New Threat to Oil sand Projects

Posted on May 14, 2015 by

Newfound Threat to Oilsand Projects

Researchers discover ancient salt formation key factor in Alberta steam fracking disasters.

By Andrew Nikiforuk, 28 Jul 2014, TheTyee.ca

Also See: Next Oil sands Threat: Cracking Caprock

A new study suggests that naturally occurring upward flow of groundwater in the oilsands region is creating fractures and weaknesses that may explain a series of catastrophic events for the controversial mining industry.  The findings were published in a PhD thesis last year and soon will appear in a paper for the American Association of Petroleum Geologists Bulletin.

These findings have significant implications for worker safety, groundwater protection, the security of massive industrial wastewater disposal in the region as well as the economics and placement of more than 100 steam plants and mines.

Recent eruptions of steam, bitumen and groundwater at oilsands operations may all represent an industrial collision with a natural process that drives salty groundwater into bitumen-bearing reservoirs where it fractures and weakens the rock near and above bitumen deposits.

These calamities cost the industry tens of millions of dollars. The disasters also required large-scale cleanup efforts or resulted in project abandonment.

Ancient groundwater channels can carve holes in cap rock (a shale/sandstone layer that purportedly seals bitumen formations from other rock layers). In addition this protective cap rock thins or erodes to nothing in many places in the tarsands.

In other words, no geological seal exists to prevent industry made fractures caused by high-pressurized steam injections or waste water injection from erupting to the surface.

Breaking the Cap Rock

Approximately 80 per cent of Alberta’s bitumen deposits lie deeper than 75 metres and cannot be mined. As a consequence, these deep deposits, all capped by rock, are currently being heated to as high as 300 degrees Celsius with highly pressurized steam.

Given that there are more than 100 steam plant facilities poking thousands of holes into irregular layers of bitumen, there is “a need to improve the collective capabilities of operators, service providers and regulatory bodies in the area of caprock integrity management,” noted the event’s organizers.

Industry uses either a steaming tool called steam-assisted gravity drainage or cyclic steam stimulation to melt a resource as hard as a hockey puck.

The overlaying caprock acts as a primary but not always impermeable seal that keeps steamed bitumen from seeping into aquifers, neighbouring industry wellbores and other geological formations, as well as the forest floor and lakes.

In general, industry tries to keep the pressure significantly low enough to ensure the caprock does not break — but high enough to push the melted bitumen out.

It is a very fine line. In 2006, French multinational company Total blew a 300-metre crater in the forest while trying to steam up a shallow formation of bitumen.

Although regulatory reports on the event weren’t published until four years later, the “catastrophic event” put caprock integrity on the agenda and forced Total to abandon its project.

Ever since then, all steam-based bitumen operations, the industry’s most energy-intensive facilities, report yearly on caprock integrity. The Society of Petroleum Engineers devoted a sold-out workshop on the subject last spring in Banff.

Half of all bitumen now produced from the oilsands relies on a form of oil production that injects highly pressurized steam into deep deposits of cold bitumen.

Harvard researcher and University of Calgary graduate Benjamin Cowie traces four significant and costly events in the tarsands to a newly identified geohazard: the erosion of salt formations underneath bitumen deposits by the movement of groundwater.

Echos of fracking

Recent studies by petroleum scientists as well as annual industry progress reports to the Alberta Energy Regulator show that the technologies used to steam deep bitumen deposits have created the same sort of problems now plaguing the hydraulic fracturing of unconventional oil and gas resources across North America.

Both technologies inject highly-pressurized fluids into formations where the resulting pressure can crack or fracture overlying rock and well casings in unpredictable ways. These fractures can bring fluids or gases to the surface, contaminate groundwater or connect with other existing wells.

The end result for both technologies are the same: hydrocarbons go where regulators don’t want them or industry can’t control them.

Alberta regulators described the Total blow-out as a fracking issue in a 2011 presentation. “Given ongoing caprock integrity concerns associated with fracturing and hydro-fracking in the subsurface to initiate production, these findings will have relevance to other shallow thermal and non-thermal operations, including in-situ bitumen/extra-heavy oil operations, and production of other emerging unconventional commodities such as tight oil and shale gas.”

The problem seems most pronounced at cyclic steam operations such as those run by Canadian Natural Resources Ltd. and Imperial Oil, where steam is injected into the ground for weeks at a time from pads that typically contain as many as 20 wells. After a soaking period, melted bitumen is brought to the surface.

Cowie suspects that fractures and faults created by the new hazard have collided with industrial activity along the eastern fringes of bitumen mining in northeastern Alberta.

