Saturday, February 15, 2014

Kyoto Protocol fiasco

The treaty on limiting greenhouse-gas emissions signed in Kyoto, Japan, on December 11, 1997, proved a classic fisaco--feeble from the start and stumbling toward failure. Of about 200 countries worldwide, only 32 agreed in 1997 to reduce their emissions of greenhouse gases: [1]

Goals (1990 Countries
to 2008-2012) Committing
  -8% E.U.-15,* Bulgaria, Czech Republic, Estonia, Latvia, Liechtenstein,
  Lithuania, Monaco, Romania, Slovakia, Slovenia, Switzerland
  -7% U.S.**
  -6% Canada,** Hungary, Japan,** Poland
  -5% Croatia
    0% New Zealand, Russian Federation,** Ukraine
  +1% Norway
  +8% Australia
+10% Iceland
* The fifteen countries who were European Union members in 1997 when the Kyoto Protocol was adopted--Austria, Belgium, Denmark, Finland, France, Germany, Greece, Ireland, Italy, Luxembourg, Netherlands, Portugal, Spain, Sweden and United Kingdom--agreed to an 8% total reduction goal to be distributed by and among themselves.
** The U.S. never ratified the treaty, and by the end of 2013 Canada, Japan and Russia had withdrawn.

Initial commitments for emission reductions were to be over a period from 1990 to 2010, where the latter year was to be measured by average emissions for years 2008 through 2012. Russia and the E.U.-15 countries had already reduced emissions during 1990 through 1997, whereas the U.S. had increased emissions by more than 10 percent during that time. In effect, E.U.-15 countries were agreeing to reduction of less than 7 percent over the next 11 to 15 years, while the U.S. was agreeing to nearly 20 percent reduction over that period. China, India, South Korea and Indonesia did not agree to any limits at all on their emissions, however large.

By late 2013, it became possible to review results from years considered under the Kyoto treaty, as data for 2012 were reported. A useful contribution has come from the Netherlands Environmental Assessment Agency, where analysts compiled fuel-related emissions of carbon dioxide worldwide. Government reporting tends to make data for those emissions easier to obtain and more accurate than data for emissions from other activities and for other greenhouse gases. They represent over three-fourths of all estimated greenhouse-gas effects. [2]

Fuel-related CO2 1990 to 1997 to 1990 to Treaty
emission changes 1997 2012 2008-12 goal
E.U.-15 countries -1.5% -8.5% -6.2% -8.0%
United States +11.8% -7.0% +8.8% -7.0%
Canada +13.3% +9.8% +23.6% -6.0%
Japan +8.6% +4.8% +7.4% -6.0%
Russia -34.8% +11.3% -28.2% 0.0%
Australia +22.2% +30.3% +60.7% +8.0%
China +43.0% +174.7% +252.2% none
India +45.5% +105.2% +167.9% none
South Korea +80.0% +42.2% +136.0% none
Indonesia +62.5% +88.5% +182.5% none
Worldwide +7.5% +41.4% +45.5% none

Of participants listed in Annex B of the 1997 treaty, only Russia achieved its goal--considering fuel-related carbon dioxide emissions and following treaty rules. The 15-country European Union came close at -6.2 percent change versus -8.0 percent goal. The United States missed badly, with +8.8 percent change versus -7.0 percent goal. Japan also missed badly, with +7.4 percent change versus -6.0 percent goal. As the data show, Russia and the 15-country E.U. began with advantages from reductions already in place when the treaty was signed in late 1997. For the period from 1997 through 2012, the last year considered in the treaty, the U.S. came close to reductions achieved by the 15-country E.U. and matched its treaty goal of 7 percent reduction. However, the comparison years designated in the treaty smeared the U.S. record of achievement.

The 1997 treaty never considered international trade. By 1990, North American industries had already closed large segments of emissions-intensive steelmaking, metal extraction and cement manufacturing. The U.S. and Canada continued to use large amounts of materials from those industries but imported much of that from overseas. They had little remaining potential for further large reductions in industrial emissions. In the early 1990s--following the 1989 collapse of Communist regimes--Russia, the former East Germany and other countries of eastern Europe closed many old and inefficient plants with high emissions. [3] [4] Ignoring international trade and specifying 1990 as a comparison year meant that scaledowns in heavy industry from 1991 through 1997 would be counted as progress toward emissions reductions for Europe and Russia but that earlier scaledowns would not be recognized for North America.

China, India, South Korea and Indonesia did not make commitments in the Kyoto treaty, From 1990 through 2012, their large increases in emissions eclipsed reductions achieved by the E.U. and Russia. China, India, South Korea and Indonesia have expanded heavy industries, exporting materials that North America, Europe and Russia continue to use but no longer produce in such large amounts. [3] A chart based on data from the Netherlands Environmental Assessment Agency shows trends for some countries during 1990 through 2012. [5]

The 32 participants in the Kyoto treaty that agreed to reduce their greenhouse-gas emissions represented about 48 percent of worldwide fuel-related carbon dioxide emissions in 1990, but by 2012 their worldwide share fell to only about 31 percent, mainly because of other, rapidly growing emitters. In 1995, China became the world's second-largest emitter of fuel-related carbon dioxide, passing the 15-country European Union. After 2005, China's emissions exceeded those of the United States. After 2009, China's emissions exceeded those of the 15-country E.U. and the U.S. combined. Data from the Netherlands Environmental Assessment Agency show shares of worldwide fuel-related carbon dioxide emissions. [5]

Fuel-related Share Share
CO2 emissions 1990 2012
E.U.-15 countries 19.0% 10.8%
United States 22.0% 15.0%
Canada 2.0% 1.6%
Japan 5.1% 3.8%
Russia 10.7% 5.1%
Australia 1.2% 1.2%
China 11.1% 28.6%
India 2.9% 5.7%
South Korea 1.1% 1.9%
Indonesia 0.7% 1.4%

Former Vice President Gore, who led the U.S. delegation at the December, 1997, Kyoto conference, was played for a fool by other participants. In July, 1997, the U.S. Senate passed a resolution by unanimous vote--Gore not voting--rejecting anticipated terms of the treaty that Gore signed later that year. [6] Former Presidents Clinton and Walker Bush and President Obama have all refused to submit the treaty Gore signed to the Senate for ratification. As of the start of 2014, four countries participating in the 1997 Kyoto treaty and its successors have dropped out. Since 1997, aside from E.U. expansion, no more countries have joined.

As of the start of 2014, countries participating in an extension of the Kyoto treaty to 2020 accounted for less than 15 percent of worldwide greenhouse-gas emissions. [2] Even if they and the United States were somehow to eliminate their entire combined emissions by 2020, growth in emissions from China alone, at its rate over the past ten years, would more than offset that achievement. No reduction of emissions can occur without participation by rapidly growing emitters: China, India, South Korea and Indonesia.

[1] Kyoto protocol targets, United Nations Framework Convention on Climate Change, 2014, at

[2] Jos G.J. Olivier, Greet Janssens-Maenhout, Marilena Muntean and Jeroen A.H.W. Peters, Trends in global CO2 emissions, 2013 report, Netherlands Environmental Assessment Agency, December, 2013, at

[3] Quirin Schiermeier, The Kyoto protocol: Hot air, Nature 491(7426):656–658, 2012, at

[4] Maria Csutora and Zsofia Mozner, Rethinking Kyoto compliance from a consumption-based perspective, Corvinus University of Budapest, 2012, at

[5] Olivier et al., Table 2.2 and Figure 2.2

[6] Senate Resolution 98 of the 105th Congress, available at

Tuesday, November 19, 2013

New England's invisible wind-power plants

At least 13 wind-powered electricity plants of industrial size, operating in New England during 2007 through 2012, are easily seen by visitors but invisible to federal government. They don't appear in Form EIA-860 data about plant characteristics, maintained by the U.S. Energy Information Administration, so that the plants are apparently unregistered with the U.S. Department of Energy. [1] They don't look to have been submitting Form EIA-923 data on their electricity generation. [2]

Rated outputs of New England's invisible wind plants, as reported by news media, vary from 1.5 to 6.0 peak MW, with from 1 to 3 wind turbines per plant. Of those plants, 11 are located in Massachusetts and 2 are in Rhode Island; 7 are apparently owned by government and 6 by industry and individuals; 3 plants apparently owned by government have commercial operators: ones in Fairhaven, Kingston and Scituate, MA. Among them, the invisible plants have 20 industrial-size wind turbines, rated at a total of 35 peak MW. Considering the plants with full calendar years of operation through 2012, a wind plant of that size would rank seventh largest in the region.

It's no surprise to find nonreporting wind plants in Massachusetts--New England's capital of trophy-size wind power. Starting in 2009, officials in Gov. Patrick's administration had a windfall--so to speak--millions of federal dollars in so-called "stimulus" subsidies to pass out, funding new wind plants. Aside from the Hoosac and Berkshire Wind projects in western Massachusetts, the Patrick administration channeled its largesse to small and trophy-size plants. Once a turbine was turning and the governor spoke, who cared? The following list identifies the 13 wind plants missing in action and their apparent owners and operators. It references some articles in Web-based news media indicating that the plants have been operating.

