All Electric Trucks. Probably not going to happen. Ever. Why not?

Posted on April 14, 2015 by

There are “forms of transport that cannot be electrified — heavy-duty trucks and planes… Even if the electricity problem can be solved, it won’t address the needs of planes, trucks, ships and some industrial heating that cannot be electrified” (Long).

The heavy-duty trucks that do the essential work of civilization, such as agricultural tractors and harvesters, Class 7 and 8 long-distance freight trucks, the trucks used in mining, logging,  and so on are too big and heavy to run on batteries.

The battery packs or fuel cells would take up so much space there would be little, if any, room for cargo. The batteries are so heavy that the truck would barely move, and it might take a day or more to charge the battery. Tractors and other off-road vehicles would be stranded if they ran out of power, and likely to be far from a power outlet.

FedEx is concerned that charging just 10 EVs during “off peak” hours will increase the “off peak” load to “peak” or higher level. That could result in additional infrastructure costs (Sondhi).

Medium-duty class 3-6 All-electric delivery vans

All of these vans run on lithium-ion batteries. That’s okay for the short and medium term, but long-term there isn’t enough lithium even with recycling.

Many companies bought medium-duty delivery trucks starting in 2011, such as Frito Lay and Staples, and the National Renewable Energy Lab has been testing their performance.

But just like electric cars, delivery trucks are being held back by poor performing, high cost batteries.  They need, far more than autos, a very powerful, revolutionary battery.  And I’m not holding my breath, since battery development has been very slow the past 200 years (see Who Killed the Electric Car? for details).

Price of an electric Van

These were the only prices I could find after a lot of searching:

  • Kansas City’s municipal government wanted a bucket truck. A diesel version cost $132,000. The city bought the Smith All-electric truck, which cost $330,000, almost $200,000 more, because a federal grant covered the difference (Lockridge)
  • $800 per kWh (Lyden, Calstart)
  • $175,000 for the e-truck. A diesel equivalent would cost $65,000. A 60 kWh battery is $54,000, an 80 kWh $70,000 (Calstart)
  • The basic electric van is $75,000, and the battery ranges from $25,000 to $75,000 (Motavalli).
  • Smith Electric trucks cost up to $90,000 each. Frito-lay has bought them at a reduced price with subsidies from both the federal government and New York state. A comparable diesel truck costs $60,000 (Vyas)
  • Each truck cost $100,000 to $150,000 with federal subsidies of about $57,000 and also many other additional grants and tax breaks
  • Mike O’Connell, senior director of fleet operations at Frito-Lay, which has a fleet of 280 Smith medium-duty electric trucks, said in an interview: “In the short term, buying electric trucks without subsidies is extremely challenging…” (Motavalli)
  • Calstart estimated that without the $40,000 HVIP incentive it would take 12 to 36 years to payback an electric truck. But the Smith electric battery warranty was a 5-year limited, full replacement within 3 years. With batteries costing $25-$75,000 one or more replacements means the price might never be paid back

The incentives are huge

Common EV incentives include tax credits, rebates, vouchers, grants and unrestricted access to high occupancy commuter lanes on major roadways. Here are some federal level incentives in the US:

  • Tax credit from $2500-$7500 (Qualified plug-in electric drive motor vehicle tax credit)
  • EPA DERA funds up to 25% of the total cost of the vehicle
  • Clean Cities: up to 50% total cost of the vehicle
  • Congestion Mitigation & Air Quality Funds (CMAQ): federal money dispersed to states where these funds are given to localities based on air quality and varies state to state

Each state also offers subsidies.

  • New York has 5 different programs, including one that pays up to $60,000 per vehicle.
  • The Oregon Department of Transportation is launching a $4 million new electric truck buyer incentive program. The Commercial Electric Truck Incentive Program will be offered in the form of $20,000 vouchers per eligible, all-electric vehicle over 10,000 pounds, regardless of manufacturer.

The battery and electric truck makers were heavily subsidized, but are bankrupt or in financial trouble

  • A123 made batteries for Smith Electric, but went bankrupt in March 2012 despite a $263 million dollar grant (Cohan).
  • Smith has never made a profit since despite a federal $32 million dollar grant that paid for 44 to 67% of each trucks’ cost. Smith went bankrupt late 2013. Net losses were $17.5 million 2009, $30.3 million 2010, $52.5 million 2011, and $27.3 million through June 30, 2012 with only 439 of 500 vehicles delivered and $29,150,672 government dollars reimbursed, a $66,402 taxpayer subsidy per vehicle (FS, Chesser)
  • Navistar Inc received $39.4 million for 950 electric delivery trucks but is in financial trouble and discontuned its eStar electric van in March 2013 (based on technology from bankrupt Modec)

Smith was already a failed company based in the United Kingdom within the Tanfield Group. Smith-U.S. established itself in Kansas City in January 2009, following a precipitous drop in Tanfield’s U.K. stock value in mid-2008. Financial analysts became troubled because claims the company made about matters such as vehicle orders could not be verified. The company was accused of exercising poor disclosure standards and weak financial controls, according to the London Telegraph. Tanfield’s cash evaporation led the company to lose 97 percent of its value in 2008, prompted inquiries by the London Stock Exchange and by the U.K. Accountancy and Actuarial Discipline Board.

Charging time

Typical charge duration for the FCCC MT E-Cell was measured between 12 and 14 hours to achieve the bulk of the charge and over 17 hours to achieve a full charge. Total charge duration for the Navistar eStar was estimated between 12 and 13 hours (calstart).

References

Calstart. 2013. Battery electric parcel delivery truck testing and demonstration. Prepared by California Hybrid for California Energy Commission.

Cassidy, W. B. Apr 16, 2014   Smith Electric Vehicles Halts Truck Production. www.joc.com

Chesser, P. July 8, 2013. Bottomless Subsidies Needed to Keep DOE Electric Truck Project Alive. National Legal and Policy Center.

Chesser, P. April 15, 2014. Energy Dept. Revives Stimulus Loans as Another Electric Vehicle Comany Stalls. Bankruptcy Law Review.

Cohan, P. June 12, 2012. Is A123 electric battery a waste of $263 million in government funds. Forbes.

FS. May 16, 2013. Fuel Smarts. Fuel Smarts Navistar Sells RV Business, Drops eStar Van as Part of Its Turnaround Plan. trucking.info

Lockridge, D.June 28, 2012. What’s up with electric trucks? Truckinginfo.com

Long, J. October 26, 2011. Piecemeal cuts won’t add up to radical reductions. Nature 478.

Lyden, S. 2014. The State of All-electric trucks in the U.S. medium-duty market. zerotruck.com

Motavalli, J. November 16, 2011. Smith Electric to build trucks in the Bronx. New York Times.

Sondhi, K.. Feb 20, 2013. Talking Freight Webinar. FedEx

Vyas, A. D., et al. February 2013. Potential for Energy Efficiency Improvement Beyond the Light-Duty-Vehicle Sector. Prepared for the U.S. Department of Energy by Argonne National Laboratory.