1. In 2009 bitumen seeped to surface at CNRL’s Primrose operation in Cold Lake. Four more seeps appeared in 2013 resulting in a $50-million cleanup operation. CNRL eventually excavated 82,508 tonnes of impacted earth and drained an entire lake. The fourth largest oil spill in Alberta history is still under investigation.

2. In 2010 Shell’s Muskeg River mine hit a gusher of sulfate-rich and salty groundwater connected to the Devonian while excavating a tailing pond. It took more than a year to contain a rupture that spurted 2,000 cubic metres of salt water an hour. It cost millions of dollars to plug the leak. Researchers say that “it is almost certain that more conduits exist throughout the oilsands region, and that this will not be the last incident of brine discharge in an oilsands system.”

3. In 2006 Total blasted a 75 by 125 metre surface crater in the boreal forest at its Joslyn Creek steam plant resulting in the abandonment of the project. The event rendered nearly 30 million barrels of bitumen unrecoverable. Alberta regulators, which didn’t report on the event for four years, later compared the Total blowout to an uncontrolled frack job in a 2011 presentation. “Given ongoing cap rock integrity concerns associated with fracturing and hydro-fracking in the subsurface to initiate production, these findings will have relevance to other shallow thermal and non-thermal operations, including in-situ bitumen/extra-heavy oil operations, and production of other emerging unconventional commodities such as tight oil and shale gas.”

4. In the 1980s Texaco created a geyser of bitumen and salt water outside of Fort McMurray. There is little literature on the blowout. But it may have connected to a Devonian aquifer too. —Andrew Nikiforuk

The events include the massive 12,000 barrel bitumen seepage to the surface by Canadian Natural Resources Ltd. (CNRL); a huge blowout at Total’s Joslyn steam plant project in 2006; and a large groundwater gusher at Shell’s Muskeg River mine.

That 2010 disaster turned a newly created dam for mining waste into a lake full of 7-billion litres worth of highly saline water.

Harvard researcher Benjamin Cowie, who recently presented his findings to industry, now argues that all of the events share one geological feature: they occurred along the edge of an ancient salt formation that runs in a northwest to southeast direction through the Athabasca and Cold Lake oilsands deposits.

Geologists call it the Prairie Evaporite and it is part of the Devonian formation that lies underneath the tarsand deposits.  But based on the chemistry of water samples collected by industry from the region, Cowie believes that ancient glacial water is not only eating away the rock but creating new weaknesses under these bitumen layers targeted by industry.

In some places the highly saline water has erupted into bitumen formations where industry has recorded the sudden appearance of sinkholes or seeps of highly saline water. Many of these naturally occurring seeps run directly into the Athabasca river.

In addition Cowie suspects that that aquifers with high salt content have dissolved and weakened the rock infrastructure beneath bitumen deposits and in some places created vertical fractures as the highly pressurized salty water rises toward the surface.

At this point industry-made fractures created by oilsands mining and steaming operations then collide with these up swells of water or connect to metre scale fractures created by the dissolution of salt by the groundwater movement.

“This is a big regional process and an entirely new environmental risk for the oilsands,” Cowie said in an exclusive Tyee interview.

Underground saltwater can destroy seal of cap rock

The Alberta Energy Regulator (AER), which is mapping the area to identify geological factors that may affect cap rock seals, now supports Cowie’s findings.

A 2013 paper presented to the American Rock Mechanics Association in San Francisco said that the regulator had identified “a complex sub-Cretaceous structure created by salt dissolution and collapse, which has implications for cap rock integrity and also for the disposal of produced and process water into Devonian strata.”

The paper also warned that ancient groundwater channels can carve holes in cap rock (a shale/sandstone layer that purportedly seals bitumen formations from other rock layers). In addition this protective cap rock thins or erodes to nothing in many places in the tarsands.

In other words, no geological seal exists to prevent industry made fractures caused by high-pressurized steam injections or waste water injection from erupting to the surface.

Earlier this year the AER abruptly suspended proposed shallow steam plant operations over a large area of the tarsands, worth billions of dollars, due to concerns about punching holes through the cap rock and polluting groundwater.

New clues to Cold Lake disaster

The regulator’s San Francisco presentation also revealed that large science gaps now exist on the issue. Stress regimes below 350 metres in the region are “not well understood and there is very little publicly available data.” Nor has groundwater been properly mapped or monitored in the region.

A June 2014 preliminary report by CNRL on its large bitumen seepage in Cold Lake also underscores how poorly industry understands the complexity of rock structures in the region.