Jiminy Peak Ski Resort, Hancock (Lanesboro), MA, 2007, 1.50 MW, 1 turbine
-- Jiminy Peak Mountain Resort, 37 Corey Rd, Lanesboro, MA 01237, 413-738-5500

Portsmouth High School, Portsmouth, RI, 2009, 1.50 MW, 1 turbine
-- Town of Portsmouth, 2200 East Main Rd., Portsmouth, RI 02871, 401-683-3255

Town of Templeton Municipal Light, Templeton, MA, 2010, 1.65 MW, 1 turbine
-- Templeton Municipal Light & Water, 86 Bridge St., Templeton, MA 01436, 978-939-5323

Kingston Wind, Kingston, MA, 2011, 6.00 MW, 3 turbines
-- No Fossil Fuel, Mary O'Donnell, 47 Marion Dr., Kingston, MA 02364, 617-688-6088

Town of Kingston Landfill, Kingston, MA, 2011, 2.00 MW, 1 turbine
-- Kingston Wind Independence, c/o Aquinergy, 60 Almy Knoll Ter., Portsmouth, RM 02871, 401-835-4033

North Central Correctional Institution, Gardner, MA, 2011, 3.30 MW, 2 turbines
-- NCCI/Massachusetts, 500 Colony Rd., Gardner, MA 01440, 978-630-6000

Town of Scituate Wastewater Treatment, Scituate, MA, 2012, 1.50 MW, 1 turbine
-- Scituate Wind, c/o Solaya Energy, 56 Cummings Park, Woburn, MA 01801, 781-832-0201

Town of Fairhaven Wastewater Treatment, Fairhaven, MA, 2012, 3.00 MW, 2 turbines
-- Fairhaven Wind, c/o Solaya Energy, 56 Cummings Park, Woburn, MA 01801, 781-832-0201

Camelot Wind, Plymouth, MA, 2012, 1.50 MW, 1 turbine
-- Camelot Wind, 74-1 Camelot Dr., Plymouth, MA 02360, 508-888-9282

Lightolier, Fall River, MA, 2012, 2.00 MW, 1 turbine
-- Lightolier Div., Philips Lighting, 631 Airport Rd., Fall River, MA 02720, 508-679-8131

Varian, Gloucester, MA, 2012, 2.50 MW, 1 turbine
-- Varian Semiconductor Equipment, 35 Dory Rd., Gloucester, MA 01930, 978-281-2000

Gloucester Engineering, Gloucester, MA, 2012, 4.00 MW, 2 turbines
-- Gloucester Engineering, 11 Dory Rd., Gloucester, MA 01930, 978-281-1800

Narragansett Bay Wastewater Treatment, Providence, RI, 2012, 4.50 MW, 3 turbines
-- Narragansett Bay Commission, 1 Service Rd., Providence, RI 02905, 401-461-8848,74434

[1] Existing and planned generators, Form EIA-860, U.S. Energy Information Administration, 2013, at

[2] Power plant operating data, Form EIA-923, U.S. Energy Information Administration, 1970-2012, at

Saturday, November 9, 2013

New England wind capacity factors

New England's wind industry is in its youth--still at a very rapid rate of expansion. New Englanders who don't live near one of the wind plants tend not to know much about the dimensions of the industry and sometimes lack vocabulary to describe it. "Capacity factor" is one of the industry's key phrases.

The capacity factor for a power source is its actual output expressed as a fraction or percentage of its rated capacity. Although that is straightforward, in New England, at least, wind-energy promoters seem to avoid it. Instead they tend to confuse people by citing how many homes their projects could serve--whatever "homes" might mean. Factories, stores, offices, street lights and homes of different sizes don't seem to interest them. An accurate way to characterize a power source is through the average amount of power it can produce: the rated capacity, multiplied by the capacity factor.

It is usual to find the capacity of a wind turbine rated according to its peak output--during the strongest winds it can tolerate--rather than by its average output as installed, even though average output is usually what matters most. A knowledgeable reader encountering a capacity rating in "MW" will interpret that as meaning "peak MW." Capacity factors for a single turbine, a group of turbines or a whole wind plant are figured against their rarely achieved peak outputs.

Since in most places wind speeds are usually much lower than peak winds, capacity factors for wind turbines and wind plants are usually much less than 100 percent. When reporting capacity factors achieved by wind, with its great variability, measured outputs are often averaged over full operating years, avoiding false impressions resulting from seasonal changes. For example, in New England during a midsummer week a wind turbine may produce only a third the electricity that it produces during a midwinter week.

Accurately estimating a wind plant's capacity factor is a critical element for financial success. When a wind plant falls short of its expected capacity factor, its revenue typically falls short in proportion. To the same degree, it fails to displace conventional generation, with its pollution and greenhouse-gas emissions. So far, New England has only modest operating experience with wind plants of commercial sizes. Estimating the capacity factors for the region's wind plants, even averaged over several years, remains somewhat uncertain.

As of late 2013, there were ten New England wind plants of commercial size--rated 10 peak MW or more--with at least one full calendar year of operation. At that time, only three of the plants, with 78 turbines among them rated at 123 peak MW, had been operating for three or more full calendar years. Following are the numbers of commercial-size wind plants in each state, with their numbers of full calendar years of operation. [1] [2]

                 ME  (2) 1-year  (2) 2-year  (1) 3-year  (1) 5-year
                 NH  (1) 1-year  (1) 4-year
                 VT  (1) 1-year
                 MA  (1) 1-year

For the full calendar years 2010 through 2012 during which they operated, New England's commercial-size wind plants achieved a combined capacity factor of 26 percent. Those plants have a combined rated capacity of 515 peak MW, so their average combined output would have been about 134 MW. That is far less than the region's 20 large natural gas-fired plants, which generated, on average, more than 6,000 MW. Following are the plant names, states and opening years, rated capacities and capacity factors of individual wind plants for those years. [2]

           New England wind-power plants                                                                                    Capacity factors
Plant name State Capacity 2012 2011 2010
Mars Hill ME 2007 42 peak MW 36% 35% 33%
Stetson I ME 2009 57 peak MW 21% 31% 31%
Kibby Mountain ME 2010 132 peak MW 23% 24%  
Stetson II ME 2010 26 peak MW 19% 27%  
Rollins Mountain ME 2011 60 peak MW 24%    
Spruce Mountain ME 2011 20 peak MW 32%    
Lempster Mountain NH 2008 24 peak MW 30% 31% 36%
Granite Reliable NH 2011 99 peak MW 16%    
Sheffield VT 2011 40 peak MW 23%    
Berkshire Wind Plant MA 2011 15 peak MW 36%    

When data for calendar 2013 become available, six more commercial-size wind plants will appear in a similar list: Record Hill and Bull Hill in Maine, Groton in New Hampshire, Lowell Montain and Georgia Mountain in Vermont, and Hoosac in Massachusetts (recently renamed New England Wind). These newer plants add a combined rated capacity of 234 peak MW--representing capacity growth of 45 percent in a year.

Operators of Stetson and Rollins Mountain in Maine have noted that those plants were idle or curtailed for substantial periods of 2012, while Central Maine Power installed upgrades to a transmission line, causing an estimated 30 percent loss in total output for the year. [3] [4] The new Lowell Mountain plant in Vermont also experienced severe curtailments. Its operators needed to install a $10.5 million synchronous condenser--a phase-shifting motor-generator--to avoid causing instability on the ISO New England grid. [5]

With a larger and longer base of operations, some countries of western Europe have encountered discrepancies between capacity factors projected for commercial-size wind plants and those experienced. A survey of estimates from project developers, compared with estimates produced by academic researchers and with actual experiences, found a typical developer estimate of 35 percent capacity factor, average academic researcher estimate of 37 percent and average experience of 21 percent. [6] A government survey of the five largest wind development regions in California found an average capacity factor for about 11,600 active wind turbines, during calendar years 2000 and 2001, of about 22 percent. [7]

Experiences in Europe and California were both influenced by many small turbines--under 0.1 peak MW--installed while government promotions during the 1970s and 1980s offered large subsidies. Some either were poorly located or were too closely spaced. [8] More professionally designed and managed wind plants, using the larger and more robust wind turbines produced since the mid-1990s, usually achieve somewhat higher capacity factors. [9]

Nevertheless, for New England we should expect overly optimistic projections from project promoters, and we should be prepared to discount estimates from academic researchers. Not all discrepancies are faults of wind turbines or plant design and operation. In addition to problems during power transmission projects, New England wind outputs have been curtailed to avoid overloading segments of the power grid, called "congestion." [10]

Many practical elements that reduce capacity factors are also often omitted from estimates. Wind turbines are complex machines requiring periodic maintenance. They are exposed to lightning strikes, drastic temerature changes and storms. They suffer electrical, mechanical and control failures. [11] In the snowy country from northeastern Vermont through west central Maine, some roads may remain unplowed in winter. Heavy snow drifts can make back-country roads impassible until spring melt, so that power losses may extend over weeks. [12]

If their rotating components or automatic orientation (yaw control) systems fail, wind turbines can become candidates for disasters. [13] In some accidents, lubricating oil has ignited; turbine compartments have been completely incinerated. [12] In others, heavy blades snapped by strong winds have collided with turbine towers that folded and collapsed. There have been deaths, injuries and wildfires. [14] When turbines of a wind plant are damaged, obviously the plant's capacity factor suffers too.

[1] Existing and planned generators, Form EIA-860, U.S. Energy Information Administration, 2013, at

[2] Power plant operating data, Form EIA-923, U.S. Energy Information Administration, 1970-2012, at

[3] Tux Turkel, Inadequate transmission lines affect some Maine wind power, Portland (ME) Press Herald, August 4, 2013, at

[4] Tux Turkel, Wind industry says tax breaks are key, Portland (ME) Press Herald, December 31, 2012, at

[5] Willem Post, Was Vermont's Lowell Mountain wind turbine facility a good idea?, Energy Collective, July 15, 2011, at

[6] Nicolas Bocard (Department of Economics, University of Girona, Spain), Capacity factor of wind power: realized values vs. estimates, Energy Policy 37:2679–2688 (in English), 2009, available at

[7] Dora Yen-Nakafuji, California wind resources, California Energy Commission, 2005, at

[8] Paul Gipe, Wind Energy Comes of Age, Wiley, 1995, excerpted at

[9] Berthold Hahn, Michael Durstewitz and Kurt Rohrig, Reliability of wind turbines, University of Kassel (Germany), 2005, available at

[10] John Dillon, Grid constraints mean less power output from wind projects, Vermont Public Radio, January 30, 2013, at

[11] Kevin Alewine (Shermco Industries), Wind turbine generator failure modes, National Renewable Energy Laboratory, U.S. Department of Energy, September 19, 2011, at

[12] Whit Richardson, $4-million turbine fire at Kibby Mountain, Bangor (ME) Daily News, April 23, 2013, at

[13] Andred Walden, Wind energy's ghosts, American Thinker, February 10, 2010, at

[14] Summary of wind turbine accidents, Caithness (UK) Windfarm Information Forum, 2013, at

Tuesday, November 5, 2013

New England's wind power and politics

In New England, over the past several years, people would often hear of a new wind facility opening--typically with the state's governor or some other politician present. Yet wind still provides only a tiny fraction of the region's electricity. How come?