Posted in Batteries, Lithium-ion, Trucks | Tagged , , , , , , , | 5 Comments

GAO on why ethanol, and other non-drop in fuels, face pipeline & installation at service station challenges

Posted on April 9, 2015 by

[The challenges that ethanol faces in being put into new or modified pipelines and added to gas stations are issues faced by all alternative fuels (methanol, CNG, LNG, DME, diesohol, CTL, hydrogen, and so on) in a transition from gasoline and diesel to “Something Else”. 

Since natural gas, coal-to-liquids, and other fuels are nonrenewable and also at or near their peak, and biofuels don’t scale up (and have a negative EROI), it’s unlikely that these problems will need to be solved. But it’s still interesting to understand why E85 is in so few stations.  Alice Friedemann www.energyskeptic.com]

USGAO. June 2011. Challenges to the transportation, sale, and use of intermediate ethanol blends. United States Government Accountability Office. 57 pages

The U.S. transportation sector is almost entirely dependent on petroleum products refined from crude oil—primarily gasoline and diesel fuels. In 2009, this sector consumed the equivalent of about 14 million barrels of oil per day, or over 70% of total U.S. consumption of petroleum products. To meet the demand for crude oil and petroleum products, the nation imported, on a net basis, about 52 percent of the petroleum products consumed in 2009.

Ethanol is the most commonly produced biofuel in the United States. In 2010, the nation produced 13.2 billion gallons of ethanol, the vast majority of which came from corn. Most U.S. corn is grown in the Midwest, and ethanol is generally produced in relatively small biorefineries near corn producing areas. Unlike petroleum products, which are primarily transported to wholesale terminals by pipelines, ethanol is transported to wholesale terminals by a combination of rail, tanker truck, and barge. At the terminals, most ethanol is currently blended as an additive in gasoline to make fuel blends containing up to 10 percent ethanol (called E10). Finally, the blended fuel is transported via tanker truck to retail fueling outlets.

In a 2009 report, we identified fuel-blending limits as a challenge to expanded ethanol consumption.  We stated that the nation may soon reach a “blend wall”-the upper limit to the total amount of ethanol that can be blended into U.S. gasoline, given current constraints. At the time, the blend wall existed partly because under EPA’s implementation of the Clean Air Act, fuels containing more than 10% ethanol were prohibited from being introduced for use with the vast majority of U.S. automobiles.

One option to address the blend wall is to use “intermediate” ethanol blends such as E15 or E20 (generally 15% or 20% ethanol).

The EPA, in January 2011, allowed E15 for use in model years 2001 through 2006 automobiles. The EPA did not allow E15 for use in older automobiles or non-road engines (such as lawn mowers, chainsaws, and boats), motorcycles, or heavy-duty gasoline engines. EPA cited insufficient test data to support the use of E15 in these engines, as well as engineering concerns that older vehicles and non-road engines may not maintain compliance with emission standards if operated on E15.  In light of the potential use of intermediate ethanol blends, you asked us to review their potential effects. Our objectives were to (1) determine the challenges, if any, associated with transporting additional volumes of ethanol to wholesale markets to meet RFS requirements; (2) determine the challenges, if any, associated with selling intermediate ethanol blends at the retail level; and (3) examine research by federal agencies into the effects of intermediate ethanol blends on the nation’s automobiles and non-road engines.

As shown in figure 2, the infrastructure used to transport petroleum fuels from refineries to wholesale terminals in the United States is different from that used to transport ethanol. Petroleum-based fuel is primarily transported from refineries to terminals by pipeline.  In contrast, ethanol is transported to terminals via a combination of rail cars, tanker trucks, and barges.  According to DOE estimates, there are approximately 1,050 terminals in the United States that handle gasoline and other petroleum products. At the terminals, most ethanol is currently blended as an additive in gasoline to make E10 fuel blends. A relatively small volume is also blended into a blend of between 70% to 83% ethanol (E85) and the remainder gasoline. E85 has a more limited market, primarily in the upper Midwest, and can only be used in flexible-fuel vehicles, which are vehicles that have been manufactured or modified to accept it.  After blending, the fuel is moved to retail fueling locations in tanker trucks.

There are approximately 159,000 retail fueling outlets in the United States, according to 2010 industry data. This total included more than 115,000 convenience stores, which sold the vast majority of all the fuel purchased in the United States. Consumers in the United States use retail fueling locations to fuel hundreds of millions of automobiles and non-road products with gasoline engines. According to DOT data, Americans owned or operated almost 256 million automobiles, trucks, and other highway vehicles in 2008, while about 91% of all households owned at least 1 automobile the same year, according to U.S. Census data. Americans also owned and operated over 400 million products with non-road engines in 2009, according to one industry association estimate. According to EPA documentation, non-road engines are typically more basic in their engine design and control than engines and emissions control systems used in automobiles, and commonly have carbureted fuel systems  and air cooling, whereby extra fuel is used in combustion to help control combustion and exhaust temperatures. According to representatives from industry associations for non-road engines, most of the small non-road engines manufactured today rely on older technologies and designs to keep retail costs low, and all of the small non-road engines currently being produced are designed to perform successfully on fuel blends up to E10. According to industry representatives, while it is possible to design small non-road engines to run on a broad range of fuels, such designs would not be cost effective and could add hundreds of dollars to the price.

Fuel economy. According to DOE’s report for Project V1, ethanol has about 67 percent of the energy density of gasoline on a volumetric basis. As a result, automobiles running on intermediate ethanol blends exhibited a loss in fuel economy commensurate with the energy density of the fuel. When compared to using gasoline containing no ethanol, the average reduction in fuel economy was 3.7 percent using E10, 5.3 percent using E15, and 7.7 percent using E20.

Large investments in transportation infrastructure may be needed to meet 2022 projected consumption, according to EPA documentation. One option for doing so may be to construct a dedicated ethanol pipeline, but this option presents significant challenges.

Railroads hauled more than 220,000 rail carloads of ethanol in 2008 (the most recent year for which data are available)-which was about 0.7 percent of all the rail carloads and about 1% of the total rail tonnage transported that year in the United States, according to data from the Association of American Railroads. Similarly, knowledgeable DOT officials and industry representatives said there is sufficient capacity in the short term to transport additional volumes of corn ethanol via trucks, which transport about 29% of corn ethanol to wholesale markets, and barges, which transport roughly 5%, to meet RFS requirements.

If overall ethanol production increases enough to fully meet the RFS over the long term, one option to transport it to wholesale markets would be through a dedicated ethanol pipeline. Over many decades, the United States has established very efficient networks of pipelines that move large volumes of petroleum-based fuels from production or import centers on the Gulf Coast and in the Northeast to distribution terminals along the coasts. However, the existing networks of petroleum pipelines are not well suited for the transport of billions of gallons of ethanol. Specifically, as shown in figure 4, ethanol is generally produced in the Midwest and needs to be shipped to the coasts, flowing roughly in the opposite direction of petroleum-based fuels. The location of renewable fuel production plants (such as biorefineries) is often dictated by the need to be close to the source of the raw materials and not by proximity to centers of fuel demand or existing petroleum pipelines.