The company’s first report on the causes of the headline-making event blames industry made rock fractures that allowed bitumen and steam to break through a shale barrier and then travel by natural fractures, faults or badly cemented wellbores to the surface.

Since 2009 CNRL Primrose East steam operation in Cold Lake has leaked thousands of barrels of bitumen and steam to the surface in as many as five identified distinct ground fractures contaminating both surface and groundwater.

However, the CNRL report does not mention the possibility that the erosion of a salt formation underlying its Primrose East field may also play a role in weakening local geology by inducing fractures and faults.

Nor does the CNRL’s report make any reference to the 2013 AER study or Cowie’s work.

But an independent technical panel, which reviewed CNRL’s causation work, flags the novel geological hazard as a major concern.

The panel noted, for example, that the geological weaknesses created by dissolving unique salt formations under the bitumen deposits in Primrose East “could influence shale integrity.”

Salt-related subsidence could also result in changes in rock stress and fractures that damage bitumen bearing zones, adds the technical report. “Clearly identifying these potential geologic hazards” is imperative, adds the report.

New factor in assessing risk

Some bitumen miners, however, have quietly recognized the new geohazard and have recently set up agreements to share data on what’s happening in the Devonian formation and how these events might compromise industrial activity.

One recent industry presentation, for example, noted that the dramatic erosion of salt deposits by glacial waters in the eastern portion of the Athabasca tarsands deposit “has created additional complexity” for steam plant operations.

Another 2014 presentation warned, “the presence of a highly transmissive aquifer in the ‘Intact’ Prairie Evaporite Formation will need to be considered as part of their risk analysis and, as needed, risk mitigation plans.”

Bernhard Mayer, a University of Calgary hydrologist who supervised Cowie’s PhD thesis, says the government and industry need to do a “more detailed investigation of the nature of these localized pathways between the McMurray formation and underlying Devonian units.”

They also need to study “the integrity of cap rocks overlying the bitumen-containing units and assess the cap rock integrity in view of the stress regime and the pressures associated with steaming operations.”

Cowie adds that there is little information about the complex geological phenomena.

“The extent of recent rock dissolution beneath the oilsands region is unknown and I think the absence of information poses a real risk to oilsands producers.”

By linking all these serious events to one mechanism Cowie hopes that regulators and industry “will pay more attention to it” and perform better regional mapping to study the risks.

During the catastrophic Joslyn steam blowout and the bursting of the previously unknown saline aquifer at Shell’s Muskeg mine, bitumen workers could have been seriously injured near the discharge sites, says Cowie.

The geohazard could also significantly affect economics by “requiring more detailed geological characterization to truly identify what’s happening with groundwater in these systems, or in the worst case, substantial and expensive cleanup efforts would be required if a leak does occur.”

David Schindler, a world famous water researcher and long-time critic of rapid bitumen development, called Cowie’s research clear and significant and urged provincial authorities to change how projects are approved and monitored.

“Once again, the scientific homework is done after the assignment is due. When will the Alberta government ever learn?”

 

 

 

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Global oil risks in the early 21st century, Energy Policy 2011

Posted on May 12, 2015 by

[This is a large excerpt from an excellent 18-page paper I think predicts how the future will unfold as well as a good overview of our predicament. Alice Friedemann]

Fantazzini, Dean; Höök, Mikael; Angelantoni, André. 2011. Global oil risks in the early 21st century. Energy Policy, Vol. 39, Issue 12: 7865-7873

http://dx.doi.org/10.1016/j.enpol.2011.09.035

The Deepwater Horizon incident demonstrated that most of the oil left is deep offshore or in other difficult to reach locations. Moreover, obtaining the oil remaining in currently producing reservoirs requires additional equipment and technology that comes at a higher price in both capital and energy. In this regard, the physical limitations on producing ever-increasing quantities of oil are highlighted as well as the possibility of the peak of production occurring this decade. The economics of oil supply and demand are also briefly discussed showing why the available supply is basically fixed in the short to medium term. Also, an alarm bell for economic recessions is shown to be when energy takes a disproportionate amount of total consumer expenditures. In this context, risk mitigation practices in government and business are called for. As for the former, early education of the citizenry of the risk of economic contraction is a prudent policy to minimize potential future social discord. As for the latter, all business operations should be examined with the aim of building in resilience and preparing for a scenario in which capital and energy are much more expensive than in the business-as-usual one.