A look at New England's wind-power plants told much of the story. Although the machines are large on a human scale, their outputs are small on the scale of industry. At the end of 2012, there were 62 active plants rated at 0.1 MW peak output or more. Only 37 were large enough to be reporting generation to the government--rated at 1.0 MW peak output or more. The rest were "trophy" plants: single turbines just big enough to crow about. [1]

  Reporting Peak MW Trophy Peak MW
  plants total plants total
Maine 10 430 2 1
New Hampshire 3 171 0 0
Vermont 4 119 5 1
Massachusetts 20 84 18 6
Connecticut 0 0 0 0
Rhode Island 0 0 0 0
Totals 37 804 25 8

Electricity from these active wind-power plants remained a small fraction of the region's use. The following table shows state electricity use and reported in-state wind-power generation for New England. [2] [3]

  Use Wind Wind
  TWh* TWh* percent
Maine 11.5 0.88 7.6%
New Hampshire 30.4 0.21 0.7%
Vermont 5.6 0.11 1.9%
Massachusetts 57.1 0.09 0.2%
Connecticut 30.4 0.00 0.0%
Rhode Island 7.8 0.00 0.0%
Totals 142.8 1.28 0.9%

          * TWh, billions of kilowatt-hours

There is substantial flow of electricity across New England states and Canadian provinces. Maine exports most of the wind-generated electricity that Massachusetts and Connecticut import. Massachusetts and Connecticut also import small amounts of wind-generated electricity from upstate New York. [4]

New England has three areas with notable wind potential: (1) a broad swath from northern New Hampshire into central and northern Maine, (2) a north-south spine in western Vermont, dipping into western Massachusetts, and (3) an arc near the Atlantic shoreline extending many miles offshore, particularly around southeastern Massachusetts. [5] With offshore wind very costly and complicated to develop, it could hardly be surprising to find Connecticut and Rhode Island providing no significant wind power.

Today's most productive wind plants in New England are built on mountain ridges: the White and Longfellow Mountains and the Mahoosuc Range of New Hampshire and Maine and the Green and Berkshire Mountains of Vermont and Massachusetts. Conservationist and preservationist movements have sprung up to block the installation of new wind plants and power transmission lines in these areas. [6] [7] [8] So far they have yet to make common cause with similar efforts that focus on the region's southeastern ocean coasts. [9]

Maine has dominated New England's wind power, providing about 53 percent of active capacity at the end of 2012 and about 68 percent of wind-powered generation for the year. Of states participating, Massachusetts came in last with about 10 percent of capacity, although it was by far the leader in trophy plants. In part, that reflected state politics. Govs. Patrick of Massachusetts and Shumlin of Vermont have served as wind gadflies, constrained by finances of wind power and by their state geographies and vigorous protest movements but celebrating, when they can, symbols of what they see as progress.

Former Govs. Baldacci and King of Maine, in contrast, have served as wind promoters--encouraging, finding and participating in financial opportunities for their states. [10] [11] Sen. King's son, Angus King, III, became vice president for mergers and acquisitions at First Wind of Boston--as of 2012 the largest developer of wind power in Maine. Wind power, particularly in Maine, got a boost from the American Recovery and Reinvestment Act of 2009 (Public Law 111-5), adding new subsidies and loan guarantees to previous federal and state benefits.

For the next few years, the future appears to hold more of the same. In 2008, for example, urged on by Gov. Patrick and his departed environmental affairs secretary, Dr. Ian Bowles, Massachusetts enacted a state law requiring increasing amounts of electricity from renewable sources, including wind--called a "renewable portfolio." [12] [13] By 2008, however, Massachusetts utilities were already paying penalties for noncompliance with previous, less demanding state requirements. [14]

In 2008, Gov. Patrick announced a laughable goal to install 2.0 GW of capacity for wind power in Massachusetts by 2020--well after he has left office. [15] Five years later, the state had only 0.09 GW installed and 0.02 GW under review--all as measured by peak power, not the sustained power expected from conventional sources. [1] At first, Massachusetts agencies qualified only in-state renewable sources, but in June, 2010, the state caved in, quietly recognizing that Massachusetts lacked practical potential and accepting imports. [16]

Maine and New Hampshire look likely to expand wind power substantially. As of late 2013, there were ten major projects under review by Maine, New Hampshire and Vermont (with all plants 0.1 MW peak and over counted in the following table). [1]

Under review
  Plants Turbines Peak MW
Maine 12/7 226/292 431/730
New Hampshire 3/1 69/23 171/76
Vermont 9/2 46/35 120/80
Massachusetts 38/6 74/10 90/16
Totals 62/16 415/360 812/902

Six projects in Maine and the one in New Hampshire have state-approved contracts with Northeast Utilities, National Grid and Connecticut Light & Power--the major utilities serving southern New England. Those would add 296 turbines and 775 peak MW in capacity, nearly doubling the current size of New England wind power. Sparsely populated central and northern Maine, with its good wind potential, is getting nearly all the attention.

Because rural Maine is little developed, it lacks power transmission capacity. Independent operators of power transmission are not much interested. Lines must be sized for maximum power to be carried, but revenues scale with average power. Serving New England's wind power, with 23 percent average capacity factors, offers poor financial prospects compared with serving its gas-fired power, with 61 percent average capacity factors. [17]

New wind facilities can include power transmission in projects qualifying for state and federal benefits. Some projects have already built tens of miles of power lines, but new ones may have to build hundreds of miles. As that happens, prices of electricity from land-based wind plants are likely to rise beyond levels most recently reported for major utility contracts, [18] although not as high as those reported for offshore wind power. [19]

[1] Existing and planned generators, Form EIA-860, U.S. Energy Information Administration, 2013, at Smaller units from American Wind Energy Association and news media.

[2] Electricity profiles for New England states, U.S. Energy Information Administration, 2010, at The most recent data were for 2010, as of November 1, 2013.

[3] Power plant operating data, Form EIA-923, U.S. Energy Information Administration, 2012, at

[4] Energy sources in New England, ISO New England, 2013, at

[5] New England wind resources, U.S. Department of Energy, 2011, at

[6] Environmentally sound approaches to Maine’s energy policy, Citizens' Task Force on Wind Power (Maine), at

[7] Exposure to industrial wind energy's real impacts, Industrial Wind Action Group (New Hampshire), 2013, at

[8] Benefits low impacts high, National Wind Watch (Vermont), 2013, at

[9] Beginning of the end, Alliance to Protect Nantucket Sound (Massachusetts), 2013, at

[10] Tux Turkel, Wind backers decry conflict-of-interest claims, Portland (ME) Press Herald, January 31, 2010, at

[11] John Richardson, Angus King defends his wind career, Portland (ME) Press Herald, September 15, 2012, at

[12] Acts of 2008, Chapter 169. Beth Daley, Patrick signs landmark energy legislation, Boston Globe, July 2, 2008, at

[13] The so-called "Green Communities Act" of 2008 expanded on Acts of 1997, Chapter 164, quickening paces of requirements. Polestar Communications, Massachusetts renewable portfolio standard, ISO New England, 2004, at

[14] David Hurlbut, State clean energy practices, National Renewable Energy Laboratory, 2008, at

[15] Christopher Nichols, State legislation to boost renewable energy, Taunton Gazette, July 14, 2012, at

[16] Jon Chesto, Maine's mountains offer New England a modest alternative, Mass. Markets, August 26, 2010, at

[17] Evaluated for all major New England wind-powered and gas-fired power-plants in 2012. See [3]

[18] Rick Saia, State announces record wind-energy deal, Worcester (MA) Business Journal, September 23, 2013, at

[19] Michael C. Bailey, DPU approves Cape Wind contract with National Grid, The Enterprise (Falmouth, MA), November 26, 2010, at

Saturday, November 2, 2013

Renewable energy at a fair price

The Cape Wind project, started by Jim Gordon's company, Energy Management, in 2001, [1] has largely turned into a distraction for renewable energy in New England. It aims to build and operate an offshore wind farm between Cape Cod and Nantucket. [2] The site has very good wind potential, [3] relatively shallow waters and adequate access to power transmission. However, the projected construction cost rose steeply, from $0.5 billion in 2001, [4] for 168 MW annual average (not peak) generating capacity, to $2.6 billion in 2013 for 183 MW. [5] Some owners of oceanfront property have sponsored preservationist campaigns and lawsuits, [6] while the nearest residents are about five miles away from the site boundaries.

Comparable conventional electricity is readily found in Massachusetts. In Cambridge, for example, the Kendall Square station--opened by Cambridge Light and Power in 1949 burning coal--was converted to combined-cycle natural gas by Mirant in 2000 and is now run by NRG Energy. Kendall Square has a current year-round (not peak) generating capacity of 218 MW. [7] For calendar years 2010, 2011 and 2012, it ran at an average 68 percent of that capacity. [7] Its output was somewhat above the average 61 percent of capacity for all large gas-fired plants in New England. It was selling into a New England bulk electricity market with average wholesale prices per kilowatt-hour of $0.051 in 2010, $0.048 in 2011 and $0.037 in 2012--according to ISO New England. [8] [9]

By the end of 2012, Cape Wind had two major contracts to sell bulk electricity for $0.187 per kWh that it has not been able to fulfill, because its offshore wind farm remains unbuilt. [10] [11] That would be about five times the actual, average wholesale price of bulk electricity in New England for 2012. In September, 2013, Massachusetts and Connecticut state agencies approved long-term agreements by Northeast Utilities, National Grid and other utilities to buy bulk electricity from land-based wind farms run by First Wind, Iberdrola Renewables and Exergy Development, at an average wholesale price of less than $0.080 per kWh. [12] [13]

The total capacity of New England's land-based wind power coming under contract in 2013 was nearly twice what was promised by Cape Wind. The price per kWh is less than half the price from Cape Wind. If Cape Wind had built its offshore wind farm at the cost projected in 2001, it too could sell renewable energy at a fair price. [14]

[1] Background, Energy Management, Inc., 2012, available at

[2] Cape Wind Project History, U.S. Bureau of Ocean Energy Management, 2013, at

[3] New England wind resources, U.S. Department of Energy, 2011, at

[4] Jeffrey Krasner, Offshore wind farm blows into Cape view, Boston Globe, July 28, 2001, p. A1

[5] Ehren Goossens and Christopher Martin, Cape Wind offshore farm lawsuits, Bloomberg News, October 22, 2013, at

[6] Katharine Q. Seelye, Koch brother wages 12-year fight over wind farm, New York Times, October 23, 2013, at

[7] Power plant operating data, Form EIA-923 and related forms, U.S. Energy Information Admimistration, 1970-2012, at

[8] Annual Markets Report, ISO New England, 2011, at

[9] Annual Markets Report, ISO New England, 2012, at

[10] Michael C. Bailey, DPU approves Cape Wind contract with National Grid, The Enterprise (Falmouth, MA), November 26, 2010, at

[11] Erin Ailworth, NStar deal with Cape Wind gets OK, Boston Globe, November 26, 2012, at

[12] Rick Saia, State announces record wind-energy deal, Worcester (MA) Business Journal, September 23, 2013, at

[13] Renewables progress in Northeast, American Wind Energy Association, September 27, 2013, at

[14] Expanded from a version appearing in the Brookline (MA) Tab, October 31, 2013, p. B2

Thursday, October 17, 2013

Coal-fired and oil-fired electricity in New England

In New England today, the only significant use of coal is in a dwindling number of coal-fired electricity generating stations. [1] Just after World War II, almost all electricity and most industrial and space heating in the region were coal-fired, [2] but twenty years later most energy users had migrated to fuel oil, which remained remarkably cheap until the Arab Oil Embargo of 1973. Around that time, much more demanding safety requirements rapidly raised costs of nuclear power plants. Then the Three Mile Island disaster of 1979 chilled remaining interest in nuclear power.