Existing petroleum pipelines can be used to ship ethanol in some areas of the country. For example, in December 2008, the U.S. pipeline operator Kinder Morgan began transporting commercial batches of ethanol along with gasoline shipments in its 110-mile Central Florida Pipeline from Tampa to Orlando. Kinder Morgan invested approximately $10 million to modify its Central Florida Pipeline for ethanol shipments, which included chemically cleaning the pipeline, replacing equipment that was incompatible with ethanol, and expanding storage capacity at its Orlando terminal.

However, pipeline owners would face the same technical challenges and costs that Kinder Morgan representatives reported facing, including the following:

  • Compatibility. Ethanol can dissolve dirt, rust, or hydrocarbon residues in a petroleum pipeline and degrade the quality of the fuel being shipped. It can also damage critical nonmetallic components, including gaskets and seals, which can cause leaks. In order for existing pipelines to transport ethanol, pipeline operators would need to chemically remove residues and replace any components that are not compatible with ethanol. According to DOT officials, the results from two research projects sponsored by that agency have identified specific actions that must be taken on a wide variety of nonmetallic components commonly utilized by the pipeline industry.
  • Stress corrosion cracking. Tensile stress and a corrosive environment can combine to crack steel. The presence of ethanol increases the likelihood of this in petroleum pipelines. Over the past 2 decades, approximately 24 failures due to stress corrosion cracking have occurred in ethanol tanks and in production-facility piping having steel grades similar to those of petroleum pipelines. According to DOT officials, the results from nine research projects sponsored by that agency have targeted these challenges and produced guidelines and procedures to prevent or mitigate stress corrosion cracking. As a result, pipelines can safely transport ethanol after implementing the identified measures, according to DOT officials.
  • Attraction of water. Ethanol attracts water. If even small amounts of water mix with gasoline-ethanol blends, the resulting mixture cannot be used as a fuel or easily separated into its constituents. The only options are additional refining or disposal.

Some groups have proposed the construction of a new pipeline dedicated to the transportation of ethanol. For example, in February 2008, Magellan Midstream Partners, L.P. (Magellan) and Buckeye Partners, L.P. (Buckeye) proposed building a new pipeline from the Midwest to the East Coast.

The federal government has studied the feasibility of building a pipeline similar to the one proposed by Magellan. The report identified a number of significant challenges to building a dedicated ethanol pipeline, including the following:

  • Construction costs. Using recent trends in and generally accepted industry estimates for pipeline construction costs, DOE estimated that an ethanol pipeline from the Midwest to the East Coast could cost about $4.5 million per mile. While DOE assumed that the construction of 1,700 miles of pipeline would cost more than $3 billion, it did not model total project costs beyond $4.25 billion in the report.
  • Higher transportation rates. Based on the assumed demand for ethanol in the East Coast service area and the estimated cost of construction, DOE estimated the ethanol pipeline would need to charge an average tariff of 28 cents per gallon, substantially more than the current average rate of 19 cents per gallon, for transporting ethanol using rail, barge, and truck along the same transportation corridor.
  • Lack of eminent domain authority. DOE estimated that siting a new ethanol pipeline of any significant length will likely require federal eminent domain authority, which currently does not exist for ethanol pipelines.

Non-Drop-in fuels face huge barriers in being added to service stations as shown by E85

According to several industry associations representing various groups, such as fuel retailers and refiners, many fuel retailers may face significant costs and risks in selling intermediate ethanol blends. According to these industry representatives, retailers make very little money selling fuel-for example, the national average profit from selling gasoline last year was 9 cents per gallon, according to industry data. Most retailers make most of their profit selling merchandise such as food, beverages, and tobacco products, according to these industry representatives, and gasoline is sold below cost in some markets to attract customers to buy more profitable goods. As a result, according to several industry representatives, most retailers do not upgrade their fuel-storage and -dispensing equipment without a significant market opportunity.

For these fuel retailers, the prospect of selling intermediate ethanol blends presents several potential challenges. The first is cost. Some fuel retailers may have to spend hundreds of thousands of dollars to upgrade their equipment to store and dispense intermediate ethanol blends, for the following reasons:

  • Under current OSHA regulations, most fuel retailers will need to replace at least one dispenser system to sell intermediate ethanol blends. According to estimates from EPA and several industry associations, installing a new dispenser system compatible with intermediate ethanol blends will cost over $20,000.40 According to some industry association representatives, a typical fuel retailer has four dispensers and, therefore, would face costs exceeding $80,000 to upgrade an entire retail facility.
  • According to EPA and industry estimates, the total cost of installing a new single-tank UST system compatible with intermediate ethanol blends is more than $100,000. In addition to the high costs, some industry association representatives stated that fuel retailers who have recently installed new UST systems may be particularly reluctant to replace them, especially since UST warranties can last for several decades, and the useful life of these systems can be even longer.

A second potential challenge consists of financial and logistical limitations on the types of fuel a retailer may be able to sell. According to representatives from several industry associations, most retail fueling locations have only two UST systems, and many fuel retailers cannot install additional UST systems due to space constraints, permitting obstacles, or cost.42 Currently, fuel retailers with two UST systems can sell 3 grades of gasoline: regular, midgrade, and premium. To accomplish this, they typically use one of their tanks to store regular gasoline and the other for premium, both of which are pre-blended with up to 10% ethanol. They then use their dispensing equipment to blend fuel from both tanks into midgrade gasoline. If fuel retailers with two UST systems want to sell intermediate ethanol blends, however, they may face certain limitations. For example, fuel retailers with two UST systems who want to sell regular, mid-grade, and premium gasoline could use the tanks to store regular and premium grades of an intermediate blend, such as E15. However, since EPA has only allowed E15 for use in model year 2001 and newer automobiles, these retailers would not be able to sell fuel to consumers for use in older automobiles and non-road engines.

Posted in Automobiles, Biofuels, Fuel Distribution, Pipeline | Tagged , , , , , | Comments Off on GAO on why ethanol, and other non-drop in fuels, face pipeline & installation at service station challenges

Biofuels do not scale up enough to power society

Posted on April 9, 2015 by

Richard, T. August 23, 2010. Challenges in scaling up biofuels infrastructure. Science. (329)  

Below are excerpts from this paper.  Look at the impossible scale of biomass required:

  • 150 EJ/year = 15 billion metric tons of plant biomass = 200 billion cubic meters of bales, wood chips, pellets, etc
  • Agricultural products: Rice, wheat, soy, corn, etc: 2 billion tons, 2.75 billion cubic meters
  • Coal: 6.2 billion cubic meters, Oil: 5.7 billion cubic meters
  • Therefore, the biofuel biomass required would be much larger than all energy and agricultural commodities now.

Rapid growth in demand for lignocellulosic bioenergy will require major changes in supply chain infrastructure. Even with densification and preprocessing, transport volumes by mid-century are likely to exceed the combined capacity of current agricultural and energy supply chains, including grain, petroleum, and coal.

The next few decades will require massive growth of the bioenergy industry to address societal demands to reduce net carbon emissions. This is particularly true for liquid transportation fuels, where other renewable alternatives to biofuels appear decades away, especially for truck, marine, and aviation fuels. But even for electricity and power, the growth potential of other renewables and nuclear power appears limited by high cost, technology barriers, and/or resource constraints.