An economy needs energy to produce goods and deliver services and the size of an economy is highly correlated with how much energy it uses (Brown et al., 2010a, Warr and Ayers, 2010). Oil has been a key element of the growing economy. Since 1845, oil production has increased from virtually nothing to approximately 86 million barrels per day (Mb/d) today (IEA, 2010), which has permitted living standards to increase around the world. In 2004 oil production growth stopped while energy hungry and growing countries like China and India continued increasing their demand. A global price spike was the result, which was closely followed by a price crash. Since 2004 world oil production has remained within 5% of its peak despite historically high prices (see Figure 1).

The combination of increasingly difficult-to-extract conventional oil combined with depleting super-giant and giant oil fields, some of which have been producing for 7 decades, has led the International Energy Agency (IEA) to declare in late 2010 that the peak of conventional oil production occurred in 2006 (IEA, 2010). Conventional crude oil makes up the largest share of all liquids commonly counted as “oil” and refers to reservoirs that primarily allow oil to be recovered as a free-flowing dark to light-colored liquid (Speight, 2007). The peak of conventional oil production is an important turning point for the world energy system because many difficult questions remain unanswered. For instance: how long will conventional oil production stay on its current production plateau? Can unconventional oil production make up for the decline of conventional oil? What are the consequences to the world economy when overall oil production declines, as it eventually must? What are the steps businesses and governments can take now to prepare? In this paper we pay particular attention to oil for several reasons. First, most alternative energy sources are not replacements for oil. Many of these alternatives (wind, solar, geothermal, etc.) produce electricity— not liquid fuel. Consequently the world transportation fleet is at high risk of suffering from oil price shocks and oil shortages as conventional oil production declines. Though substitute liquid fuel production, like coal-to-liquids, will increase over the next two or three decades, it is not clear that it can completely make up for the decline of oil production. Second, oil contributes the largest share to the total primary energy supply, approximately 34%. Changes to its price and availability will have worldwide impact especially because alternative sources currently contribute so little to the world energy system (IEA, 2010).

Oil is particularly important because of its unique role in the global energy system and the global economy. Oil supplies over 90% of the energy for world transportation (Sorrell et al., 2009). Its energy density and portability have allowed many other systems, from mineral extraction to deep-sea fishing (two sectors particularly dependent on diesel fuel but sectors by no means unique in their dependence on oil), to operate on a global scale. Oil is also the lynchpin of the remainder of the energy system. Without it, mining coal and uranium, drilling for natural gas and even manufacturing and distributing alternative energy systems like solar panels would be significantly more difficult and expensive. Thus, oil could be considered an “enabling” resource.

Oil enables us to obtain all the other resources required to run our modern civilization.

Peak oil is the result of a complex set of forces that includes geology, reservoir physics, economics, government policies and politics.

There are a number of physical depletion mechanisms that affect oil production (Satter et al., 2008). Depletion-driven decline occurs during the primary recovery phase when decreasing reservoir pressure leads to reduced flow rates. Investment in water injection, the secondary recovery phase, can maintain or increase pressure but eventually increasingly more water and less oil is recovered over time (i.e. increasing water cut). Additional equipment and technology can be used to enhance oil recovery in the tertiary recovery phase but it comes at a higher price in terms of both invested capital and energy to maintain production.

The situation is similar to squeezing water out of a soaked sponge. It is easy at first but increasingly more effort is required for diminishing returns. At some point, it is no longer worth squeezing either the sponge or the oil basin and production is abandoned.

Another way to explain peaking oil production is in terms of predator-prey behavior, as Bardi and Lavacchi (2009) have done. Their idea is that, initially, the extraction of “easy oil” leads to increasing profit and investments in further extraction capacity. Gradually the easiest (and typically the largest) resources are depleted. Extraction costs in both energy and monetary terms rise as production moves to lower quality deposits. Eventually, investments cannot keep pace with these rising costs, declining production from mature fields cannot be overcome and total production begins to fall.

Hubbert (1982) wrote: There is a different and more fundamental cost that is independent of the monetary price. That is the energy cost of exploration and production. So long as oil is used as a source of energy, when the energy cost of recovering a barrel of oil becomes greater than the energy content of the oil, production will cease no matter what the monetary price may be.

Currently, around 60 countries have passed “peak oil” (Sorrell et al., 2009)— their point of maximum production. In most cases this is due to physical depletion of the available resources (e.g. USA, the UK, Norway, etc.) while in a few cases socioeconomic factors limit production (e.g. Iraq).

