, 5 years duration; water use, 3,765 af.

Nevada One Solar Project. Parabolic trough, 64 MW capacity. Wet cooled. Operational water use ~400 afy. Construction, no duration or water use figures available.

*Crescent Dunes Solar Project. Power tower, 110 MW capacity. Hybrid wet/dry cooled. Operational water use 600 afy. Construction, 30 months duration; water use, 725 af.

*Imperial Valley Solar Project. Heat engine, 750 MW capacity. No generation cooling. Operational water use 33 afy. Construction, 39 months duration; water use, 166 af.

*Calico Solar Project. Heat engine, 850 MW capacity. No generation cooling. Operational water use 20 afy. Construction, 52 months duration; water use, 600 af. Rights to this land have been sold, may be used for PV installation.

*Desert Sunlight Solar Farm. Thin film PV, 550 MW capacity. No generation cooling. Operational water use 29 to 1,460 afy. Construction, 26 months duration; water use, 1,400 af

*Lucerne Valley Solar Project. Thin film PV, 45 MW capacity. No generation cooling. Operational water use 0.07 to 0.1 afy. Construction, 270 days duration; water use, 10 af.

*Silver State Solar, N & S.  Thin film PV, 327 MW capacity. No generation cooling. Operational water use 21 afy. Construction, 4 years duration; water use, 600 af.

__________________________________________________________________________

* Fast-track project

** Operational water use figures are given in acre feet per year (afy) for the life of the projnect, Construction uses are given in total acre feet (af) estimated to be used for the period of construction only.

Estimates of operational water consumption range from 100 to 600 afy for dry cooled solar thermal projects, from 400 to 3,000 afy for wet cooled solar thermal, and from 0.07 to 33 afy for heat engine and photovoltaic arrays (although one inexplicably ranges from 29 to 1,460 afy). Water use and project size are only slightly correlated for each type of plant.

Water use estimates for construction vary from 10 to 3,765 af for duration periods of 9 months to 6 years. Water use estimates for comparable projects vary so widely that many must be little more than guesswork, heavily influenced by project proposers. The public is not likely to see accurate figures until the projects have been in service over a substantial period. Wet cooling strategies clearly are far more water-consuming than dry cooled designs, but substantial amounts of groundwater likely will be consumed by both over the prolonged construction periods.

Wet cooling is preferred by project developers because it costs less to install and is more efficient than dry-cooling, but its use in water-scarce arid regions is discouraged both by agency and public pressure. Potentially significant operational problems might force greater reliance on wet cooling after these expensive power plants have been built, however.

The disadvantages of dry cooling include: higher capital costs (6 to 10 times the cost of wet cooling),³ higher auxiliary operating requirements (high energy use to operate fans and pumps),⁴ fan noise, and lower plant performance, especially on hot days, when the peak power is most in demand. Lower plant performance translates directly to higher electricity costs.

Model studies show about 5% lower performance for dry cooled parabolic trough plants, and under 2% for power tower plants. During hot periods, however, the performance penalties are more than triple: 17.6% for parabolic trough plants and 6.3% for power tower plants. Lowered generation of electricity can add significantly to the cost of the electricity produced.⁴ Efficiency penalties might be even greater: a technical study of hybrid air cooled power plants of the type used with geothermal sources and parabolic-trough solar thermal, discovered a 37% output reduction on hot days with air cooling than with wet (evaporative) cooling.⁵

A critical concern that is not assessed by any of the environmental documents I have reviewed is the potential impact of climate change on the operation of these solar facilities. The environmental assessments focus solely on the climate effects from greenhouse gas releases in plant construction and operation. Climate warming is already happening, as has been abundantly demonstrated in the scientific literature, and the predicted effects include extended drought in the southwestern U.S.⁶ Considering both the existing temperature and precipitation trends and the potential for abrupt climate change,⁷ it would be wise to assess the potential problems affecting the solar thermal power plants now being considered for installation. Prolonged hot periods are likely to bring pressure from plant operators to shift to wet cooling with a risk of depleting aquifers. Operation permits already allow night time make up of reduced solar insolation from transient cloudiness, but it is not clear that a shift to wet cooling could replace full days of hot weather. If permits do not cap permissible levels of water use, there may be trouble ahead.