In the 1970s and 1980s, some New England generating units were adapted to use coal again, including ones in the large Salem Harbor plant and the giant Brayton Point plant in Somerset, MA. [3] Residents and business owners located nearby protested the pollution, and over time they were partly successful. After a campaign against the "filthy five" (actually six) most polluting power plants, [4] in 2001 Massachusetts issued fairly stringent new emissions rules for existing power plants, reaching full effects in 2012. [5] A similar but later campaign in Connecticut attacked the "sooty six" plants in that state, [6] resulting in less stringent regulations. [7]

In 2003, Exelon took over the giant Mystic plant in Everett, MA, which had been coal-fired, then oil-fired and equipped for steam-cycle natural gas; it was repowered using combined-cycle natural gas. [8] Exelon slid into bankruptcy because of poor earnings, lost its Massachusetts plants and reacquired them years later. [9] As fuel oil became uneconomic over the next few years, Mirant put the large, mostly oil-fired Canal plant in Sandwich, MA, into hibernation, [10] operating it only at extreme peaks of summer demand. That largely disposed of two of the six most polluting power plants in Massachusetts.

In 2007, NRG Energy proposed to convert the smaller, coal-fired Montaup plant in Somerset to coal gasification, [11] but in 2011 it closed the plant instead. [12] GDF Suez tried buying emission credits to keep running the smaller coal-fired Mt. Tom plant in Hoyoke, MA, but the plan became uneconomic; it announced that Mt. Tom will be delisted in 2016. [13] As agreed under a federal court order, in 2012 Dominion announced it would close the coal-fired Salem Harbor plant by the summer of 2014. [14] It sold the property to Footprint Power, which has received preliminary environmental approval to repower Salem Harbor using combined-cycle natural gas. [15] Five of the six most-polluting plants in Massachusetts were thus being closed, idled or repowered.

With the giant, coal-fired Brayton Point, Dominion tried to buck trends, spending over $1 billion to install cooling towers that replace water drawn from Mt. Hope Bay and pollution controls that substantially reduce emissions of sulfur dioxide, nitrogen oxides and mercury. [16] However, those efforts were financially undercut by declines in the prices of natural gas, and the plant ran at less than 20 percent of capacity after 2011. Dominion sold the plant in 2013 at a heavy loss. In October, 2013, new owner EquiPower announced that Brayton Point would be delisted by the summer of 2017. [17]

That development completed the disposition of all six of the most polluting power plants in Massachusetts. Just to the north, in Bow, New Hampshire, Merrimack became the one large remaining, frequently operated coal-fired power plant in New England. [18} Like Brayton Point, its output has been made uneconomic much of the time by natural gas prices. In May, 2012, Public Service of New Hampshire announced that Merrimack would be closed for all but peak periods of demand in summer and winter. [19] A 2006 New Hampshire law required Merrimack Station to achieve 80 percent reduction in mercury emissions. The company is in disputes over about $422 million spent through 2011 to retrofit the plant with more than the minimum pollution control specified in the law. [20]

Although stronger state regulations made differences in Massachusetts, Connecticut and New Hampshire, shifts in the economics of power generation accelerated changes. Effects on New England power plants in recent years are shown in the following table, which tallies the outputs of large power plants for 2010, 2011 and 2012, compiled by the federal government. [21]

New England power plants with over 1 million megawatt-hours annual outputs

Plant name Location MW * 2010 MWh 2011 MWh 2012 MWh
Brayton Point Somerset, MA 1,100 6,574,727 3,382,751 1,817,889
Merrimack Bow, NH 451 2,667,326 1,982,492 1,185,688
** All large coal plants 1,550 9,242,052 5,365,243 3,003,577
Mystic Everett, MA 1,382 9,093,560 9,234,268 8,466,252
Lake Road Plant Dayville, CT 745 3,721,965 5,279,444 4,536,819
Fore River Weymouth, MA 688 4,247,152 4,781,876 4,048,023
Granite Ridge Londonderry, NH 678 3,241,127 3,839,821 4,824,841
Kleen Energy Midldetown, CT 628 0 2,040,433 4,062,939
R.I. State Johnston, RI 528 3,043,081 3,076,553 2,415,704
Newington En. Newington, NH 525 1,920,852 2,712,026 2,122,028
Milford Power Milford, CT 507 3,395,512 3,920,883 3,651,538
Westbrook Westbrook, ME 506 2,689,175 2,659,935 2,446,083
Maine Indep. Veazie, ME 490 2,657,587 1,775,905 1,243,500
Bellingham Bellingham, MA 475 1,728,914 1,095,126 1,728,447
Bridgeport Bridgeport, CT 454 3,294,276 2,861,180 2,913,274
Manchester St. Providence, RI 447 1,928,019 2,399,970 2,455,440
Ocean State Harrisville, RI 437 1,434,006 1,448,894 1,551,102
Blackstone Blackstone, MA 437 1,746,412 2,087,965 2,098,048
Millennium Charlton, MA 325 2,033,339 2,407,211 2,002,904
Tiverton Power Tiverton, RI 250 1,099,210 1,578,676 1,610,946
Verso Paper Bucksport, ME 250 1,380,078 1,346,241 1,382,575
Berkshire Power Agawam, MA 229 1,002,963 1,060,233 761,901
Kendall Square Cambridge, MA 218 1,485,468 1,053,133 1,346,268
** All large gas plants 10,199 51,142,696 56,659,773 55,668,631
Seabrook-1 Seabrook, NH 1,247 10,910,055 8,362,807 8,189,181
Millstone-3 Waterford, CT 1,233 9,335,738 9,344,084 10,751,630
Millstone-2 Waterford, CT 869 7,414,566 6,583,753 6,326,257
Pilgrim Plymouth, MA 685 5,917,813 5,085,220 5,859,540
Vermont Yankee Vernon, VT 620 4,782,473 4,907,355 4,989,338
** All operating nuclear units 4,655 38,360,645 34,283,219 36,115,946

               * Rated summer output: operating, non-peaking units

In 2008, outputs of New England's remaining coal-fired power plants began to fall, and in 2010 they entered rapid decline. For 2012, the largest ones operated at only 22 percent of capacity on average, with further declines in 2013. Plants powered by combined-cycle natural gas have been filling most of the gaps. However, only some of the gas-fired plants prospered during these years. Granite Ridge, in New Hampshire, and Tiverton, in Rhode Island, saw large increases in outputs. After a terrible explosion a few months before it was to open in 2010, [22] the Kleen Energy plant in Connecticut was repaired and has done well. Half the other large natural gas-fired plants in New England suffered declines in outputs, shown in the table.

Financial pressures have also affected the five remaining nuclear power units in New England. In August, 2013, Entergy threw in the towel with Vermont Yankee, located in Vernon. [23] It will close by the end of 2014. Of the ten New England nuclear power units, Seabrook-2 was abandoned before completion, and four others were previously closed. [24] The Seabrook-1 unit in New Hampshire shows a substantial drop in output. Prolonged subnormal outputs at Seabrook-1 and at Millstone-2 in Connecticut suggest those units might be threatened.

Although several combined-cycle natural gas-fired plants became successful by 2010, during the 20 years before that the owners of such plants suffered through many problems and financial losses. Besides increases in total electricity powered by combined-cycle natural gas, the recent declines in coal-fired and nuclear power have been partly offset by increased outputs of wind and solar power, contributing to reduced total outputs from fossil-fueled and nuclear plants. [25] A problem that will continue to need attention is limited transmission capacity to convey power from generators to customers. [26]

So-called "congestion" on transmission lines has been a chronic factor in low outputs from plants using combined-cycle natural gas that are distant from the major demand centers in Connecticut and Massachusetts. [27] [28] Plants notably affected include Maine Independence in Veazie, Berkshire Power in Agawam, MA, Bellingham Energy, also in Massachusetts, and Ocean State Power in Harrisville, RI. Wind farms in Maine, New Hampshire and Vermont have also encountered transmission restrictions. [29]

Through the bramble of changes, however, one result has remained consistent and strong. In New England, the long era of coal-fired, then oil-fired electricity generation has ended. A surge in natural gas from shale has provided an opportunity to expand renewable power sources, whose costs still remain so high that they operate mainly because of mandates and subsidies. If those costs can be reduced enough before prices of natural gas rise again, then coal and fuel oil will never return to dominate New England electricity.

[1] Lindsey Konkel, Coal's slipping grip: New England, virtually coal-free, leads the way, Environmental Health News, July 1, 2013 at

[2] Utilities promoted efficiency. Unattributed, Edgar steam-electric station in Weymouth, Massachusetts, 1925: a national historic mechanical engineering landmark, American Society of Mechanical Engineers, 1976, at Today the former Edgar, now Fore River plant in Weymouth has been repowered with combined-cycle natural gas.

[3] New England Region Annual Report, U.S. Environmental Protection Agency, 1982, at EPA issued coal-conversion permits in 1979 for Brayton Point, in 1981 for Mt. Tom and in 1982 for Salem Harbor, all in Massachusetts.

[4] Rob Sargent, Cleaning up the filthy five, Environment Massachusetts and Massachusetts Public Interest Research Group, 2007, at

[5] Emission standards for power plants, Statement of reasons and response to comments for 310 CMR 7.29, Massachusetts Department of Environmental Protection, 2001, at

[6] The Connecticut campaign concentrated on mercury and sulfur dioxide emissions. Unattributed, Sooty six power plants, Clean Water Action (CT), 2003, at

[7] Liz Halloran, [Connecticut] takes action on mercury, Hartford Courant, 2003, at

[8] Jon Chesto, Mystic and Fore River plants are about to get yet another owner, Mass. Markets, 2011, at

[9] Unattributed, Boston Generating LCDS (loan-only credit default swap) auction results, CDS Market Information, 2010, at

[10] Chuck Kleekamp, Why oil is on the way out for New England's electric grid, Cape Cod (Hyannis) Times, 2007, at

[11] John Moss, Somerset Power gets OK to begin coal gasification, Wicked Local Somerset (MA) and Herald News, 2008, at

[12] Marc Munroe Dion, Somerset's NRG power plant closing down, Fall River (MA) Herald News, November, 2011, at

[13] Shanna Cleveland, Familiar cautionary tale unfolding at Mt. Tom, Conservation Law Foundation (MA), March 7, 2013, at

[14] U.S. District Court for Massachusetts, Conservation Law v. Dominion, Case cv-11069, Consent decree, February, 2012, available at See 26. Shutdown of Salem Harbor Station.