Attempts to disprove peak oil that focus solely on the amount of oil available in all its forms demonstrate a fundamental, and unfortunately common, confusion between how much oil remains versus how quickly it can be produced. Although until recently oil appears to be more economically available than ever before (Watkins, 2006), others have shown this to be an artifact of statistical reporting (Bentley et al., 2007). Further, it is far less important how much oil is left if demand is, for instance, 90 Mb/d but only 80 Mb/d can be produced. Still, the most realistic reserve estimates indicate a near-term resource-limited production peak (Meng and Bentley, 2008; Owen et al., 2010).

Total oil production is comprised of conventional oil, which is liquid crude that is easy and relatively cheap to pump, and unconventional oil, which is expensive and often difficult to produce. It is vital to understand that new oil is increasingly coming from unconventional sources like polar, deep water and tar sands. Almost all the oil left to us is in politically dangerous or remote regions, is trapped in challenging geology or is not even in liquid form.

Today, over 60% of the world production originates from a few hundred giant fields. The number of giant oil field discoveries peaked in the early 60s and has been dwindling since then (Höök et al., 2009). This is similar to picking strawberries in a field. We picked the biggest and best strawberries first (just like big oil fields they are easier to find) and left the small ones for later. Only 25 fields account for one quarter of global production and 100 fields account for half of production. Just 500 fields account for two-thirds of all the production (Sorrell et al., 2009).

As the IEA (2008) points out, it is far from certain that the oil industry will be able to muster the capital to tap enough of the remaining, low-return fields fast enough to make up for the decline in production from current fields.

Oil sources are not equally easy to exploit. It takes far less energy to pump oil from a reservoir still under natural pressure than to recover the bitumen from tar sands and convert it to synthetic crude. The energy obtained from an extraction process divided by the energy expended during the process is the Energy Return on Energy Invested (EROEI).

Since giant and super giant oil fields dominate current production, they are good indicators for the point of peak production (Robelius, 2007; Höök et al., 2009). There is now broad agreement among analysts that the decline in existing production is between 4-8% annually (Höök et al., 2009). In terms of capacity, this means that roughly a new North Sea (~5 Mb/d) has to come on stream every year just to keep the present output constant.

Peak oil is the point in time where production flows are unable to increase. It is not just underinvestment, political gamesmanship or remote locations that make oil production increasingly difficult. The physical depletion mechanisms (increasing water cut, falling reservoir pressure, etc.) will unavoidably affect production by imposing restrictions and even limitations on the future production of liquid crude oil. No amount of technology or capital can overcome this fact.

Some consequences of having extracted much of the easy oil are the following:

  1. It takes significantly more time once a field is discovered to start production. Maugeri (2010) estimates it now takes between 8 and 12 years for new projects to produce first oil. Difficult development conditions can delay the start of production considerably. In the case of Kashagan, the world’s largest oil discovery in 30 years, production has been delayed by almost ten years due to difficult environmental conditions.
  2. In mature regions, an increased drilling effort usually results in little increase in oil production because the largest fields were found and produced first (Höök and Aleklett, 2008; Höök et al., 2009).
  3. Because the cost of extracting the remaining oil is much higher than easy-to-extract OPEC or other conventional oil, if the market price remains lower than the marginal cost for long enough producers will cut production to avoid financial losses. See Figure 3.
  4. Uncertainty about future economic growth heightens concerns for executing these riskier projects. This delays or often cancels projects (Figure 4).
  5. Most remaining oil reserves are in the hands of governments. They tend to under-invest compared to private companies (Deutsche Bank, 2009).
  6. Possible scarcity rents have to be taken into account. Hotelling (1931) showed that in the case of a depletable resource, price should exceed marginal cost even if the oil market were perfectly competitive (the resulting difference is called scarcity rent).

If this were not the case, it would be more profitable to leave the oil in the ground, waiting to produce it until the price has risen. Hamilton (2009a, 2009b) noted that while in the 1990s the scarcity rent was negligible relative to costs of extraction, the strong demand growth from developing countries in the last decade together with limits to expanding production could in principle account for a sudden shift to a regime in which the scarcity rent is positive and quite important. In this regard, the Reuters news service reported on April 13, 2008 that Saudi Arabia’s King Abdullah said he had ordered some new oil discoveries left untapped to preserve oil wealth in the world’s top exporter for future generations, the official Saudi Press Agency (SPA) reported. Therefore, a possible intertemporal calculation considering scarcity rents may have already influenced (i.e. limited) current production. Although the sudden fall of prices at the end of 2008 is difficult to reconcile with scarcity rents, the following quick price recovery to the 70$-120$ range during the enduring global financial crisis indicates that this aspect cannot be dismissed. This is despite the assertion by Reynolds and Baek (2011) that the Hotelling principle “… is not a powerful determinant of nonrenewable resources prices,” and that “…the Hubbert curve and the theory surrounding the Hubbert curve is an important determinant of oil prices.” We agree that the Hubbert curve, which defines the depletion curve of a non-renewable resource, may be the prime determinant of oil price but it is not the only one.