Endnotes

1. U.S. Department of the Interior, Bureau of Land Management, Fast-Track Renewable Energy Projects, January 6, 2011. http://www.blm.gov/wo/st/en/prog/energy/renewable_energy/fast-track_renewable.html

2. Howard Wilshire, Fast-Tracking Solar Energy in the Desert, 2010 www.theamericanwestatrisk.com, click on Resources

3. EPRI, Palo Alto, CA, and California Energy Commission, Comparison of Alternate Cooling Technologies for California Power Plants: Economic, Environmental, and Other Tradeoffs, 2002, the initial capital costs of dry cooling systems exceed the costs of wet cooling systems by 6 to 10 times, and the fan power required for cooling is 4-6 times higher. Such penalties would substantially increase the costs of solar electricity.

4. U.S. Department of Energy, Concentrating Solar Power Commercial Application Study: Reducing Water Consumption of Concentrating Solar Power Electricity Generation, U.S. Department of Energy, Report to Congress [2008] http://www.nrel.gov/csp/pdfs/csp_water_study.pdf; U.S. Department of Energy, Estimating Freshwater Needs to Meet Future Thermoelectric Generation Requirements, 2008 Update, DOE/NETL-400/2008/1/339, 2008. http://www.netl.doe.gov/technologies/coalpower/ewr/pubs/2008_Water_Needs_Analysis-Final_10-2-2008.pdf

5. Written communication from John Rosenblum, Rosenblum Environmental Engineering,  November 30, 2010; Greg Mines, Evaluation of Hybrid Air-Cooled Flash/Binary Power Cycle, Idaho National Laboratory, October 2005

6. U.S. Global Change Research Program, Climate Change Impacts in the United States, A State of Knowledge Report from the U.S. Global Change Research Program, 2009; Richard Seager and G.A. Vecchi, Greenhouse Warming and the 21^st Century Hydroclimate of Southwestern North America, Proceedings of the National Academy of Sciences, vol. 107, no. 50, 2010; Seth Shulman, Dust Bowl 2: Drought Detective Predicts Drier Future For American Southwest, Grist, 12 August 2010

7. U.S. Geological Survey, Abrupt Climate Change, Final Report, Synthesis and Assessment Product 3.4, U.S. Climate Change Science Program and the Subcommittee on Global Change Research, 2008; G.T. Narisma and others, Abrupt Changes in Rainfall During the Twentieth Century, Geophysical Research Letters, vol. 34, L06710, doi:10.1029/2006GL028628, 2007

Greener Solar Developments

A major new solar power plant proposal is in the works that makes better sense than siting solar power on previously undisturbed lands. The Westlands agricultural district in the San Joaquin Valley encompasses thousands of acres of salinated land, which is degraded and rendered unproductive for agriculture after decades of agricultural irrigation (Figure 1).¹ The Westlands project is underway to build a 5,000 MW solar park on these degraded lands (“brownfields”).

Figure 1. Salination of agricultural land, southern San Joaquin Valley

A project of this size will take decades to buildout, and depends on major upgrades to the electrical transmission system,^{2, 3} but use of degraded lands is a much better idea than current projects in the Mojave Desert on little-damaged public lands (see our pdf on Fast-Tracking Solar Development in the Desert). Whether a photovoltaic (PV) or solar thermal plant will generate the electricity is not yet clear, but since cooling and cleaning water would have to be imported, PV is the likely choice.

Another 5,000 MW project proposed for a site on Owens Dry Lake, southeast of Westlands, is more contentious. The site’s disturbed lands are on large parts of the dry lake surface and adjacent flatlands. Although disturbed, the flatlands have a mature vegetative cover, so grading to install PV arrays would open a new source of dust and sand for the area’s frequent high winds to transport.

The proposal supposes that installing solar panels will reduce dust yield and offset the current need for periodic shallow flooding to reduce dust transport. PV arrays on the dry lake surface would reduce (but not eliminate) the size of the dust fetch (the area contributing dust during windy intervals) (Figure 2).

Figure 2. Multiple dust sources, minor dust storm, Owens Lake, CA

The solar panels also will create surface roughness, like vegetation, so reducing wind velocity and hence its dust-carrying capacity and overall dust transport. But the near-surface wind turbulence induced by the solar array also would likely cause severe problems of dust impacts on the panels themselves. And if PV panel systems are tracking types (panels constantly turn to maximize solar gain), the amount of land exposed to dust yield is larger than for fixed panel arrays.⁴

An issue for the Owens Lake proposal is the composition of the dry lake surface, where corrosive materials have been found that have a potential to degrade the panels more severely than plain dust. This discovery has apparently dampened interest in building a solar mega-project, limiting the current proposal to a 50 MW pilot project. The risk of occasional natural flooding, which could weaken the stability of panel supports, has not yet been addressed .