With both agronomic and societal concerns about further increases in the use of grains and oilseeds for biofuels, almost all of this increased bioenergy will likely come from lignocellulosic feedstocks: dedicated energy crops, crop residues, forests and organic wastes. These materials have considerably lower bulk densities than grains, resulting in significant logistical challenges.

The transportation fraction of the energy required to grow and deliver energy crops to a biorefinery is only 3 to 5% for grains and oilseeds, but increases to 7 to 26% for lignocellulosic crops such as switchgrass, miscanthus, and other forages and crop residues (5–7).

To reach the IEA 2050 target of 150 EJ/year, primary energy from biomass would require 15 billion metric tonnes [i.e., megagrams (Mg)] of biomass annually, assuming 60% conversion efficiency (4, 7) and a biomass energy content of 17 MJ/kg dry matter (8). A typical dry bulk density of grasses and crop residues is about 70 kg/m3 when harvested, so without compaction the shipping volume of these 15 billion metric tonnes would require more than 200 billion cubic meters (bcm). At baled grass and woodchip densities of 150 and 225 kg/m3 (8–10), this transport volume would be 100 or 60 bcm, respectively (Fig. 1). Using reported energy densities of pellets, pyrolysis oil, and torrefied pellets these densified products would require 28, 17, and 15 bcm of transport capacity, respectively.

For agricultural commodities, the sum of rice, wheat, soybeans, maize, and other coarse grains and oilseeds will approach 2 billion tons in 2010, with a total volume of 2.75 bcm (11).

Current global volumes of energy commodities are somewhat larger, with 6.2 bcm of coal and 5.7 bcm of oil transported in 2008 (12).

The combination of expected growth in energy demand and the lower density of biomass imply that by 2050, biomass transport volumes will be greater than the current capacity of the entire energy and agricultural commodity infrastructure.

a major stress on the transportation infrastructure, especially in rural regions around the world. If managed poorly, this additional traffic could degrade rural roadways and increase safety concerns.

DELIVERY

The transportation and logistics at the back end of a biofuel refinery must also be addressed. Ethanol is incompatible with the current fuel pipeline distribution system due to its corrosivity and its azeotrope with water, which can lead to pipe or tank failure and fuel contamination, respectively. That 200 ML/year biofuel plant would require 16 to 20 tanker trucks or railcars per day to move the fuel to market, increasing both traffic and costs

These fuel distribution challenges are helping drive the interest in “drop-in” fuels that would be compatible with both the existing fuel distribution infrastructure as well as the vehicle fleet. Several such advanced biofuels are nearing commercialization, including butanol, Fischer-Tropsch fuels, and other bio-based gasoline and diesel equivalents. But regardless of the fuel product, massive investments in new pipe, rail, and highway infrastructure are needed to move those fuels from a new biorefinery network dispersed across the landscape.

Economic analysis of both preprocessing and conversion systems highlights the importance of year-round operations, as it is difficult to amortize capital costs for facilities that are only used for a few months of the year (6, 13). However, many biomass feedstocks have optimal harvest periods that may run for only a few weeks. There are likely other seasons during which harvesting should not occur due to weather or various ecosystem constraints. Livestock farmers have been facing a similar problem supplying forages to their 24/7/365 milk- and meat-producing animals for over a thousand years, and have developed effective wet (<70% dry matter) and dry 80% dry matter) storage systems for grasses and crop residues (Fig. 3). Dry biomass is preferred for pellets, torrefaction, and downstream thermochemical processing, where the presence of water would reduce overall energy efficiency

The size and efficiency of bioenergy conversion facilities will determine how far these huge volumes of biomass and biofuel will need to travel, and thus transportation’s contribution to the energy, economic, and environmental impacts of biomass use. At a community scale, biomass energy can be converted in combined heat and power (CHP) systems producing 1 to 30 MW at efficiencies of 80% or more (4). At 80% efficiency, 30 MW of useful energy would require 150 Mg/day of biomass, or rough overwhelm, the economies of scale associated with advanced conversion technologies.

In contrast, cellulosic biofuel refineries are expected to achieve economies of scale at 200 to 1000 megaliters (ML) per year (7, 13, 14). Above this size range, the marginal cost of biomass transport can become greater than the marginal savings of larger biorefinery equipment on a per-unit basis (13). At the lower end of this range, feedstock needs would be equivalent to those of a 300-MW power plant, and a single biorefinery would require 50 trucks to deliver the 1600 Mg of biomass consumed each day. At the high end of this range, with 250 trucks per day, one truck would be unloading every 5 min around the clock.

Both feedstock supply and fuel distribution logistics will influence the optimal size required for these biorefineries to achieve economies of scale

Brazilian sugar cane factories operate as a plantation system, with monocultures of sugar cane surrounding each refinery. Most sugar cane production is within 100 km of Sao Paulo, Brazil’s largest city and industrial base, so the markets for biofuels are relatively close. In the United States, by contrast, midwestern corn ethanol must travel by road and rail more than 1000 km to markets on the east and west coasts.

Although capital costs, oil stability, corrosivity, and deoxygenation remain challenges for pyrolysis (6), downstream conversion possibilities include gasification and blending with petroleum in conventional refineries. Pyrolysis also produces a biochar coproduct that can be used to improve soil quality, serving as a carrier for returning recovered nutrients to the soil. Interestingly, the economies of scale for most of these densification and preprocessing technologies plateau in the range of 20 to 80 MW thermal equivalent (6).

ENDNOTE: other scaling articles

CEC 2015. An assessment of biomass resources in California 2013. California Energy Commission, U.C. Davis. CEC-500-11-020

Total technical energy generation potential of California’s biomass is 34.5 TWh per year, 11.5% of California’s 300 TWh electrical energy demand.   Nowhere in this document is the energy return on invested, such as how much diesel fuel energy will be used by heavy-duty trucks to harvest, transport, build the low-efficiency biomass thermal plant (just  20%) or biogas refinery, the gasoline burned by truck drivers to and from work, and all the other fossil energy inputs over the life-cycle of this project.  Nor did the document mention how much biomass is already being used by the biofuel industry, for animal feed and bedding, mulch, compost, biochemicals, and other industries.

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  42. I thank C. Taylor, K. Ruamsook, E. Thomchick, and C. Hinrichs for providing helpful comments and sources.
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Oil shortages: Transportation needs to go back to high inventories, not just-in-time delivery

Posted on April 8, 2015 by

Huge amounts of fuel are wasted as trucks arrive half full with just the needed parts at factories and warehouses and return empty. As oil shocks strike, fuel will be less available.  Large inventories will help by cushioning businesses from long and unpredictable delays in deliveries.  Large inventories of food (nonperishable especially) will also help prevent social unrest and famine.

Let’s go back to “push” logistics and high inventories:

logistics push pull more inventory

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A third of Nuclear Reactors are going to die of old age in the next 10-20 years

Posted on April 3, 2015 by

Number of operating reactors by age (as of June 26, 2007). Age is determined by first grid connection. Source: IAEA power reactor information system

70% of reactors are over 25 years old, 23% are over 35 years old, so within 10 to 20 years about a third will have to be decommissioned, far more than the 63 under construction.  Some are bound to fail as they age, making the future of nuclear power even less certain.

And where will the waste go?