Figure 3. Global marginal cost of production 2008. Source: LCM Research based on Booz Allen/IEA data (Morse, 2009).

Figure 3. Global marginal cost of production 2008. Source: LCM Research based on Booz Allen/IEA data (Morse, 2009).

 

 

After 2014, it appears that global oil production will begin its decline (See the second report of the UK Industry Taskforce on Peak Oil and Energy Security (UK ITPOES, 2010), Lloyd’s (2010), Deutsche Bank (2009, 2010), the report by the UK Energy Research Centre (Sorrell et al., 2009a) and the 2010 World Energy Outlook by the IEA (2010).)

Deutsche Bank (2009) asserts that for American consumers this point is when energy represents 7.5% of gross domestic product. This value is close to the one calculated by Hamilton (2009b) but is based on monthly data and uses a different methodology. In a more recent report, Deutsche Bank (2010) lowered this threshold to 6.5% because “…the last shock set in motion major behavioral and policy changes that will facilitate rapid behavioral changes when the next one comes and underemployment and weak wage growth has increased sensitivity to gasoline prices. Last time it took $4.50/gal gasoline to finally tip demand, this time it might only take $3.75/gal to $4.00/gal to do it.” However, they also highlighted that “Americans have become comfortable with paying more for gasoline, and it may take higher prices to force behavior change”.

Hamilton (2011) highlighted that 11 of the 12 U.S. Recessions since World War II were preceded by an increase in oil prices. Unfortunately, there is no clear alternative source of energy able to fully substitute for oil (see, for example, Maugeri (2010) for a recent nontechnical review of the limits of alternative sources of energy with respect to oil). It possesses a combination of energy density, portability and historically very high EROEI that is difficult for alternatives to match. 4. A timely energy system transformation not assured. As oil production declines, significant changes to the currently oil-dependent economy in the medium term are likely to be needed. However, it isn’t clear that there will the financial means to implement such a change. For example, Deutsche Bank (2009, 2010) suggested that the widespread use of electric cars in the second part of this decade will be the disruptive technology that will finally destroy oil demand. Apart from technology and resource constraints (lithium necessary for electrical batteries is quite abundant in nature but production is currently very limited), the availability of sufficient financial resources to transition the entire vehicle fleet seems dubious. As Hamilton (2009b) demonstrates, tightened credit follows high oil prices and most vehicles are purchased on credit. Others suggest that natural gas is the next energy paradigm. Again, will be there sufficient financial resources to switch to it as oil production declines? Reinhart and Rogoff (2009, 2010) found that historically, after a banking crisis, the government debt on average almost doubles (86% increase) to bail out the banks and to stimulate the economy. They also showed that a sovereign debt crisis usually follows, not surprisingly as we saw Iceland, Greece, Ireland, Hungary and Portugal turning to the EU/ECB and/or the IMF for financial help to refinance their public debts to avoid default. The need to switch to alternative energy sources with the enormous financial investments that such a task would require— and the simultaneous presence of large public and private debts — may well form a perfect storm.

Demography will also be extremely important in the next decade as well. Europe and the United States have aging populations and their baby boomers are entering pension age. China faces a similar demographic problem due to their one child policy, too.

The combination of declining oil production (and thus oil priced high enough to cause recessions), high taxes, austerity measures, more restrictive credit conditions and demographic shifts have the potential to severely constrain the financial resources needed to move the economy away from oil and to alternative energy sources. Another consequence of this combination of forces is the likely contraction of the world economy (Hamilton, 2009b; Dargay and Gately, 2010).

Businesses and governments struggle with alternating circumstances of insufficient cash flow to handle price spikes and plummeting prices that don’t cover their cost structure. Long term planning in this ever-changing environment becomes extremely difficult and investment — even highly needed investment — can drop precipitously.

Friedrichs (2010) also cautions that after peak oil countries have several sociological trajectories available to them: they can follow predatory militarism like Japan before WWII, totalitarian retrenchment like North Korea, or, ideally, socioeconomic adaptation like Cuba after the fall of the Soviet Union. Given the recent century of conflict and the extensive weapon stocks and militaries held by modern nations (especially the United States, which spends on its military almost as much as the remaining countries of the world combined (SIPRI, 2011), there is simply no guarantee that the relatively peaceful period currently experienced by developed nations that is conducive to rapid energy source transitions will continue much longer.