Endnotes

1. Howard G. Wilshire, et al., Geologic Processes at the Land Surface, U.S. Geological Survey, Bulletin 2149, 1996

2. The American Society of Civil Engineers recently gave the U.S. electricity grid a grade of D (American Society of Civil Engineers, U.S. Electric Power Grid, 2005: http://apps.asce.org/reportcard/2005/page.cfm?id=25).

3. See also The Oil Drum, The U.S. Electric Grid: Will It Be Our Undoing? – Revisited, The Oil Drum, 6 August, 2010: http://www.theoildrum.com/node/6817#more. This article considers the current grid inadequate for carrying additional electricity, which is hoped to come from renewable sources

4. Tracking arrays require greater spacing between solar collector panels to avoid the shading effects caused by the sun-tracking movement of the modules.

Bakken Oil non-Bonanza, revisited

We have received a comment from “John B” relevant to our blog entry debunking the circulating internet myth that the Bakken shale-oil resource can supply the U.S. thirst for petroleum far into the future. (Some versions of the myth imply that Bakken can supply all the oil we can ever use.)

In his comment, “John B” agreed that the Bakken shale oil is not an immense bonanza, but contended that “The number of wells going in is increasing, and the rate they are going in is also increasing. Will this drilling solve all our energy needs? No, but each little bit does make a difference. … If this demonstration in North Dakota can be reproduced in other formations throughout the country, then it WILL have an impact on our import needs, and ‘that’s worth talking about!’…” In reply, I stated: “However quickly the Bakken field can be exploited, growth of on-land U.S. oil production (including from the Bakken Formation) cannot keep up with depletion of older fields plus consumption growth.”

U.S. oil production and drilling rate from 1949 to 2005

The graph¹ shows why accelerated drilling into the Bakken Formation probably will not make a difference in the level of U.S. petroleum production. This figure is a plot of both U.S. oil production, in billions of barrels of oil equivalent per year (to cover all petroleum fractions), along with the total depth of all oil wells drilled in the U.S., plotted as millions of feet per year, from 1949 to 2005. (The number of feet drilled is probably a much more accurate representation of oil well drilling than the number of wells drilled).

The graph shows again that U.S. oil production peaked in 1970-71, as predicted by M. King Hubbert over a decade earlier. The rate of oil well drilling peaked in 1979 or 1980, due to high oil prices, as Ronald Reagan made his hollow promise that the U.S. oil industry and market forces would yield “energy independence.” Since 1971, the production curve has steadily declined. The lower ‘shoulder’ on the production peak, between about 1974 and 1984, represents extraction and depletion of Alaska’s North Slope oil bonanza. It slowed the decline of U.S. oil production but could not reverse it.

Starting in 1999, oil prices rose again, and as a result drilling rates also increased — only modestly when compared to 1980, but well above the level of drilling that preceded peak production. In 2004 as drilling levels rose, the decline in oil production increased. The authors of our reference summarize the relation between drilling and production thusly (page 235): “… oil production in the U.S. has declined by 50 percent, as predicted by Hubbert. The market did not solve this issue for U.S. oil because, despite the huge price increases and drilling in the late 1970s and 1980s, there was less oil and gas production then, and there has been essentially no relation between drilling intensity and production rates for U.S. oil and gas since.”

There has been no relation between drilling and production since the peak of U.S. production, because the oil left to be found and produced in the continental U.S. is in small fields or is dispersed, or “bound,” in “non-conventional” deposits, which are energy-expensive to produce. No known offshore oil fields have the potential to make up for the depletion of older fields, let alone to support growth of the already-immense level of U.S. oil consumption.

By 1990, the whole U.S. energy industry, including President Reagan’s energy advisors, had to be aware that the nation’s oil production was in irreversible decline. This appears to have been a top secret piece of information, kept from the American pubic. It is still largely unknown.

¹ Graph from Charles A. S. Hall and John W. Day, Jr., Revisiting the Limits to Growth After Peak Oil, American Scientist Online, May-June 2009 (http://www.americanscientist.org/issues/id.78/past.aspx), p 230-237.

Fracking for Natural Gas

Enhancing Natural Gas Production from Buried Rock

The business of hydraulic fracturing (aka fracing or fracking) to entice natural gas (mostly methane) out of hard rocks is on the minds of many rural citizens across the country. It especially concerns water well owners and their neighbors who signed lease agreements to gas producers and now face pollution of their drinking water.