The U.S. depends on nuclear power plants built with designs from the 1950s that have known flaws.

Worse yet, the U.S. has 23 reactors with the same design as those in Fukushima Japan that melted down after the 2011 earthquake and tsunami.

In both old and more recent plants, the components face a daily load of high temperatures, pressures, vibration and bombarding neutrons, which can render thick steel walls so brittle that cracks form at welds and joints (Biello).

Biello, D. Feb 7, 2015. Sorry State: U.S.’s Nuclear Reactor Fleet Dwindles. Scientific American.

 

Number of operating reactors by age (as of June 26, 2007). Age is determined by first grid connection. Source: IAEA power reactor information system

Posted in ! PEAK EVERYTHING, Nuclear Power Energy | Tagged , | 7 Comments

EROI negative for Coal-to-Liquids (CTL) at Shenuha Direct Coal Liquefaction plant

Posted on March 29, 2015 by

Kong, Z. et al. 23 January 2015. EROI Analysis for Direct Coal Liquefaction without and with CCS: The Case of the Shenhua DCL Project in China. Energies 8(2): 786-807.

Shenhua Direct Coal Liquefaction (DCL) Plant

Shenhua Direct Coal Liquefaction (DCL) Plant

 

Many nations see coal-to-liquids (CTL) as a way to avoid becoming dependent on oil producing nations and even essential for national security.  All eyes are on China, which has spent billions developing CTL technology, though policies there are somewhat schizophrenic. The central government is trying to put the brakes on CTL because of water scarcity, human health, CO2 emissions, other environmental issues, and business risks. But local governments in coal-rich areas are eager to build CTL plants for jobs and economic growth.

This paper calculates the EROI of making coal-to-liquids (CTL) at the only commercial-level Direct Coal Liquefaction (DCL) plant in the world, built by China’s Shenhua Group.

The other method of making CTL is indirect coal liquefaction (ICL), also known as Fischer-Tropsch (F-T). There are ICL plants in China (and South Africa), but they are not as efficient as the DCL plant looked at in this study.

But not all that efficient! The EROI results are negative when internal energy is included, .68-.81 (no by-product), and still negative even with by-product: .75-.90.

Internal energy certainly should be included. This is the coal energy used to liquefy coal. Some argue it shouldn’t count because society didn’t “pay for it”, the energy didn’t come from somewhere else, such as electricity generated outside of the CTL plant. But that’s rubbish. The energy to liquefy CTL has to come from somewhere, or you won’t have any liquefied coal, and diverting some of the coal to burn for the energy to make it also means less liquefied coal output.

Using by-product to push EROI out of negative territory is a tricky way to avoid the whole point of EROI: what is the ENERGY returned. Trucks and locomotives won’t move an inch burning CTL byproducts like benzene and xylene, unless perhaps they explode from trying such an experiment.

At best, if by-product is included and internal energy ignored, the EROI is 4.13 to 6.14. But that’s without carbon capture and storage, which would lower the EROI to 3.2-4.4. By 2020 the CTL EROI will be lower still as the EROI of coal production declines from 27:1 in 2010 to 24:1 in China (Hu).

The authors could find very few peer-reviewed estimates for CTL EROI.  The few that exist are for the ICL process, because DCL has been experimental until now.  Cleveland gives ranges of EROI both below and above the break-even EROI of 1 depending on assumptions regarding location, resource quality, and technology characterization. Two other ICL estimates range from 3.5 to 4:1 but don’t subtract carbon capture EROI.

The authors conclude: “In Section 3, we determined the EROI value of coal liquefaction to be less than 1…so any increases in production will not meaningfully affect the net energy available to society and accordingly, CTL should not currently be developed on a large scale in China.  A CTL project may generate a financial profit, but from this EROI analysis, the quantity of net energy delivered to society by CTL production is extremely low, perhaps even negative, which may be due to high investments in infrastructure and low conversion efficiency…. therefore, the Chinese government and investors should be prudent when developing it”.  They also say that given the dependency of China on imported oil, research should continue, and that perhaps innovations in technology will improve the EROI.

Environmental Effects (Greenpeace)

Water extraction. The Project extracts water through subterranean pipes from Haolebaoji, a region 100 kilometers away, with low precipitation rates 3 but relatively rich in groundwater. There, the Project relies on 22 wells dug well 300 meters deep to extract groundwater. As a result, groundwater levels in the region have dropped significantly 4 co mpared with 10 years ago. Also,the surface area of nearby Subeinaor Lake has decreased by 62% from 2004.

Water Pollution. The Project illicitly discharges industrial waste water into the surrounding environment at three locations.

As a result of pressure from Greenpeace and other organizations, Shenhua announced in 2013 that they were going to reduce the Project’s per ton water intensity of oil production to 6 m³ , compared to 10 m³

Statistics

This plant can produce 25,000 barrels of oil products per day from 6,000 tonnes of dry coal, or about 9 million barrels/year, and cost roughly $1.5 billion dollars. It takes 36,646.9 tonnes of raw coal to produce 10,000 tonnes of DCL oil and by-products.

References

Greenpeace. April 8, 2014. Key developments since Thirsty Coal 2: Shenhua’s Water Grab. Greenpeace.org

Hu, Y. et al. 2013. Energy return on investment (EROI) of China’s conventional fossil fuels: Historical and future trends. Energy, 54:352-364

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Kurt Cobb Cheap oil, complexity and counter-intuitive conclusions

Posted on March 23, 2015 by

Kurt Cobb. March 22, 2015.   Cheap oil, complexity and counterintuitive conclusions. Resource Insights.

It is a staple of oil industry apologists to say that the recent swift decline in the price of oil is indicative of long-term abundance. This kind of logic is leading American car buyers to turn once again to less fuel efficient automobiles–trading efficiency for size essentially–as short-term developments are extrapolated far into the future.

The success of such argumentation depends on a disability in the audience reading it. The audience must have amnesia about the dramatic developments in the oil markets in the last 15 years which saw prices reach all-times highs in 2008 and then after recovering from post-crash lows linger at the highest average daily price ever from 2011 through most of 2014. And, that audience must have myopia about the future. It is an audience whose attention has narrowed to the present which becomes the only reference point for decision-making. History is bunk, and what is, always will be.

The alternative narrative is much more subtle and complex. As I’ve written before, the chief intellectual challenge of our age is that we live in complex systems, but we do not understand complexity. How can cheap oil be a harbinger of future supply problems in the oil market? Here’s where complexity, history and subtle thinking all have to combine at just the right intellectual temperature to reveal the answer.

Cheerleaders for cheap oil only seem to consider the salutary effects of low-priced oil on the broader economy and skip mentioning the deleterious effects of high-priced oil. They seem to ignore the possibility that the previously high price of oil actually caused the economy to slow and thereby dampened demand–which then led to a huge price decline.

If this is the primary driver behind cheaper oil, then cheaper oil in this case is not a sign of abundance, but of lack of affordability for many of the world’s people. It suggests that there is an oil price speed limit now in effect for the world economy above which it cannot grow for long.

If the ultimate significance of high-oil-prices-turned-to-low-oil-prices is a worldwide recession, then we will have a better idea whether such a price speed limit applies. The past does not offer much hope that it’s different this time. Economist James Hamilton has documented that 10 of the last 11 recessions were preceded by a significant rise in oil prices.