[15] Tom Dalton, Salem power plant gets tentative state approval, Salem (MA) News, October 9, 2013, at

[16] Jo C. Goode, Financial future of Somerset's Brayton Point is bleak, Fall River (MA) Herald News, March 1, 2013, at

[17] Steve Urbon, Brayton power station to close by 2017, New Bedford (MA) Standard-Times, October 8, 2013, at The event was ignored at the time by large general-interest news media in New England.

[18] A few coal-fired plants, including 530 MW Bridgeport Harbor, remain in standby for extreme summer peaks and emergencies. However, in 2012 Bridgeport Harbor ran an average of only 3 percent of rated capacity. Brian Lockhart, Bridgeport Harbor Station gets permit for five more years, (Bridgeport) Connecticut Post, November, 2012, at

[19] Kathryn Marchocki, Merrimack Station power plant in Bow temporarily shut down, Manchester (NH) Union Leader, May, 2012, at

[20] Bob Sanders, Public Service of New Hampshire turns to New Hampshire Supreme Court in scrubber showdown with state's Public Utilities Commission, New Hampshire Business Review, October 4, 2013, at PSNH installed wet gas desulfurization when it might have gotten by with less expensive sorbent injection and fabric filters.

[21] Power plant operating data, Form EIA-923 and related forms, U.S. Energy Information Admimistration, 1970-2012, at

[22] Unattributed, Kleen Energy natural gas explosion, U.S. Chemical Safety Board, 2010, at

[23] Matthew L. Wald, Entergy will close the Vermont Yankee nuclear power plant, New York Times, August 28, 2013, at

[24] Unattributed, Nuclear power safety in New England, Union of Concerned Scientists (MA), April, 2012, at

[25] Massachusetts state profile and energy estimates, U.S. Energy Information Admimistration, 2013, at See similar data for other New England states.

[26] New England congestion area of concern, in National Electric Transmission Congestion Study, U.S. Department of Energy, 2009, pp. 52-58 at

[27] Unattributed, Transmission congestion cost rising in New England, Electric Light and Power, 2001, at

[28] Brad Kane, Billion-dollar transmission project anticipates power weaknesses, Hartford (CT) Business Review, 2010, at

[29] Diane Cardwell, Intermittent nature of green power is challenge for utilities, New York Times, August 15, 2013, at

Friday, September 28, 2012

Uncertain promises of thorium-fueled nuclear power

Since the 1940s, thorium-fueled nuclear power has been an occasional matter of interest. The late Dr. Glenn Seaborg first isolated the fissile isotope uranium-233 from neutron-irradiated thorium in 1941. He predicted a potential for thorium as a nuclear fuel in 1946. [1] The late Dr. Alvin Weinberg, former director of Oak Ridge National Laboratory, was an early advocate for developing a thorium fuel-cycle.

Despite perennial interest, thorium has remained a research topic and has never been used to fuel commercial power reactors for sustained operation. The early days of nuclear energy were dominated by development of weapons, for which plutonium-239 produced from neutron-irradiated uranium-238 proved more versatile than uranium-233. Because of greater investment and technical knowledge, a uranium-based fuel cycle enhanced by its plutonium byproducts was adopted for military reactors and then for commercial power reactors. It has remained entrenched as the only sustained, commercial nuclear-power fuel-cycle. [2]

There is much speculation and considerable misinformation [3] available on thorium-fueled nuclear power but relatively little solid knowledge, as compared with knowledge of uranium-fueled power. Three main approaches have been actively investigated: pressurized heavy-water reactors, now active mainly in India, molten salt reactors, now active only in China, and high-temperature gas-cooled reactors, such as the former Fort St. Vrain thorium-fueled reactor in the U.S. and former THTR in Germany, now active nowhere at commercial scale. All these approaches have been found to suffer from major, unsolved problems.

Thorium has no long-lived fissile isotope as a minor constituent, comparable to uranium-235. As with production of plutonium, thorium-232 must be transmuted to fissile uranium-233 using neutron irradiation. That can be provided from a uranium-235-enriched or a plutonium fuel-cycle, in a light water-reactor, or from a natural or an enriched uranium fuel-cycle, in a heavy-water reactor. In any case, a substantial "breeding" period is needed to produce enough uranium-233 to contribute substantially to power output.

India appears committed by technology-lock-in to heavy-water reactors, which it began to develop with U.S. and Canadian help in 1956. India surreptitiously used spent fuel from its first CIRUS reactor to obtain plutonium for nuclear weapons. Efficient use of thorium in heavy-water reactors involves high burn-up, at least two to three times the current industry practice with light-water reactors, and extended fuel-rod exposure, ten years or more. Zirconium alloy cladding for fuel rods has not been validated for such conditions, and conventionally manufactured fuel rods probably would not survive. No other technology is currently proven. [4]

China has announced development of a molten-salt reactor, leveraging knowledge from the MSRE project at Oak Ridge, 1961-1969. While avoiding some problems associated with heavy-water reactors, molten-salt reactors used for power generation have other problems. One is heat-transfer piping, which must function reliably for 40 or more years in corrosive, hydrogen-bearing molten salts at very high temperatures and pressures. The MSRE project validated Hastelloy-N piping--but only at lower temperatures and pressures and only for 18 months at full power. Key, unsolved engineering problems for heat-transfer piping in molten-salt reactors are neutron and hydrogen embrittlement and corrosion-promoted stress-cracking. [5]

Of the large, high-temperature thorium-fueled reactors, Fort St. Vrain in Colorado opened first, in 1979. It suffered from leaks and component faulting. After a fire in 1987 and the discovery of pipe cracks in 1988, Public Service of Colorado shut it down. The plant reached full rated power for only two days and averaged less than 15 percent of rated capacity during nine years of commercial operation. THTR in Germany opened in 1985 and closed in 1988, with similar episodes of major problems. It averaged about 40 percent of capacity. Neither effort solved problems of fuel reprocessing, which is made especially difficult by chemically inert coatings on fuel elements of high-temperature reactors. [6]

Most thorium-fueled reactors, including all those noted, involve fuel reprocessing to extract uranium-233 and remove neutron poisons and other fission products. All reprocessing is complicated by highly penetrating gamma radiation from nuclear decay products of uranium-232, which is always being released in thorium-fueled reactors from neutron reactions with uranium-233 and its precursor, proactinium-233. Among the decay products are polonium-212 and thallium-208, which both emit high-energy gammas at about 2.6 MeV. [7]

Typical of thorium-fueled reactors, the one at Fort St. Vrain was enclosed in 15-foot-thick concrete. A smaller but more expensive alternative shield employs depleted uranium. Adequate radiation shields for bulk quantities of irradiated thorium, for its uranium-produced decay products and for radioactive waste from thorium-fueled reactors are too heavy to transport by standard rail, highway or air services. [8] Only relatively small quantities could be packaged for shipment in those ways.

Rationales for developing thorium fuel-cycles have usually focused on four claims: (1) more plentiful, less hazardous fuel at lower costs, (2) intrinsic resistance to diversion for nuclear weapons, (3) smaller amounts of nuclear waste and (4) more stable operation. [2] None of those claims stand up robustly to review. Potential thorium-fueled power reactors would present hazards and limitations similar to those of uranium-fueled power reactors, differing mainly in details.

As to claim (1), more plentiful, less hazardous fuel at lower costs: While the geologic abundance of thorium is greater than that of uranium, much of that thorium is at low concentrations that are impractical to mine. Thorium-bearing substances extracted from rare-earth mines can be more toxic than substances from uranium mines. [9] They have been associated with high incidences of severe mining-induced diseases. [10]

As to claim (2), intrinsic resistance to diversion for nuclear weapons: Uranium-233, which can be extracted from neutron-irradiated thorium by a chemical process, is a more powerful nuclear explosive than bomb-grade uranium, highly enriched in uranium-235. [11] Its claimed resistance to diversion comes from contamination at parts-per-million levels by uranium-232, with highly penetrating radiation from decay products. However, that would not necessarily deter terrorists, who often mount suicide missions. [12]

As to claim (3), smaller amounts of nuclear waste: While the fission daughter and actinide products in thorium-fuel waste are substantially less and shorter-lived than those in uranium-fuel waste, for the same yield in energy, [7] requiring isolation for perhaps ten thousand years instead of a million or more years, the shorter-term components of thorium-fuel waste, with deeply penetrating gamma radiation that remains hazardous for at least a thousand years, are much more difficult to handle safely. [13]

As to claim (4), more stable operation: While the neutron cross-section of uranium-233 is more uniform than those of other fissile isotopes, helping to stabilize performance, [7] in practice thorium-fueled reactors have been plagued with leaks, component faulting, power excursions, fires and materials failures. The practical history of thorium-fueled reactors--as contrasted with theory--recalls the long learning curves with uranium-fueled reactors. While no major disaster has occurred yet with thorium-fueled reactors, the experiences with them so far amount to only a tiny fraction of experiences with uranium-fueled reactors.

The notion of a permanently enclosed thorium-fueled reactor, operating continuously for 30 or more years, has been proposed. [14] It has not yet been proven practical from either a scientific or an engineering perspective. The gradual build-up of neutron poisons from fission would be a key challenge for long-term operation, and the unresolved engineering issues of long-term embrittlement and corrosion are at least as challenging for such an approach as for other types of thorium-fueled reactors.

Cost of nuclear fuel has long been a prominent argument for developing thorium fuel-cycles but is clearly a red herring. [15] Capital costs of reactors have dominated for more than 30 years, and fuel costs have sometimes been considered negligible. Because of requirements for extremely heavy shielding, fully robotic operations inside shielding, and fuel reprocessing, thorium-fueled reactors could be more expensive than uranium-fueled reactors of equal capacity, so costs of electricity from them might be higher. [16]

Until a shortage of uranium emerges, at least decades from now, there will not be any strong financial or environmental reason for industrially developed countries to pursue thorium fuel-cycles. Even with such a shortage developing, reprocessing spent uranium fuel to obtain plutonium fuel might be less costly and no more hazardous. The interests of power generation will be better served by long-term research investigating the unsolved engineering problems of thorium-fueled reactors.