The fracking process releases gas disseminated through rocks of low permeability (“tight formations,” such as shales) by injecting fluids into the gas-bearing formations at high pressure to induce fracturing. The induced fractures provide pathways for much easier collection of the gas for pumping  to the surface. The injected fluids are laced with a large variety of chemicals,¹ some carcinogenic. The high potential for contamination of water supplies by these dangerous chemicals, and even by the methane itself, is the chief public concern.²

As the craving for additional gas supplies increases, the potential scope of the problems from fracking spread to communities near gas-bearing coal beds, to regionally extensive shale formations. Figure 1 shows the huge extent of these areas in the lower 48 states.

Figure 1. Potential U.S. shale-gas resources

The Safe Drinking Water Act of 1974 (SDWA) is the main regulation that protects drinking water supplies from wastes and other substances injected into the ground.³ SDWA allows a state to become the prime regulator of waste disposal and other activities under the Act. Thus, the U.S. granted the State of Alabama regulatory authority over that state’s production of natural gas from coal beds.

In 1995, an environmental group petitioned the U.S. Environmental Protection Agency (EPA) to withdraw approval of Alabama’s SDWA regulations because they did not cover hydraulic fracturing practices for enhancing coalbed gas production. The court denied that petition on grounds that hydraulic fracturing was part of the production process and thus exempt from SDWA. On appeal, the 11^th Federal Circuit Court ruled in 1997 that hydraulic fracturing should be regulated under the SDWA.

Alabama revised its regulations in 1999, under EPA direction, but EPA’s approval was again appealed to the 11^th Circuit Court, which in this case ruled (2001) that Alabama’s regulations comply with the SDWA. Subsequent federal legislation through 2003 has attempted, but failed, to exempt hydraulic fracturing from SDWA altogether.

In June 2004 EPA released a study of coal bed fracking for natural gas production, concluding that hydraulic fracturing fluids posed little or no threat to U.S. drinking water (USDW). EPA’s conclusion was based on a literature review and an array of untested assumptions, including the assumption that the fracturing process would dewater the coal beds and so dilute the fracturing fluids,⁴ and that processes of dispersion, adsorption, and potential biodegradation of contaminants in the water would eliminate any significant risk. These conclusions were unsupported by any research done by the EPA, and were severely criticized by two EPA employees in a private letter to three Congressmen.⁶ At the same time, the EPA obtained a Memorandum of Understanding from three major coalbed methane producers that they would stop using diesel fuel in fracking fluids – the only component considered potentially harmful by the EPA.⁵

The EPA study had serious flaws, because it only dealt with coal beds as methane reservoir rocks, and interpreted the lack of evidence for contamination of water supplies by hydraulic fracturing in some incidents as evidence for the absence of contamination from fracking processes. In addition, the 2004 EPA review focused entirely on threats to water supplies from the hydraulic fracturing fluids.

Hydraulic fracturing is applied to a wide variety of rock types, not all of which respond  in the same way as coal beds. And the lack of evidence for contamination also lacked rigorous testing to assess the possibility of hydraulic fracturing causing drinking water pollution, not a simple matter. In addition to fracking fluids, the natural gas (and oil) sought by hydraulic fracturing, pollutants in the pore waters of oil and gas reservoir rocks , and pollutants entrained or adsorbed in migrating natural gas and hydraulic fracturing fluids by reaction with rocks through which they pass, all are potential sources of contamination. In the first case, combustion of methane in kitchen tap water⁷ (Figure 2) certainly suggests that methane released by hydraulic fracturing can and does migrate into water supplies.

Figure 2. Burning tap water - methane gas in well water

By 2008, rapid escalation of shale gas exploitation in the east and south re-energized the issue of drinking water contamination from hydraulic fracturing, making it a news item and focus of increased citizen concerns. In 2009, companion House and Senate bills were introduced to eliminate the SDWA hydraulic fracture exemption. These bills also could require disclosure of proprietary fracking fluids’ chemical formulas to emergency personnel. Early in 2010 the National Association of Utility Commissioners requested that EPA

“…carry out a study on the relationship between hydraulic fracturing and drinking water, using a credible approach that relies on the best available science, as well as independent sources of information. The conferees expect the study to be conducted through a transparent, peer-reviewed process with other Federal agencies as well as appropriate State and interstate regulatory agencies in carrying out the study.”

This EPA study is underway.

Not surprisingly, oil and gas industry sources have been quick to loudly proclaim there is no proven connection between hydraulic fracturing⁸ and drinking water contamination, and that the industry is thoroughly regulated by the States. It’s simple to avoid finding casual connection between fracking and water supply contamination when no study is undertaken to assess the issue. The lack of studies so far is due in part to the industry’s unwillingness to look for connections, and also to the difficulty and expense of rigorous studies to prove the presence or absence of connections.