This time around we haven’t had a spike in prices, but rather persistently high prices above $100 a barrel for more than three and a half years prior to the oil plunge. This produced a different kind of pressure on the economy, but pressure nevertheless.

The Chinese economy is slowing down. The European economy is stagnant. Russia is or shortly will be in outright recession. Canada is teetering on the edge of recession and it seems Australia might go there, too. Japan continues its stagnant ways despite record monetary stimulus.

Cheap oil in its own way may be presaging, not a period of abundance, but one of austerity. That austerity has already hit the oil industry itself as it undergoes deep cuts in personnel and exploration and development spending.

The big question now is: Can oil be both abundant and cheap in the long run? Or are we living through the first period in history in which oil can only be “abundant” at high prices?

Of course, it’s only abundant if you can afford it. So, demand for oil would likely remain subdued under a high-price scenario suggesting that we’ve burned through the cheap stuff and must find alternative low-cost energy sources or possibly suffer ever worsening recessions until we do. We can only hope that the 2008 crash is not a prelude to even deeper recessions ahead.

This would also suggest that we are perilously close to a ceiling on oil production mediated by a combination of affordability, geology and the limits of technology. The risk is plain, and yet, it is faith that sustains the optimists in a rock-solid belief that the future will be like past–until, of course, it isn’t.

But faith isn’t a good basis for energy policy, even if it seems to have worked in the past. An intellectually honest consideration of all the complexities of our energy situation reveals risks to adequate oil supplies worldwide from here on out that we can only ignore at our peril.

Kurt Cobb is an author, speaker, and columnist focusing on energy and the environment. He is a regular contributor to the Energy Voices section of The Christian Science Monitor and author of the peak-oil-themed novel Prelude. In addition, he has written columns for the Paris-based science news site Scitizen, and his work has been featured on Energy Bulletin (now Resilience.org), The Oil Drum, OilPrice.com, Econ Matters, Peak Oil Review, 321energy, Common Dreams, Le Monde Diplomatique and many other sites. He maintains a blog called Resource Insights and can be contacted at kurtcobb2001@yahoo.com.

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All About Coal

Posted on March 20, 2015 by

Preface. Below are my notes, statistics, and so on about coal from many publications.

Way more fun to look at and understand the coal used to make steel (a different kind is used to generate electricity) is this site:

2022 Understanding Global Demand for Steelmaking Coal:

https://www.visualcapitalist.com/understanding-global-demand-for-steelmaking-coal/

United States Coal Productioncoal mining regions USA

 

 

Coal Production Map by region (2011 million short tons, % change from 2010). Source: Quarterly Coal Report, October- December 2011 (April 2012), U.S. Energy Information Administration (EIA).

Coal is a solid with a high carbon content and a low hydrogen content, typically only 5%.

The cost of coal mining is going up, production is declining in the Appalachian region and shifting to the Powder River Basin where it’s cheaper to mine and the coal is lower in sulfur. Factors such as geology and the rising costs of complying with a variety of new regulations, transportation, explosives and wages are making coal mining more expensive. Appalachian coal has been facing a structural decline as its mine seams have become thinner, more difficult to mine and less productive.

Western region mines over half of the coal produced in the United States and has some of the largest coal deposits in the world in the Powder River Basin  in northeast Wyoming and southeast Montana.

Coal mining in the United States is a major industry, which peaked in 2008 at 1.2 billion short tons. Coal production is highly localized and depends on having access to a full network of services, transport and power plants.

Coal accounts for approximately 45% of railroad carloads and 25% of the annual revenues of freight rail Class I companies (Association of American Railroads, 2011). Trucks are often the quickest and easiest way to move coal and can easily be scaled up or down. They are used in shorter hauling, moving smaller quantities, and access to loading points to nearby electric and industrial plants. Barges only move coal from mines that have access to the U.S. river system. They are slower but more cost effective and fuel efficient. About 20% of the coal used in U.S. electricity generation travels by inland waterways. Many coal companies use a multimodal delivery system that includes rail (short and long haul), trucks, railcars and barges. Coal transportation cost, especially in the west, can exceed mining cost (EIA 2012).

Hard Coal: Most Energy, Least Water

  1. 1% Anthracite. Domestic/Industrial including smokeless fuel
  2. 52% Bituminous. Metallurgical (coking coal) used to make iron and steel, Thermal (steam coal) used for power generation, cement making, and other industrial uses

Low Ranking Coal: Least Energy, Most Water

  1. 30% Sub-bituminous. Power generation, cement making, industrial uses
  2. 17% Lignite. Power generation mainly

Northern Appalachia coal, rated at 13,000 Btu per pound, is the highest quality, while Powder River Basin coal (from Wyoming and other Rocky Mountain states) is the lowest quality, with a rating of just 8,800 Btu per pound.

Coal fired power plant retirement

  • Most coal-fired capacity established in the 1970s &1980s
  • About 19% of existing U.S. coal-fired capacity (63GW) is at least 50 years old
  • 62% of the capacity (212GW) is between 30 to 50 years old
  • Different scenarios estimated 35–65 GW of coal retirement by 2020, representing 10%–20% of total U.S. coal fleet
  • Top five lead firms announced 11GW of coal retirement by 2016, representing 15% of their coal portfolio

What’s it good for besides electricity? The steel industry is the second largest user of coal and coal by-products to make steel for automobiles, bridges and buildings (Spiegel, 2006). Nearly 70% of global steel production depends on coal (Ernst & Young, 2011). Other coal users include concrete, cement, aluminum, paper, chemical, wood and roofing companies. Coal gas by-products such as methanol and ethylene are used to make products such as plastics, medicines, fertilizers and tar.

Full-scale carbon capture, utilization, and storage (CCS) technology has yet to be demonstrated in practice or proven to be commercially acceptable for coal-power- generating units due to significant technology, financial and regulatory challenges.

Coal gasification and liquefaction technologies have been known for some time. Their products can range from transportation fuels and gases to valuable chemicals that can be used in the industrial gas, fertilizer, plastics, rubber and various other industries.

Europe: Coal to replace oil (IEA)

Europe faces a dilemma. Indigenous oil and gas reserves are limited; supplies are increasingly dependent on imports; prices are uncertain, but likely to fluctuate wildly, and [Russia] shows a willingness to use its oil and gas for political purposes. Thus, there is a strategic need for the EU to establish stable fuel supplies.

From this strategic perspective, the only primary fuel (apart from nuclear) which has the capacity and the infrastructure to meet this stability requirement is coal. Unlike oil and gas, coal is geographically widely distributed, with many countries trading it, limiting odds of a monopoly supply situation. Also, international trade represents less than 15% of total world production. Because of its large reserves, the price is likely to be more predictable than that of either oil or gas.