Some 60 years ago, the late U.S. Admiral Hyman Rickover, an early leader in military applications of nuclear reactors, summarized what he already saw as jejune enthusiasms for nuclear technologies--comparing what he called "academic" reactors with practical ones. [17] Abbreviated here:

Simple Complicated
Easy to buildHard to build
Not availableAvailable now

Most enthusiasts for thorium-fueled reactor technologies are academics, researchers or gadflies. Few have practical, daily working experience designing, developing, operating, maintaining, testing, regulating or certifying nuclear reactors or power systems of any kind. History has shown that such backgrounds fail to yield dependable estimates for energy technologies, so that any estimates from such sources ought to be discounted.

[1] U.S. Secretary of State, Report on the international control of atomic energy (the Acheson-Lilienthal Report), March, 1946, available at Unattributed, United Press, Third nuclear source bared, Tuscaloosa (AL) News, October 21, 1946, available at

[2] F. Sokolov, K. Fukuda and H.P. Nawada, Thorium fuel cycle: Potential benefits and challenges, International Atomic Energy Agency, 2005, at

[3] Unattributed, quoting Prof. Reza Hashemi-Nezhad, Thorium reactor, Thorium Enthusiasts, 2011, at

[4] Paul R. Kasten, Review of the Radkowsky thorium reactor concept, Science and Global Security 7:237-269, 1998, available at

[5] Kun Chen, Thorium-fueled molten salt reactor research in Shanghai Institute of Applied Physics, Department of Nuclear Engineering, University of California at Berkeley, August 6, 2012, announcement at

[6] Tony Kindelspire, Colorado nuclear plant at Fort St. Vrain had short, troubled life, Longmont (CO) Weekly, March 28, 2011, at

[7] Michel Lung and Otto Gremm, Perspectives of the thorium fuel cycle, Nuclear Engineering and Design 180:133-146, 1998, available at

[8] L.H. Brooks, R.G. Wymer and A.L. Lotts, Progress in the thorium and urainium-233 reprocessing, Oak Ridge National Laboratory, 1974, at

[9] Comparing thorium-232 with natural uranium, in Radionuclides (occupational limits), U.S. Nuclear Regulatory Commission, 2012, at

[10] C├ęcile Bontron, En Chine, les terres rares tuent des villages, Le Monde (France), July 19, 2012, at

[11] Rene G. Sanchez, Minimum critical mass: Analytical studies, Los Alamos National Laboratory, 1993, available at

[12] Cameron Reed, A thorium future?, American Scientist 98(5):364, 2010, at

[13] Kevin Hesketh and Andrew Worrall, The thorium fuel cycle, UK National Nuclear Laboratory, 2011, at

[14] Gabriele Rennie, Self-contained, portable reactor, Lawrence Livermore National Laboratory, 2004, at

[15] Robert Hargraves and Ralph Moir, Liquid-fuel nuclear reactors, Forum on Physics and Society, American Physical Society, January, 2011, at

[16] Arjun Makhijani and Michele Boyd, Thorium fuel: No panacea for nuclear power, Physicians for Social Responsibility, 2009, at

[17] Hyman G. Rickover, Letter to the Joint Committee on Atomic Energy, June 5, 1953, quoted in Nuclear and Radiation Studies Board, Internationalization of the Nuclear Fuel Cycle: Goals, Strategies and Challenges, National Academies Press, 2009, p. 60, at

Sunday, February 20, 2011

Cause of Gulf blowout remains only partly known

Unlike the Final Report of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, the Chief Counsel's Report, released February 17, 2011, provides some technical analysis of the disaster, along with new information. [1] The most striking new information discloses that, after cementing, the Macondo well reservoir of oil and gas under very high pressure was left with a potential channel into the well's production casing through an open float collar. It confirms that blowout oil, gas and sand flowed upward inside the casing rather than through the annulus around the production casing, as most early descriptions had estimated.

The Chief Counsel's Report describes some steps performed after the July 15, 2010, actions that ended the flows of oil and gas. BP personnel, using Development Driller II, recovered an upper section of the production casing, the attached casing hanger and samples of annulus contents [p. 43]. The annulus samples had low hydrocarbons, and the outside of the casing hanger showed no erosion [Fig. 4.1.4], indicating that blowout flow did not occur in the annulus between the production casing and outer casing. The inside of the casing hanger showed severe erosion, indicating that abrasive blowout flow traveled inside the casing--evidence that appears conclusive.

Unless there was a downhole rupture in the production casing, blowout flow ran through the casing shoe. Evidence cited in the Chief Counsel's Report shows that check valves in a float collar above the shoe probably failed to activate and interrupt back-flow [pp. 88-90]. A mud flow rate was never measured that would have been enough to displace the auto-fill tube propping the check valves open. Pressures applied while trying to displace the auto-fill tube may instead have broken some element of the casing string. The check valves would not have fully sealed out oil and gas flow, but they would have reinforced the shoe track cement barrier, had they been closed.

Although the Chief Counsel's Report does not describe pressure balances, displacing about 3,300 feet of drilling mud with seawater, following the cementing operation, left over 1,200 psi of pressure difference on shoe track cement. Highly foamed cements may achieve less than 2,000 psi compressive strength, and the foamed cement used for the Macondo well may have been unstable. Three out of four laboratory tests performed by Halliburton and nine out of nine tests later performed by Chevron, as requested by the National Commission, showed instability, resulting in porous structures with low strength. A collapse of shoe track cement, unrestrained by check valves, could have allowed oil and gas to enter the production casing.

The Chief Counsel's Report has been criticized for preparation by lawyers rather than engineers. However, the National Commission and its staff were both headed by lawyers. No working engineers served on its staff. Its assistant staff director was an economist. Its "senior scientist" had been communications network manager. The commission did not form an advisory team of engineers and scientists. Its access to practical and scientific knowledge and assessment of deepwater drilling was very limited. Out of its 85 named consultants, only one is a petroleum drilling engineer, currently working as an independent. One is a petroleum chemist. One is a former Interior Department oil and gas well regulator. Three are petroleum engineering professors, all from the same university. At least 30 of the named consultants are lawyers, and at least 40 are policy analysts.

Despite an order from President Obama stating it would be "focused on...environmental and safety precautions," the National Commission focused on determining responsibility for the disaster. About half of the commission's Final Report describes background and events of the disaster, detailing who did what and when. [2] Those issues are critical when determining comparative negligence for settling damage claims, but they are peripheral to a technical analysis of how the Macondo well blowout occurred. The Chief Counsel's Report amplifies the emphasis on assigning blame, providing an essentially forensic analysis of events, illustrated by a company that serves trial lawyers by preparing exhibits. It is mainly fortuitous that forensic analysis resulted in public release of new technical information.

The Chief Counsel's Report lodges more responsibility for the disaster than was previously clear with haphazard cement preparation and testing by Halliburton [pp. 121-123]. It gives no explanation for a discrepancy between laboratory test conditions and downhole conditions. The report shows a plastic test cell for foamed cement, with brass fittings [Fig. 4.4.3], probably rated for no more than 1,000 psi. Downhole pressures were around 13,000 psi, substantially compressing foam bubbles and resulting in cement densities higher than specified and higher than measured by laboratory tests. The report cites several obstructions by Halliburton to investigations: providing irrelevant references to industry standards [p. 120], refusing to provide company documents [pp. 118, 120 and 121], refusing to describe test methods [p. 119], refusing to provide materials for third-party testing [p. 119] and refusing to provide testimony by company personnel [pp. 118, 120, 121 and 122].

The main likely impact of the National Commission's work will be to help defend whatever penalties the federal government levies against BP, Transocean and/or Halliburton for the disaster. Much of the Chief Counsel's Report could populate a trial brief, for use in a lawsuit challenging the penalties. A major opportunity was lost to examine the cause of the blowout while evidence was fresh.

[1] National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, Chief Counsel's Report, February, 2011, available from .

[2] National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, Final Report, January, 2011, available from .

Wednesday, October 6, 2010

Recapturing carbon dioxide from the air

Would-be practitioners of "climate engineering," once called "geoengineering," are stumbling across a minefield of problems. Early investigations assumed the key issue would be finding ways to block sunlight from reaching the lower atmosphere. [1] [2] Reducing solar inputs could retard and possibly reverse warming trends. However, more recent investigations, using weather modeling and weather records after large volcanic eruptions, show that blocking sunlight reduces rainfall. [3] Land areas already at low rainfall could become deserts.

Discovery of major hazards from blocking sunlight sparked renewed interest in recapturing carbon dioxide already released by human activity, a difficult prospect that would face three key challenges:
(1) a very large amount of carbon dioxide to be recaptured
(2) low concentration of carbon dioxide in the atmosphere
(3) lack of storage capacity for gaseous carbon dioxide

The total carbon dioxide released to the atmosphere from human activities has been about 800 billion tons since the early 1800s. [4] [5] [6] A large majority came from burning coal. Since 2000, the total has been increasing an average of 2.0 percent per year. [4] Those observations set practical requirements for any proposals to recapture carbon dioxide. A realistic approach must extract and permanently store several hundred billion tons.

Carbon dioxide penetrates some solid materials, including many rubbers and plastics, more than other gases do, making possible separation by a solid, semi-permeable membrane. Other potential membrane separations depend on molecular size differences and porous membranes. [7] Commercial membrane systems for removing carbon dioxide from pressurized gas streams are available. As applied to recapture from the atmosphere, key limitations are the need to compress very large air volumes, the need for a cascade of separation stages because of the low carbon dioxide concentration, and the low permeabilities and flow kinetics of known membranes. Recapture systems using membranes would be enormous, energy-intensive and costly; practical systems have not yet been demonstrated.

Absorption of carbon dioxide by strong alkali is a well known separation technique, widely applied in equipment that maintains sealed environments. It has been demonstrated for recovery of carbon dioxide at atmospheric concentrations, and a closed-cycle process is known. [8] The last process stage is calcining lime at very high temperatures, as used to make cement. It yields concentrated carbon dioxide but takes large amounts of energy, about 2 MWh per ton of carbon dioxide. [9] To recapture the atmospheric inventory of carbon dioxide released by human activities would require a total of about 2 billion GWh. Supplying that energy from fossil fuels would work at cross-purposes. Supplying it from nuclear power would take 5,000 large, 1 GWe reactors about 50 years. Costs would approach US$100 trillion for energy, [10] plus costs of chemical processing steps.