Diagrams that illustrate fracking show a branching network of connected fractures in a thin, underground layer, where the gas and fluids are confined. But these are no more than industry admen fantasies: the actual effects of fluids pumped into the ground at high pressure are quite poorly understood. The earth’s outer zones (crust) are a patchwork of vastly different materials that can respond to increased fluid pressures in markedly different ways. As a result, the extent and direction of induced fractures can be quite different from the ones envisioned.

For example, fractures may be controlled by pre-existing weaknesses in the rocks, providing pathways for fluid movement beyond target zones. The closer the target zones are to drinking water reservoirs (aquifers), the greater the risk of contamination. So even though the connection between fracking and observed water pollution near hydraulic fracking operations is still unproved by scientific studies, the widespread anecdotal evidence of changes in the character and abundance of well water closely associated with fracking strongly suggest a connection.

Credible numbers on the recovery of hydraulic fracture fluids are few and hard to find. Estimates range from 10% to 20% for “horizontal” drilling (the most common technique for exploiting tight formations)⁹ to “near-100%” from some industry sources. The amount of water—on the order of 5 million gallons per well,¹⁰ or more if more than one hydraulic fracturing event is required—is itself a controversial use of fresh water, because it ends up contaminated. Industry assumes that unrecovered fluids remain in the gas-bearing rock unit. But it is possible, if not likely, that contaminated water escapes to surrounding rocks along pathways created or enhanced by the fracking. The potential for contaminating drinkwater aquifers depends on the pathways opened and proximity to the gas-bearing formations.

Recovering fracking-contaminated water from very deep rock formations presents worse problems of disposal, even though deep rocks may be less likely to leak hydraulic fracturing fluids into drinking water aquifers. The fluids are pumped to lined surface holding ponds, which are vulnerable to leakage, overflow, and rupture. Any release may lead to contamination of surface waters and shallow drinking water aquifers.¹¹ Eventually the fluids in holding ponds are removed for disposal, but protocols are not standard, and on western public lands, such contaminated waters commonly are dumped into evaporation ponds and surface streams,¹² both of which may lead to groundwater contamination.

The as yet unresolved issues of fracking for natural gas supplies include: why is it necessary to produce methane from deep, tight formations? The short answer is that the U.S. gas industry is not finding shallow, porous, easily productive gas fields any more. Much of the nation’s methane resource was “flared,” (burned) at wells and refineries throughout the terminating “Oil Age,” and like North American petroleum production, only the difficult-to-exploit, and environmentally damaging gas deposits remain. So we’re destroying a precious life-giving resource, clean water, to grub out the last gasps of gas.¹³

Endnotes

1. 258 chemicals constituents of hydraulic fracturing fluids are listed in Table 5-6, Draft Supplemental Generic Environmental Impact Statement, Natural Gas Drilling, New York State Department of Environmental Conservation, October 1, 2009

2. The documentary film Gasland, by Josh Fox reveals the problems of water well contamination http://www.hbo.com/html/error/browser_message_c.html?return=http://www.hbo.com/documentaries?cmpid=ABC449; see also Judi Buehrer, Fracking Advocates, Opponents Speak Out, American Water Works Association, Streamlines, 2 (19): 2010

3. Stephen F. Heare, Hydraulic Fracturing: Regulatory and  Policy Considerations, National Association of Regulatory Utility Commissioners, February 15, 2010,

http://www.narucmeetings.org/Presentations/Steve%20Heare%20EPA.pdf; S. Marvin Rogers, History of Litigation Concerning Hydraulic Fracturing to Produce Coalbed Methane, State Oil and Gas Board of Alabama, January 2009. http://www.iogcc.state.ok.us/Websites/iogcc/Images/Marvin%20Rogers%20Paper%20of%20History%20of%20LEAF%20Case%20Jan.%202009.pdf

4. Since the waters trapped in coal beds at formation are highly contaminated, this argument has little merit.

5. Weston Wilson, EPA Findings on Hydraulic Fracturing Deemed Unsupportable, Letter from geologist Weston Wilson, EPA employee, to Congresspersons Wayne Alard, Ben Nighthorse Campbell, and  dated October 8, 2004, Diana DeGette, critical of the 2004 EPA report. http://www.ucsusa.org/scientific_integrity/abuses_of_science/oil-extraction.html

6. U.S. EPA, Study to Evaluate the Impacts to USDWs [U.S. drinking water supplies] by Hydraulic Fracturing of Coalbed Methane Reservoirs, Fact sheet EPA 816-F-04-017, June 2004. The Memorandum of Understanding, applies only to coalbed methane extraction, not to shale gas. http://www.epa.gov/safewater/uic/wells_coalbedmethanestudy.html