A further challenge is that, strictly speaking, for the last 150 years we have not transitioned from previous fuel sources to new ones — we have been adding them to the total supply. We are currently using all significant sources (coal, oil, gas and uranium) at high rates. Thus, it’s common but incorrect to say that we moved from coal to oil. In fact, we are using more coal now than we ever have (IEA, 2010). We never left the coal age. The challenge of moving to alternative energy sources while a particularly important source is declining, in this case oil, should not be underestimated.

Brown et al. (2010b) show how significant the squeeze of declining gross production and increasing producer country consumption can be, which they have named the Export Land Model. Increasing producer country consumption due to population growth acts as a strong magnification factor that removes oil very quickly from the export market. Using the top five exporting countries from 2005 (Saudi Arabia, Russia, Norway, Iran and United Arab Emirates), they construct a scenario in which combined production declines at a very slight 0.5% per year over a ten year period for a total of 5%. Internal oil consumption for these exporters continues to grow at its current rate (2010). In this scenario net oil exports decline by 9.6%, almost double the rate oil production declines.

This accelerated loss of exportable oil can be seen in many producer countries that have passed their peak. Indonesia has withdrawn from OPEC because they have no more exportable oil to offer the world market. Egypt is already incurring a public debt and is on the cusp of becoming a net oil importer, which will exacerbate already stretched public finances. As producer countries continue to grow their oil use even modestly and production declines (again, even modestly), there is an extremely high risk that net exportable oil will decline much faster than most observers are currently expecting.

Other mitigation efforts like increased solar, wind and geothermal production may not be prioritized since they do not help the situation — they produce electricity and the world’s 800 million transportation, food production (i.e. tractors and harvesters) and distribution vehicles require liquid fuel.

A contracting economy presents governments with a host of problems that are not easy to resolve. Promises made to the citizenry, some in the form of social welfare programs, pensions and public union contracts, will be impossible to keep as the energy base of the economy declines. Downward wage pressure and reduced business activity will lower tax revenue. With lower revenues and greater demands in the form of social welfare support by an increasingly poorer citizenry, it is difficult to see how the accumulated (and growing) government debt can be paid back without rampant inflation. Though it is still unclear whether the government response will be hyperinflation (to minimize the debts) or extensive and massive debt defaults (deflation) — or both — it is not likely that business as usual will continue as oil production declines.

Some governments may also have to contend with food and fuel riots as they did in 2007 and 2008. Other forms of crowd behavior, namely hoarding of fuel and food, may exacerbate the situation and governments should prepare accordingly.

Supply Chains

Manufacturers in particular will have to contend with increased difficulties making and delivering products as oil production declines (Hirsch et al., 2005). It will prove imperative that business addresses this Schumpetarian shock (a structural change to industry that can alter what is strategically relevant) in a timely fashion (Barney, 1991).  A significant benefit of cheap oil was that distance was relatively inexpensive. It is possible now to manufacture goods using far-flung operations. However, as oil declines, distance will, once again, become increasingly expensive, and oil price may begin to act as a trade barrier for many products.  Another risk as oil production declines is the possibility of oil supply disruptions. If this should occur, much modern manufacturing may be impacted. Just-in-time manufacturing systems in which warehoused parts are minimized through the frequent replenishment of parts by parts suppliers — sometimes with multiple deliveries a day— have little tolerance for delivery delays.  To prepare for this risk requires more than the drive for manufacturing efficiency that has generally characterized business. Supply chains should be examined with the aim of building in resilience and greater agility (Bunce and Gould, 1996; Krishnamurthy 2007), implying the loosening of tight and often brittle couplings between suppliers and manufacturers (Christopher 2000; Towill 2001, Mitch Leppo ). With little or no slack in the system (fewer warehoused parts, etc.), just one supplier failing to deliver a part or supplier hoarding can shut down a production process.

References

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Peak soil, peak phosphate, peak fertilizer means Peak Food

Posted on May 9, 2015 by

Amundson, R., et al. May 7, 2015. Soil and human security in the 21st century. Science 348.

A group of leading soil scientists has summarized the precarious state of the world’s soil resources and the possible ramifications for human security in the journal Science.

This paper describes threats to soil productivity — and, in turn, food production — due to soil erosion, nutrient exhaustion, urbanization and climate change.

“Soil is our planet’s epidermis, it’s only about a meter thick, on average, but it plays an absolutely crucial life-support role that we often take for granted,” said lead author Sparks,  the S. Hallock du Pont Chair in Soil and Environmental Chemistry in the Department of Plant and Soil Sciences at UD, has been chair of the National Academy of Sciences’ U.S. National Committee for Soil Sciences since 2013.