Those and other methods of recapturing carbon dioxide would be useless alone, because there would be no place to put all the carbon dioxide. Even when compressed to a liquid, carbon dioxide occupies about six times the volume of the same amount of carbon as coal. In all the world's mines and wells combined, there is no space for more than a small fraction of the carbon dioxide that human activity has released. Most mines and wells have rock fissures that allow carbon dioxide to seep back to the atmosphere. Permanent storage requires combining carbon dioxide into a stable, solid mineral. While not difficult, most mineralization processes start with a substrate that was made from a carbonate, by driving off carbon dioxide. Obviously that will not do.

Rock formations containing substantial fractions of calcium and magnesium oxides readily combine with carbon dioxide, making carbonates. The formations useful as substrates are geologically young, because when weathered alkaline earth oxides have been consumed. Suitable formations are uncommon and variable in reactivity. [11] Rock formations containing substantial calcium silicate as wollastonite or magnesium silicate as forsterite are also potential substrates. [12] [13] Suitable formations are more common than those containing alkaline earth oxides but are also variable in reactivity. Reaction rates are slower than those of alkaline earth oxides, taking many hours to reach only modest yields.

Silicate carbonation is enhanced when rock substrates are pretreated at very high temperatures and ground to very fine dust. About three-fourths of silicate will then carbonate with a half-hour exposure. The process is energy-intensive; costs have been estimated at about US$70 per ton of carbon dioxide. [14] An unanswered question is emission of carbon dioxide from high-temperature pretreatment. Using the process to store the inventory of carbon dioxide released by human activities, costs would approach US$50 trillion.

Known technologies can recapture carbon dioxide from the air and store it permanently. However, potential costs of applying them to recapture all carbon dioxide released by human activities probably approach US$200 trillion. With total emissions of carbon dioxide increasing at two percent per year, incremental costs to recapture from the atmosphere the current carbon dioxide emissions probably approach US$4 trillion per year. Such an amount could be viewed as remediation of potential environmental damage. It could be raised by taxing carbon dioxide emissions at about US$900 per ton of carbon. That is far more than US$1 to US$50 tax rates factoring in recent political controversies.

Taxing carbon dioxide emissions enough to pay for their recapture from the air and their permanent storage, using those known technologies, would probably raise U.S. retail gasoline prices from about US$3 to about US$6 per gallon. It would probably raise wholesale U.S. prices for coal-fired electricity from about US$.05 to about US$.60 per KWh. Ending further carbon dioxide additions and recapturing all the releases from human activity, carried out over 50 years, would probably cost about 12 percent of the gross world product, estimated from the current level. Less expensive technologies may eventually be developed. For example, carbon dioxide capture from power-plant flue gases is being tested and will probably be less costly. Catalysts that reduce energy consumption have been conjectured, but so far no economically effective catalyst has been found. Substantial improvements are not likely to be found quickly in such longstanding, well known areas of technology.

[1] James E. Hansen and Andrew A. Lacis, Sun and dust versus greenhouse gases, Nature 346:713-719, August 23, 1990.

[2] Edward M. Teller, Lowell Wood and Roderick Hyde, Prospects for physics-based modulation of global change, UCR Livermore National Laboratory Report UCRL-JC-128715, August 15, 1997, available at

[3] Gabriele C. Hegerl and Susan Solomon, Risks of climate engineering, Science 325:955-956, August 21, 2009.

[4] Pieter Tans, Mauna Loa carbon dioxide records, U.S. National Oceanic and Atmospheric Administration, Earth Systems Research Laboratory, 2010, available through

[5] D.M. Etheridge, L.P. Steele, R.L. Langenfelds, R.J. Francey, J-M. Barnola and V.I. Morgan, Historical CO2 record derived from ice cores, Australia Commonwealth Scientific and Industrial Research Organization, Division of Atmospheric Research, 1998, available at

[6] Kevin E. Trenberth and Lesley Smith, The mass of the atmosphere, Journal of Climate 18(6):864-875, 2005.

[7] Colin A. Scholes, Sandra E. Kentish and Geoff W. Stevens, Carbon dioxide separation through polymeric membrane systems for flue gas applications, Recent Patents on Chemical Engineering 1:52-66, 2008, available at

[8] Gregory V. Lowry, Joshuah Stolaroff and David Keith, CO2 extraction from ambient air using alkali-metal hydroxide solutions, American Chemical Society, Division of Fuel Chemistry Proceedings 49(1):362-363, 2004, available at

[9] Wicky Moffat and M.R.W. Walmsley, Understanding lime calcination kinetics for energy cost reduction, Australian Pulp and Paper Industry Technical Association Proceedings 59:487-494, 2005, available at

[10] Craig A. Severance, Business risks and costs of new nuclear power, Electricity Journal 22(4):112-120, 2009, draft version available at

[11] N. Koukouzas, V. Gemeni and H.J. Ziock, Sequestration of CO2 in magnesium silicates, International Journal of Mineral Processing 93:179-186, 2009, available at

[12] Sebastian Teir, Sanni Eloneva and Ron Zevenhoven, Production of precipitated calcium carbonate from calcium silicates and carbon dioxide, Energy Conversion and Management 46(18):2954-2979, 2005.

[13] George D. Guthrie, Jr., J. William Carey, Deborah Bergfeld, Darrin Byler, Steve Chipera, Hans-Joachim Ziock and Klaus Lackner, Geochemical aspects of the carbonation of magnesium silicates, Los Alamos National Laboratory, National Conference on Carbon Sequestration, Washington D.C., May 14-17, 2001, available at

[14] W.K. O'Connor, D C. Dahlin, G. E. Rush, C. L. Dahlin and W. K. Collins, Carbon dioxide sequestration by direct mineral carbonation, Minerals and Metallurgical Processing 19(2):95-101, 2002.

Monday, May 31, 2010

Disaster by design, the Deepwater Horizon blowout

The April 20, 2010, blowout of an oil and gas well in the Gulf of Mexico, south of the Louisiana coast, created the worst environmental crisis for the United States since the massive dust storms of Great Depression years. Both occurred because of mismanaged natural resources, but otherwise they greatly differed. The Dust Bowl was a result of hundreds of thousands of farmers tilling marginal land without crop rotation, leaving soils vulnerable to severe drought. [1] The well blowout came from a highly concentrated activity, involving a few hundred people attempting to access a high-pressure reservoir, drilling from the high-technology Deepwater Horizon platform in about one mile water depth without adequate margins of safety. [2]

Both disasters might have been prevented by adequate government regulation. In the 1920s, when it would have mattered most, there was hardly any government presence in agriculture other than the field stations set up by states and the federal government to assist with, but not to regulate, crop management. The federal government and many states were in the grip of deeply conservative, even reactionary administrations, firmly opposed to government regulations. Their closest approach had been the federal Pure Food and Drug Act of 1906, passed during the Theodore Roosevelt administration and largely aimed at unsanitary meat packing. [3]

The 2010 Gulf of Mexico well blowout came 41 years after a similar disaster, the 1969 well blowout in Santa Barbara Channel, a few miles off the California coast. Shocked by gross pollution of the Pacific coastline, Congress swiftly passed the National Environmental Policy Act of 1969. [4] It formed a basis of regulation that had become institutionalized in missions of government agencies by the time of the 2010 disaster. Yet like the Pure Food and Drug Act, the National Environmental Policy Act proved susceptible to manipulation and evasion. Regulations created and enforced under it failed to prevent a catastrophe, even though when one occurred the federal government was a progressive administration committed to environmental protection.

The major cause of the 2010 Gulf of Mexico well blowout was quickly assessed, only several days after public release of a well schematic. [5] Dr. Arthur Berman, a Houston petroleum geologist, showed that unsafe design for the Macondo 1 well had left unrestrained areas of bare drillhole, above a high-pressure oil and gas reservoir, connected to the sea floor through an annulus between metal casings. [6] His analysis of the final cementing operation was soon confirmed through a public release of data from the well owner. [7] What had yet to be released at that point were documents showing the faulty design as submitted to and approved by the Minerals Management Service (MMS), an agency of the U.S. Department of the Interior set up to supervise offshore oil and gas operations.

As of 2010, MMS had managed federal leases of outer continental shelf lands and supervised their operations for 28 years, under authority of the Federal Oil & Gas Royalty Management Act of 1982. Many responsibilities were created by the National Environmental Policy Act, which requires environmental impact statements for such activities. During several years before the 2010 blowout, MMS had been repeatedly troubled by mismanagement and corruption. In 1998 and subsequent years major blunders occurred. Faulty contracts allowed leaseholders to avoid many billions of dollars in oil and gas royalties, disclosed by the New York Times February 15, 2006. Although the problems were discovered within MMS in 2004, MMS took no action to correct them until the public disclosure, according to the inspector general for the Interior Department. [8]

MMS had long paid cash bonuses to employees for expediting work related to oil and gas development, a key element in creating a corrupt job environment. [9] In 2008 MMS was found by its inspector general to host what he called a "culture of ethical failure." Abuses cited included patronage, inside dealing, kickbacks, revolving door employment and misuse of federal property--extending over a period of at least four years. As a result of the investigation several employees were reassigned, some quit, and at least one was convicted of a felony. [10]

In 2010 the Macondo 1 well blowout in the Gulf of Mexico led reporters to discover that its lease and many other projects in the Gulf of Mexico had been exempted by MMS from environmental reviews. As a result, companies had not been required to prepare and document emergency responses. The Deepwater Horizon platform lacked a fail-safe blowout preventer, and the Macondo 1 well owner lacked salvage equipment. In budget documents MMS had claimed efficiency from using "categorical exclusion" for a "streamlined" form of environmental review. [11] What the agency did was generate a prepackaged deal for companies. A pro-forma environmental review was prepared by and approved within the agency. After companies paid for leases, they were automatically exempted from reviews, and their applications to conduct operations were, quite literally, rubber-stamped.