7. Josh Fox, Gasland. http://www.nytimes.com/2010/06/21/arts/television/21gasland.html

8. For example, Energy in Depth, Debunking GasLand, 9 June 2010. http://www.energyindepth.org/tag/gasland/

9. Ali Daneshy, Why Care About Treatment Fluid Recovery, E&P Magazine 2 June 2010. http://www.epmag.com/Magazine/2010/6/item60863.php

10. Chesapeake Energy, Water Use in Deep Shale Gas Exploration, March 2010. http://www.chk.com/Media/CorpMediaKits/Water_Use_Fact_Sheet.pdf

11. Jennifer Goldman, Earthworks, Hydraulic Fracturing Myths and Facts; Why Natural Gas Is Not the Answer, un-naturalgas.org, 11 June 2010. http://un-naturalgas.org/hydraulic_fracturing_a-z.htm. In the pond lining business, two types of liners are recognized: those that are leaking and those that will leak

12. Howard G. Wilshire, Jane E. Nielson, and Richard W. Hazlett, The American West At Risk: Science, Myths, and Politics of Land Abuse and Recovery (New York, Oxford University Press, 2008), p. 323-326. Disposal of coalbed methane waste waters in evaporation ponds in Wyoming and Montana resulted in unexpected hot spots of West Nile virus due to breeding of mosquitos in the shallow warm ponds

13. Shale gas is a significant contribution to North American gas supplies, but probably is much less than hyped in the media. As production expands, the reality diminishes because the core areas of really good production are turning out to be a small percentage of the total deposits (<10%). Technically recoverable shale gas is on the order of 150 trillion cubic feet (Tcf), about 7 years of current consumption. Twice that is recoverable from more conventional sources, but in all we are not looking at 100 years of supply as claimed.  (Geologist Berman: Shale Gas Reserves ‘Substantially Overstated’, Interview, Association for the Study of Peak Oil-USA, 19 July 2010; reproduced by The Energy Bulletin. http://www.energybulletin.net)

Fast-Tracking Wind Development on Western Public Lands: Bad Idea

The Obama administration is promoting a fast-track review and approval process for renewable energy projects on western public lands, particularly wind and solar energy developments. Among the 34 projects listed for fast-track approval, six are wind developments.¹ The speeded-up process is designed to get projects underway by December 2010, to qualify them for large subsidies under The American Recovery and Reinvestment Act of 2009.²

Fig. 1. Solar Power Potential

Expediting approval of these major public lands projects raises many problems.One of the largest is that most Department of Interior (DOI) staff lack the expertise and experience needed for thorough review of the projects’ environmental impacts, as required under the National Environmental Policy Act (NEPA).

Although the Administration insists that the projects will have complete review and full public participation, its accelerated schedule allows for neither.³ The intended sites for fast-track wind developments lie in the same region targeted for solar projects.

This region contains the nation’s largest concentration of public lands, and has the highest potential for developing solar power (Figure 1). But, excluding offshore areas, it does not include the nation’s highest wind potential areas.

Fig. 2. Wind Power Potential

High-potential wind sites on western public lands are mostly limited to mountain ridge-tops. Developing wind farms on such steep terrain involves major road-building projects across hillslopes, which damage much more land than the road itself (Figure 2).⁴

In addition to extensive habitat segmentation (Figure 3)⁵, concentrated rainfall runoff, both from roads and turbine pads, cause major gullying downslope (Figure 4). Yet photographs of actual wind developments, and the project simulations found on industry websites, show no ground disturbance at all.

Fig. 3. Tehachapi, CA Wind Farms

In contrast to the regions of highest solar energy-generating potential, areas of high regional wind potential are concentrated on privately owned farming and grazing lands, located generally east of the Rocky Mountains (Figure 2). Wind farm development on agricultural lands does not seriously disrupt farming (Figure 5), and the terrain is generally not steep enough to create serious erosion problems from access roads and turbine pads.

Fig. 4. Windfarm gullies

Many wind developments on public lands have killed large numbers of birds and bats,⁶ a problem that agricultural wind farms may share. But the biggest drawback to extensive wind farm development in the Midwest is long transmission distances to coastal western population centers — a problem that plagues solar development of western public lands also.