CTL plants will be expensive to build and expensive to run. Therefore, it will only be deemed worthwhile proceeding if concerns about the security of oil and gas supplies are such that substitute oil products via CTL can provide a level of reassurance at a price that is deemed worth paying. As with all ‘insurance policies’, this will always seem unnecessary until it is actually needed. Under-investment or failure to pay the premiums will mean that benefits will not be paid out when they are needed. CTL is capital-intensive and benefits substantially from economies of scale. Most studies on process economics have assumed that a full-scale commercial plant would produce 50,000-100,000 barrels/day of liquid products (DTI 1999). Such a plant would process 15,000-35,000 metric tons/day of bituminous coal or up to double that amount of sub-bituminous coal or lignite. To be worthwhile, 400 million metric tons over the project lifetime ned to be consumed. It’s likely that an 80,000 barrel/day plant would cost $5-6 billion US dollars with annual operating costs of $250 million (Kelly).

A major pinch point for future fuel supplies is transport, for which demand shows no real sign of abating, with a continuing and expanding need for liquid fuels. The uncertainties in oil supply will continue to impact heavily on the transport sector, where no clearly viable alternative has yet been identified (not least since both biofuels and hydrogen involve significant use of fossil fuels). Consequently, the production of liquid fuels from coal offers a potentially attractive route to meeting this requirement, as one aspect of a balanced energy portfolio.

This position is reflected in the rapid growth of interest in CTL worldwide, with major engineering projects now underway in China and detailed feasibility studies being undertaken in the USA, while South Africa continues to upgrade its CTL production capacity. In Europe, there is a corresponding upturn in interest, particularly in the former Soviet Union satellite countries that are now members of the EU, such as Poland, Estonia and the Czech Republic.

The main quality parameter for coal is the carbon/energy content and so the logistics chains differ for hard coals and low rank coals. Global transportation of hard coals and some sub-bituminous coals is commercially worthwhile, while lower-grade coals (e.g. lignites and those with high impurity contents) must be used close to the coalfield as it is not economically viable to transport such coals any significant distance.

Coal is a solid with a high carbon content and a low hydrogen content, typically only 5%. Transport fuels (gasoline/petrol, diesel and jet fuel) are currently derived overwhelmingly from crude oil, which has about twice the hydrogen content of coal. For coal to replace oil, it must be converted to liquids with similar hydrogen contents to oil and with similar properties. This can be achieved by removing carbon or by adding hydrogen, either directly or indirectly, while reducing the molecular size. Also during the process, elements such as sulfur, nitrogen and oxygen must be largely eliminated. Thus, the technical challenge is to increase the hydrogen/carbon (H/C) ratio in the product, and to produce molecules with the appropriate range of boiling points.

Hydrogen is also needed to reduce the oxygen, sulfur and nitrogen present. These are removed as H2O, H2S and NH3. A range of partially refined gasoline- and diesel-like products (as well as propane and butane) can be recovered from the synthetic crude by distillation. This provides a series of different temperature-range ‘cuts’, and each of the liquid products is made up of a mixture of different hydrocarbons appropriate to the boiling point range of the different components. These products tend to be highly aromatic, which can make them difficult to use as high quality transport fuels, although they can be rich in octane aromatics making a good gasoline substitute.

coal-to-liquid diesel chart of processICL Coal-to-liquids diesel

Water usage. CTL plants require substantial amounts of water, probably in the range of 5 to 10 barrels for each barrel of liquid products. There are several major requirements for water in a liquefaction plant. 1) process water is needed for the steam feed to gasifiers to make up the hydrogen requirements, water for use in the liquefaction processes, and wash water for syngas cleaning. 2) steam may be required for the water-gas shift reaction; 3) boiler feed water is needed to produce steam, and in many cases for on-site power generation; 4) cooling water to remove heat at different stages, and in particular from the FT reactors where the highly exothermic reactions need careful temperature control.

It is important to consider the influence of coal properties on technical aspects of plant operation. In this regard, the most important characteristic coal properties are particle size, water content, amount and composition of mineral matter, content of the sulfur, nitrogen and chlorine species in the organic coal matter. The required particle size of the feed coal depends mainly on the process characteristics. On one hand, the particle size has to be low enough to ensure stability of the coal oil slurry, because coarse particles favor sedimentation while the valves of the high pressure pumps are very sensitive to oversize particles. On the other hand too high a proportion of very fine solid material is not desirable as this enhances significantly the viscosity of the coal oil slurry which causes high pressure drops and decreases the heat transfer in the heat exchangers. A typical particle size for hard coal as feed material is <0.2 mm. The feed coal is usually dried in a combined drying and pulverizing step. A high residual moisture in the coal which cannot be further reduced is disadvantageous as the resulting steam reduces the hydrogen partial pressure in the reactor volume. For hard coals 0.5-2 wt.-% moisture contents are attainable whereas for lignite 5-10 wt.-% has to be accepted. The mineral matter of the feed coal is an inert burden in the process and should be as low as possible, since they occupy expensive high pressure reactor volume without a contribution to the oil yield. Furthermore, they cause erosive material damages to the valves.

Sasol is seeking to build on its experience and expertise by looking for opportunities where substantial deposits of low cost (possibly low grade) coal would support a CTL plant producing around 80,000 bbl/d, thus taking advantage of the potential economies of scale. This approach, however, means that any individual project size requires the investment of very large amounts of capital (of the order of US$5-6 billion) so that government guarantees relating to the value of production or other long-term support would be needed.

Underground Coal Gasification (IEA)

UCG has the potential to unlock vast amounts of previously inaccessible energy in unmineable coal resources. There are significant obstacles to be overcome before this is possible, many of which are associated with the fact that the process takes place deep underground in a context where it is difficult to monitor and control the conditions. Consequently, UCG requires a multi-disciplinary integration of knowledge from exploration, geology, hydrogeology, drilling, and of the chemistry and thermodynamics of gasification reactions in a cavity in a coal seam (Couch 2009). UCG has reached the stage of “proof of concept”, but different parts of the technology have been demonstrated/proved separately and each in unique circumstances. That said, the single most important decision that will determine the technical and economic performance of UCG is site selection. The field trials undertaken so far are grouped into two main categories, namely those conducted at shallow depths, some in thicker seams, and those at greater depth in thin seams. To date, all that has been established is that given the right conditions, coals of different rank can be gasified underground. Ultimately, it will require a series of successful demonstrations, building on what has already been established, in different geological settings to establish where UCG can be safely carried out cost effectively at a commercial scale and without environmental damage.

References

Ahmed, G, et al. February 2013. US Coal and the Technology Innovation Frontier: What role does coal play in our energy future?  Duke University (much of above came from this)

Couch G. 2009. Underground coal gasification, IEA Clean Coal Centre

EIA. 2012. Coal Mining and Transporation. Coal Explained. http://www.eia.gov/energyexplained/index.cfm?page=coal_mining

Ernst & Young. 2011. Global Steel – 2011 Trends, 2012 Outlook: Ernst & Young. http://www.ey.com/Publication/vwLUAssets/Global_steel_2011_trends_2012_outlook/$FILE/Global_Steel_Jan_2012.pdf

IEA. 2009. Review of worldwide coal to liquids R, D&D activities and the need for further initiatives within Europe. International Energy Agency.

Spiegel, C. 2006. Opportunities for Coal-Based Products: Clean Coal and Coal Processing Technologies. BCC Research: BCC Research.

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Richard Heinberg: Only less will do

Posted on March 19, 2015 by

Richard Heinberg. March 16, 2015. Only Less Will Do. Post Carbon Institute.