The Macondo 1 well was mainly regulated under a "multisale EIS" (Environmental Impact Statement) covering 11 Gulf of Mexico leases, prepared by MMS staff in 2007. Its risk analysis finds that over 40 years, "there is a 69-86 percent chance of one or more spills [of] 1,000 barrels [or more] occurring" [page 4-231]. The "multisale EIS" finds substantial risk that a spill of 1,000 or more barrels will pollute many miles of coastline [page 4-234]. It also indicates that pollution can persist for many years [page 4-238]. Thus MMS knew that a disaster in this area was likely and that consequences would probably be widespread and long-lasting. [12]

The exploration plan filed with MMS to drill the Macondo 1 well described a worst-case oil discharge as 300,000 barrels per day, giving a number without saying "barrels." However, MMS instructions for such plans show daily volume in barrels. In less than 12 days such a discharge would exceed the world's worst ocean oil disaster, the 1979 Ixtoc 1 well blowout, also in the Gulf of Mexico. MMS knew the Macondo 1 well had the potential to cause a catastrophe, yet it gave the plan routine approval, letting the owner go ahead without documented procedures for responding to such a radical emergency. [13]

Immediately after the Macondo 1 well blowout the U.S. Coast Guard failed to mount coordinated rescue, control and salvage operations. Years of focusing on terrorism rather than natural and industrial disasters had left it unprepared for such an event. MMS permitted relief wells without requiring any more safety preparation than it had required for the well that blew out. The U.S. National Oceanic and Atmospheric Administration distributed a hasty assessment of the crude oil discharge rate that was soon shown to be scientifically faulty, and then it refused to release data and methods. The U.S. Environmental Protection Agency issued a hasty decision endorsing untested use of large quantities of dispersants, when environmental evidence showed that similar chemicals had led to long term environmental damage. [14]

Despite contributions to the problems, the Coast Guard and MMS were put in charge of an initial investigation. [15] Outrage over crude oil reaching beaches and marshland and protests over a compromised investigation led to a rapid series of actions: reorganization plans for the MMS, resignation of the MMS director, suspension of all offshore drilling in deep water, new drilling permits and offshore oil and gas leasing, and appointment of a Presidential investigating commission. [16] The U.S. Geological Survey prepared an estimate of the discharge, putting it at 12 to 19 thousand barrels (500 to 800 thousand gallons) of crude oil per day. [17]

Through May, 2010, the Macondo 1 well owner tried a series of maneuvers to trap or plug the oil discharge, without much success. Similar maneuvers had been tried with previous subsea well blowouts, notably the 1979 135F platform, Ixtoc 1 well blowout in the Bay of Campeche off Mexico. Despite the same kinds of attempts, that blowout flowed for 290 days, discharging an estimated 120-200 million gallons of crude oil into the southern Gulf of Mexico, the world's greatest accidental ocean oil disaster so far. [18]

Sometimes such maneuvers succeeded, as with the 1977 Bravo platform, well B14 blowout in the North Sea off Norway. But when reservoir pressure was high and consequent gas flow was strong they failed, as they recently did with the Montara platform, well H1 blowout in the Timor Sea off northwest Australia, which flowed for 70 days. [19] Company and U.S. officials lied, saying the Macondo 1 well blowout was "unprecedented," and success of the maneuvers would be unpredictable. All that was really unprecedented was water depth. There was otherwise substantial experience with similar blowouts, but there was an unprepared industry and a similarly unprepared government. [20]

The blowout preventer (BOP) configured for the Deepwater Horizon platform failed; otherwise the blowout would have been prevented. That failure was also by design, as the U.S. Minerals Management Service has been made fully aware. [21] Current-generation blowout preventers depend on shearing blind rams (SBRs) to cut drill pipe, so as to allow floating platforms like Deepwater Horizon to seal a well, disconnect from it and move away. Current-generation SBRs cannot cut through pipe joints, the enlarged, hardened sections of steel that join segments of drill pipe. About ten percent of the lineal extent of drill pipe is joint. However, BOP rams do not close with a snap. Their hydraulic systems are regulated, and they take most of a minute to close. During that time the force of a blowout is pushing drill pipe upward. As an SBR nears the point of full closure, inevitably an upward-moving pipe joint lodges in it. After trapping the pipe joint, the SBR then cannot cut it.

U.S. government says it will revise offshore oil and gas regulations and agency organizations. However, few if any people working in U.S. government actually know what to do. In the aftermath of the 1969 Santa Barbara disaster laws were written, but then they were often ignored. If the aftermath of the 1979 Bay of Campeche catastrophe, industry developed a slightly improved blowout preventer (in use at the Macondo 1 well), and U.S. government prepared a few internal studies. [22] As a result, MMS knew that existing offshore oil and gas well development was unsafe and knew that neither government nor industry was prepared for a major emergency, but it failed to generate plans, conduct relevant research, arrange for improved equipment and supplies, perform engineering evaluations or coordinate such efforts with companies or other agencies. Decades of opportunity were squandered, leading to another catastrophe.

[1] R. Douglas Hurt, The Dust Bowl: An Agricultural and Social History, Burnham, 1981.

[2] Tom Fowler, Experts have their doubts on well's design, Houston Chronicle, May 26, 2010, available at Ian Urbina, Documents show early worries about safety of rig, New York Times, May 30, 2010, available at

[3] James Harvey Young, Pure Food: Securing the Federal Food and Drugs Act of 1906, Princeton University Press, 1989.

[4] Matthew J. Lindstrom and Zachary A. Smith, The National Environmental Policy Act: Judicial Misconstruction, Legislative Indifference and Executive Neglect, Texas A&M University Press, 2002.

[5] U.S. House Energy and Commerce Committee, Testimony of Timothy Probert, May 12, 2010, available at

[6] Arthur E. Berman, What caused the Deepwater Horizon disaster? The Oil Drum, May 21, 2010, available at

[7] U.S. House Energy and Commerce Committee, BP presentation: Deepwater Horizon interim incident investigation, May 24, 2010, available at (19 MB), page 14.

[8] Edmund L. Andrews, U.S. has royalty plan to give windfall to oil companies, New York Times, February 15, 2006, available at Edmund L. Andrews, Oil lease chief knew of error, report asserts, New York Times, January 18, 2007, available at Inspector General, Interior Department, Lack of price thresholds in Gulf of Mexico oil and gas leases, January 2007, available at

[9] Edmund L. Andrews, As profits soar, companies pay U.S. less for gas rights, New York Times, January 24, 2006, available at William Yardley, Arctic drilling proposal advanced amid concern, New York Times, May 20, 2010, available at Juliet Eilperin, U.S. agency overseeing oil drilling ignored warnings of risks, Washington Post, May 25, 2010, available at

[10] Charlie Savage, Sex, drug use and graft cited in Interior Department, New York Times, September 10, 2008, available at Inspector General, Interior Department, OIG investigations of MMS employees, Re: Gregory W. Smith, MMS Oil Marketing Group and Federal Business Solutions contracts, September 9, 2008, available at

[11] Juliet Eilperin, U.S. exempted BP's Gulf of Mexico drilling from environmental impact study, Washington Post, May 5, 2010, available at Minerals Management Service, Budget justification and performance information, fiscal year 2010, available at, page 85.

[12] Minerals Management Service, Gulf of Mexico Oil and Gas Lease Sales, 2007-2012, Nos. 204, 205, 206, 207, 208, 210, 213, 215, 216, 218 and 222, Final Environmental Assessment, Volumes 1 and 2, April 2007, available at and

[13] Minerals Management Service, Initial exploration plan, lease OCS-G32306, block 252 Mississippi Canyon area, March 10, 2009, available at (rubber-stamped NOTED-SCHEXNALIDRE). Minerals Management Service, Contents of plan (Appendix A NTL No. 2006-G14 Guidance for MMS-137 OCS Plan Information Form, August 2003), available at

[14] Scott Berinato, Coast Guard, DHS and Deepwater: same ship, different day, CSO Magazine, May 1, 2004, available at Susan Saulny, Finger-pointing, but few answers at hearings on drilling, New York Times, May 12, 2010, available at Ian Urbina, U.S. said to allow drilling without needed permits, New York Times, May 14, 2010, available at Justin Gillis, Scientists fault U.S. response in assessing Gulf oil spill, New York Times, May 20, 2010, available at Lynn Yaris, Caution required for Gulf oil spill clean-up, Lawrence Berkeley National Laboratory, May 4, 2010, available at Jason Dearen and Ray Henry, Associated Press, Chemicals used to fight Gulf of Mexico oil spill a trade-off, New Orleans Times-Picayune, May 5, 2010, available at

[15] The White House, President Barack Obama, Administration-wide response to BP spill, May 3, 2010, available at "Secretary Napolitano and Secretary Salazar signed an order establishing the next steps for a joint investigation that is currently underway into the causes of the explosion of the drilling rig Deepwater Horizon in the Gulf of Mexico. The U.S. Coast Guard (USCG) and the Minerals Management Service (MMS) share jurisdiction for the investigation." Matthew L. Wald, Independent inquiry into oil spill is urged, New York Times, May 15, 2010, available at

[16] John M. Broder and Shaila Dewan, White House to create panel to study Gulf oil spill, New York Times, May 18, 2010, available at Juliet Eilperin and Scott Wilson, Birnbaum 'took fall' after MMS played catch-up after lapses in ethics, oversight, Washington Post, May 29, 2010 available at Debbi Wilgoren and Michael D. Shear, Obama to ban new deepwater oil wells, cancel lease sales off Virginia and Alaska coasts, Washington Post, May 27, 2010, available at Juliet Eilperin and David A. Fahrenthold, Graham, Reilly to lead investigation of oil spill, Washington Post, May 22, 2010, available at The White House, President Barack Obama, Executive order, National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. May 22, 2010, available at

[17] Tom Zeller, Jr., Estimates suggest spill is biggest in U.S. history, New York Times, May 28, 2010, available at Flow Rate Technical Group, U.S. Geological Survey, Flow Rate Group provides preliminary best estimate of oil flowing from BP oil well, May 27, 2010, available at

[18] Energy Resources Co., Ixtoc oil spill assessment, final report, U.S. Bureau of Land Management, March, 1982, available at March Schliefstein, BP's "top kill" process fails, forced officials to attempt yet another strategy, New Orleans Times-Picayune, May 30, 2010, available at Jeffrey Kluger, As top kill drags on, BP's credibility problems grow, Time, May 28, 2010, available at,8599,1992627,00.html.

[19] David Prestipino, Cause of western Australia oil spill revealed, Western Australia Today, November 10, 2009, available at Montara Commission of Inquiry, Australia Ministry for Resources and Energy, multiple documents available at

[20] Steven Mufson and Michael D. Shear, Pressure grows for action by BP, Washington Post, May 1, 2010, available at Debbi Wilgoren, Joel Achenbach and Anne E. Kornblut, Gulf Coast oil spill may take months to contain, officials say, Washington Post, May 3, 2010, available at

[21] West Engineering Services, Shear ram capabilities study, Minerals Management Service, September, 2004, available at

[22] PCCI Marine and Environmental Engineering, Oil spill containment, remote sensing and tracking for deepwater blowouts, Minerals Management Service, August, 1999, available at West Engineering Services, Mini shear study, Minerals Management Service, December, 2002, available at West Engineering Services, Evaluation of secondary intervention methods in well control, Minerals Management Service, March, 2003, available at