Fig. 5. Farming-compatible

The limited potential for wind energy on western public lands and the high potential for greater environmental impacts of wind farms built in steep terrain militate against the fast-track wind development program. The severity of land damage must be considered along with energy loss problems of long transmission lines. Restoration of previously undamaged arid lands, in the sense of putting the land back the way it was prior to development, is not possible. In addition, some wind farms built on public lands have failed, with no adequate reclamation bonding or oversight to prevent continued erosion and wildlife habitat degradation (Figure 6).⁷

The costs for best possible reclamation results will be high, and must be assessed prior to development. The public needs to insist that sufficient funds to cover long-term reclamation by qualified independent parties be put up in advance, to avoid the same set of problems attendant on mine closure and reclamation, and ensure that public money is not the only source of funding.

Fig. 6. Abandoned wind farm

Notes:

¹Bureau of Land Management, Fast-Track Renewable Energy Projects, February 23, 2010: http://www.blm.gov/wo/st/en/prog/energy/renewable_energy/fast-track_renewable.html

²The American Recovery and Reinvestment Act of 2009 allows as much as 30% of development costs to be collected in cash, in lieu of tax credits

³Nielson, Jane, Obama’s DOI Reforms Oil and Gas Leasing on Public Lands, But What About Renewables?: www.theamericanwestatrisk.com (January 2010); Wilshire, Howard, Fast-Tracking Solar Development in the Desert: www.theamericanwestatrisk.com (March 2010)

⁴Studies of roadway impacts show that physical, chemical, and biological impacts of roads generally affect about 4 times the amount of land as the actual roadway. Figure 2 shows a downslope impact far greater than the road width (~6 feet) due to side-casting of material removed to create the road. See (H. G. Wilshire et al., The American West at Risk: Science, Myths, and Politics of Land Abuse and Recovery (New York, Oxford University Press, 2008), Chapter 5

⁵Wilshire, Howard and Douglas Prose. 1987. Wind Energy Development in California, USA. Environmental Management 11:13-20

⁶P. M. Cryan, Overview of issues related to bats and wind energy: Web version of presentation to the Wind Turbine Guidelines Advisory Committee Technical Workshop & Federal Advisory Committee Meeting, Washington, D.C., 26 February, 2008, U.S. Geological Survey General Information Product, 2008; Smallwood, K.S. and C.G. Thelander. 2005. Developing Methods to Reduce Bird Mortality in the Altamont Pass Wind Resource Area. BioResource Consultants, Final Report to the California Energy Commission, Contract No. 500—01-019

⁷ Fast track projects do require closure “restoration” bonding, but the level of bonding is unspecified

Bakken Oil Hype

Frequent Internet users are getting emails about the Bakken Formation in North Dakota and Montana, supposedly a great oil bonanza just waiting to be tapped if only nasty enviros would let it happen. The emails and websites say that Bakken would solve all our petroleum “needs.” (What, me worry about  global warming?)

Don’t believe it. There’s some oil to be gotten out of Bakken, and it’s going to be exploited. But the “bonanza” is nothing but hype.

U.S. Geological Survey (USGS) estimates of technically recoverable undiscovered oil reserves have gotten a lot of people stirred up about Bakken. In the industry, such USGS estimates are widely discredited as overly optimistic, however, and this is borne out by the current record of production from Bakken. In addition, the terms in which USGS presents their estimates are misleading. First, some numbers to bear in mind:

Current US oil production is about 1.9 billion barrels/year (5.3 million barrels/day)

Current US oil consumption is about 7.1 billion barrels/year (19.5 million barrels/day)

Not unreasonably, USGS estimates of undiscovered and technically recoverable oil are posed rather like gambling odds. At Bakken, USGS estimates:

5% chance of finding a total of 4.3 billion barrels,

95% chance of finding a total of 3.1 billion barrels, and

50% chance of finding a total of 3.6 billion barrels (the famous USGS “mean” estimate).

In its Fact Sheet 2008-3021, USGS upped its estimate of undiscovered oil in the Bakken by a factor of 25, compared to its 1995 figures. Many petroleum experts are quite willing to agree with USGS’s admission of significant uncertainty in these estimates.

…. BUT let’s take the numbers at face value. Together with consumption figures, they imply that:

•  USGS thinks there may be a very low (5%) chance of finding (not of producing!!) what amounts to slightly more than 7 months of current US oil consumption (that’s the best possible, assuming no growth in oil consumption!).

Unscrupulous sellers of interests/stock in the Bakken mention only this 5% figure, or even the field’s total possible oil endowment.

•  The more realistic low figure represents a very high (95%) chance of finding a tad over 5 months of our current consumption.

•  The media typically report USGS’s mean estimates as though they’re real, but the mean is just an average of the other two. In this case, the mean amounts to an even chance of finding about 6 months of current US oil consumption. But this mean really should be thought of as meaningless, for when the 5% and 95% figures are averaged (5% chance + 95% chance, divided by 2), the number assigned to the very unrealistic 5% chance is the tail that wags an over- optimistic chimera-dog.