[portions of this article were cut, reworded, and rearranged]

Almost nobody likes to hear about the role of scale in our global environmental crisis, because if growth is our problem, then the only real solution is to shrink the economy and reduce population.

Back in the 1970s, many environmentalists recommended exactly that remedy, but then came the Reagan backlash—a political juggernaut promising endless economic expansion if only we allowed markets to work freely. Many environmentalists recalibrated their message, and the “bright green” movement was born, claiming that efficiency improvements would enable humans to eat their cake (grow the economy) and have it too (protect the planet for the sake of future generations).pop-energy-1980-vs-2013

Population has grown from 4.4 billion in 1980 to 7.1 billion in 2013. Per capita consumption of energy has grown from less than 70 gigajoules to nearly 80 GJ per year. Total energy use has expanded from 300 exajoules to 550 EJ annually.

We’ve used all that energy to extract raw materials (timber, fish, minerals), to expand food production (converting forests to farmland or rangeland, using immense amounts of freshwater for irrigation, applying fertilizers and pesticides). And we see the results: the world’s oceans are dying; species are going extinct at a thousand times the natural rate; and the global climate is careening toward chaos as multiple self-reinforcing feedback processes (including polar melting and methane release) kick into gear.

The environmental movement has responded to that last development by adopting a laser-like focus on reducing carbon emissions. Which is certainly understandable, since global warming constitutes the most pervasive and potentially deadly ecological threat in all of human history. But the proponents of “green growth,” who tend to dominate environmental discussions (sometimes explicitly but more often implicitly), tell us the solution is simply to switch energy sources and trade carbon credits; if we do those simple and easy things, we can continue to expand population and per-capita consumption with no worries.

In the quest to make human society sustainable, the problem of scale crops up absolutely everywhere. We can make a particular activity more energy-efficient and benign (for example, we can increase the fuel economy of our cars), but the improvement tends to be overwhelmed by changes in scale (economic expansion and population growth lead to an increase in the number of cars on the road, and to the size of the average vehicle, and hence to higher total fuel consumption).

Yet here we are, decades after the eclipse of old-style, conservation-centered environmentalism, and despite all sorts of recycling programs, environmental regulations, and energy efficiency improvements, the global ecosystem is approaching collapse at ever-greater speed.

In reality, entirely switching our energy sources will not be easy, as I have explained in a lengthy recent essay. And while climate change is the mega-crisis of our time, carbon is not our only nemesis. If global warming threatens to undermine civilization, so do topsoil, freshwater, and mineral depletion.

The math of compound growth leads to absurdities (one human for every square meter of land surface by the year 2750 at our current rate of population increase) and to tragedy.

If confronted by this simple math, bright greens will say, “Well yes, ultimately there are limits to population and consumption growth. But we just have to grow some more now, in order to deal with the problem of economic inequality and to make sure we don’t trample on people’s reproductive rights; later, once everyone in the world has enough, we’ll talk about leveling off. For now, substitution and efficiency will take care of all our environmental problems.”

Maybe the bright greens (or should I say, pseudo-greens?) are right in saying that “less” is a message that just doesn’t sell. But offering comforting non-solutions to our collective predicament accomplishes nothing. Maybe the de-growth prescription is destined to fail at altering civilization’s overall trajectory and it is too late to avoid a serious collision with natural limits. Why, then, continue talking about those limits and advocating human self-restraint? I can think of two good reasons. The first is, limits are real. When we decline to talk about what is real simply because it’s uncomfortable to do so, we seal our own fate. I, for one, refuse to drink that particular batch of Kool-Aid. The second and more important reason: If we can’t entirely avoid the collision, let us at least learn from it—and let’s do so as quickly as possible.

All traditional indigenous human societies eventually learned self-restraint if they stayed in one place long enough. They discovered through trial and error that exceeding their land’s carrying capacity resulted in dire consequences. That’s why traditional peoples appear to us moderns as intuitive ecologists: having been hammered repeatedly by resource depletion, habitat destruction, overpopulation, and resulting famines, they eventually realized that the only way to avoid getting hammered yet again was to respect nature’s limits by restraining reproduction and protecting other forms of life. We’ve forgotten that lesson, because our civilization was built by people who successfully conquered, colonized, then moved elsewhere to do the same thing yet again; and because we are enjoying a one-time gift of fossil fuels that empower us to do things no previous society ever dreamed of. We’ve come to believe in our own omnipotence, exceptionalism, and invincibility. But we’ve now run out of new places to conquer, and the best of the fossil fuels are used up.

As we collide with Earth’s limits, many people’s first reflex response will be to try to find someone to blame. The result could be wars and witch-hunts. But social and international conflict will only deepen our misery. One thing that could help would be the widely disseminated knowledge that our predicament is mostly the result of increasing human numbers and increasing appetites confronting disappearing resources, and that only cooperative self-limitation will avert a fight to the bitter end. We can learn; history shows that. But in this instance we need to learn fast.

Posted in Birth Control, By People, Climate Change, Overpopulation, Richard Heinberg | Tagged , , , , , , , , | 2 Comments

Hydropower has a very low energy density

Posted on March 17, 2015 by

To store the energy contained in 1 gallon of gasoline requires over 55,000 gallons to be pumped up 726 feet (CCST 2012).

As a thought experiment look at what it would take generate all of America’s 4,058 TWh electricity, where Power = height of dam * cubic feet/second (cfs) water * turbine efficiency (~60 to 90%) / 11.8 (converts feet and second units into kilowatts).

Given that the 550-foot high Grand Coulee dam produces an average of 18 TWh a year with 50,000 cfs, at 90% efficiency, we’d need 225 more of them, using a grand of 58.4 billion cubic yards of water flowing through each dam, equal to 110 Lake Michigan’s, the world’s 6th largest fresh water lake.

You’d also have a hard time finding enough cement. The Grand Coulee used 11,975,500 cubic yards of concrete, so 225 would need 4 billion tons (2.7 billion cubic yards * 1.5 tons/cubic yard). Cement is 10 to 20% of concrete, so you’d need 3 to 6 times more cement than what America produces every year (USGS).

Using hydroelectric power to balance intermittent energy has many problems on downriver ecosystems, stranding fish in pools, and harming other aquatic life. In California, hydro units also have very limited amount of water available in the fall and winter months, so they are not available as a regulation resource during a number of months (CEC).

Adding more hydropower or pumped hydro storage is difficult because “”it requires two proximal large reservoirs with a sufficient amount of water surface and pressure elevation between them. Suitable geologic formations are rare and tend to be found in remote off-grid locations, such as mountains, where construction is difficult or restricted (SMUD AB2514).

References

CEC. June 2010. Research evaluation of wind generation, solar generation, and storage impact on the California Grid. Prepared by KEMA, Inc for the California Energy Commission.

CCST. April 2012. California’s Energy Future: Electricity from Renewable Energy and Fossil Fuels with Carbon Capture and Sequestration. California Council on Science and Technology. (height of Hoover Dam)

USGS. 2011. Cement production. United States Geological Society. 127,200,000 long tons converted to 142,464,000 short tons (2,000 lbs)

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