Fact: average oil field production worldwide amounts to only about 25% of the total oil in a field. Current industry expectations for total oil recovery in an intensely drilled portion of the Bakken Formation are a little over half the USGS 95% chance estimate for that area. So forget the mean and 5% chances of discovery.

Last word: It takes a long time and thousands of expensive (~$4-8 million each) wells to fully develop a field the size of the Bakken, which  means that the Bakken can have only a barely discernible impact on daily US oil supply throughout the life of the field.

For a fuller discussion of these issues, see Appendix 9 (U.S. and Them: The United States and World Oil Reserves) in our book, The American West at Risk. To order the book, go to http://theamericanwestatrisk.com.

Look up the estimates and consumption figures yourself in these useful reports:

U.S. Geological Survey, Assessment of Undiscovered Oil Resources in the Devonian-Mississippian Bakken Formation, Williston Basin Province, Montana and North Dakota, 2008. USGS Fact Sheet 2008-3021: http://pubs.usgs.gov/fs/2008/3021/

The Oil Drum, The Bakken Formation: How Much Will It Help? 26 April 2008: http://www.theoildrum.com/node/3868#more

Tyler Hamilton, Bakken No Energy Panacea, Toronto Star, 14 April 2008:  http://www.thestar.com/business/article/414164

David Cohen, An Unconventional Play In The Bakken, The Energy Bulletin, 16 April 2008: http://www.energybulletin.net/node/42850

The Oil Drum, The Bakken Shale – Has It Moved The Needle? 2 November 2009: http://www.theoildrum.com/node/5928#more

MMS – Not Supposed to Regulate

One of our readers has gathered oral histories on oil production in a Louisiana Parish (County). In response to our “Foresight on Gulf  Oil Disaster” post, he wrote: “my research turned up lots of people who discussed the corrupt practices in the oil fields (or at least shortcuts). Anyone who knows about how the drillers are pushed to complete wells before ensuring the safety features are working would not be surprised at the number of blowouts in the Gulf.  I don’t expect the oil companies to behave any differently than they have for the last 100 years, but I would have thought the MMS [Minerals Management Service, the energy-resource permitting agency of the U.S. Department of Interior] would be paying closer attention to the deep water rigs because of their unique and technologically demanding environment.”

Yes, you might think that, and it should be true. But I vividly recall the creation of MMS. It was always a paper tiger and intended to be so.

Until the Reagan Administration, oil, gas, and coal leasing permits were processed, and the industry’s performance overseen and regulated, by the US Geological Survey’s Conservation Division.  It was the only part of USGS with a regulatory role, and many felt it didn’t belong there. But Congress had laid the responsibility on USGS because of its record of independence and scientific rectitude.

MMS was born (and the USGS Conservation Division eliminated) over one weekend in 1982. Not the usual, relatively slow, process for changing or reforming agency functions — with written proposals, Congressional hearings, counter-proposals, debates, compromises, etc. No — Reagan’s Secretary of Interior, James Watt, took Conservation Division out of USGS with no discussion and no warning to anyone in Congress or USGS.

I worked then at Western Region USGS, and knew a number of Conservation Division colleagues. They went home on a Friday and came back to work the following Monday, to discover that they were now employees of a new agency with no foundations or structure, and no defined relationship to any other governmental entity except the Secretary of Interior and his chain of command.  The only thing they could do for several days was gather at the local beer hall.  I well recall the few hours of one gathering that I attended on that shattering Monday.

There was no doubt in most of Conservation Division, and perhaps in USGS generally,  that MMS (often referred to as Mickey Mouse Service) was created to help industry function freely and not to regulate. The Reagan and both Bush Administrations were advocates of industry self-regulation, so MMS was not supposed to do much regulating.

Before Reagan left office,  Perry Pendley, a Watt aide (and now CEO of Mountain States Legal Foundation) was forced to resign after he told a coal company the minimum bid that MMS would accept for a mining permit. In 2008, as George W. Bush was leaving office, scandals over sex, drug use, and graft in MMS came to light.  The New York Times reported “allegations of financial self-dealing, accepting gifts from energy companies, cocaine use and sexual misconduct,” and revealed that some MMS officials were actually (not just figuratively) partying and sleeping with industry figures and their lobbyists. My guess is that such practices had probably been going on a good long time: MMS was set up to be cozy with industry, so where would any restrictive lines be drawn?

Pretty clearly, concerns about oil well safety in coastal waters were fairly far down the MMS list.