He and his five co-authors, who are also members of the national committee or leaders of soil science societies, wrote the paper to call attention to the need to better manage Earth’s soils during 2015, the International Year of Soils as declared by the United Nations General Assembly.

“Historically, humans have been disturbing the soil since the advent of agriculture approximately 10,000 years ago,” Sparks said. “We have now reached the point where about 40 percent of Earth’s terrestrial surface is used for agricultural purposes. Another large and rapidly expanding portion is urbanized. We’re already using the most productive land, and the remainder is likely to be much less useful in feeding our growing population.”

According to the Sparks and his colleagues, soil erosion greatly exceeds the rate of soil production in many agricultural areas. For example, in the central United States, long considered to be the “bread basket” of the nation, soil is currently eroding at a rate at least 10 times greater than the natural background rate of soil production.

The loss of soil to erosion leads to the loss of key nutrients for plant growth, requiring a need for commercial fertilizers. However, the current rate of fertilizer production is unsustainable.  The primary components of fertilizer are either very energy-intensive to produce or they are mined from limited supplies on Earth. 

The increase in fertilizer prices is not likely to be temporary. The largest reservoir of rock phosphate in the U.S. is expected to be depleted within 20 years, he says, at which point we will need to begin importing this source of the essential nutrient phosphorus.

“Unless we devise better ways to protect and recycle our soil nutrients and make sure that they are used by crops efficiently rather than being washed away, we are certainly headed for nutrient shortages,” Sparks said, adding that disruptions in food production could become a source of geopolitical conflict.

“Human civilizations have risen and fallen based on the state of their soils,” Sparks said. “Our future security really depends on our ability to take care of what’s beneath our feet.”

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Livestock diseases, Science Mag Review of “Arresting Contagion”

Posted on May 7, 2015 by
Science 17 April 2015: Vol. 348 no. 6232 p. 294 DOI: 10.1126/science.aaa7672

The fever on the farm

Arresting Contagion Science, Policy, and Conflicts over Animal Disease Control Alan L. Olmstead and Paul W. Rhode Harvard University Press, 2015. 477 pp.

The riots were in their 13th year. Two federal officials had recently been shot, and one of them had died from his injuries, but the local grand jury, drawn from an aggrieved and angry community, refused to indict the shooter. The year was 1922, and farming communities across the United States were vigorously resisting new regulations imposed by the Bureau of Animal Industry (BAI) that were intended to eradicate a parasitic infection known as Texas fever in domestic cattle.

Arresting Contagion is at once a biography (even a hagiography) of the BAI and a penetrating glimpse into the behavioral economics that defined early animal disease control efforts in the United States. The book begins in the late 19th century, a time of enormous innovation in agriculture and infrastructure. Animals were bred and killed on an unprecedented scale and transported over vast distances, both domestically and internationally. This created enormous opportunities for diseases—including Texas fever, contagious bovine pleuropneumonia (lung plague), bovine tuberculosis, pork measles, and hog cholera—to emerge and spread. The book focuses on how some of these devastating livestock diseases were progressively controlled—a story that is complete with setbacks and victories, heroes and villains.

From 1904 to 1915, James Dorsey, who falls firmly into the villain category, did a good trade in cheap cattle that had failed a tuberculin test, passing them off as healthy animals to unsuspecting farmers. This practice created at least 10,000 foci of tuberculosis among dairy herds across the United States and likely contributed to tens of thousands of cases of human tuberculosis (1). Compared to “TB James,” Typhoid Mary was an amateur.

A pleasant contrast to Dorsey can be found in Daniel E. Salmon, who became the first person to be awarded a veterinary degree in the United States in 1876 and was appointed the first chief of the BAI in 1884. Within eight years of his appointment, lung plague had been eradicated in the United States. Under his leadership, veterinary scientists showed medical researchers the way by demonstrating that insect vectors could transmit disease, developing the first killed vaccine, and identifying the human hookworm parasite. Salmonella bacteria, discovered by his research group in 1885, were named after him in 1900.

In their book, Olmstead and Rhode probe the motives that drive individuals to comply with, or reject, efforts to mitigate animal disease transmission. These motives are both fascinating and, more often than not, uncomfortably predictable. For example, many men who made money moving cattle refused to believe in contagions altogether. In the early 1880s, Chicago stockyard owners argued that their animals were in perfect health and that it would be financial suicide for them to sell unwholesome meat. Yet, inspections conducted in September 1886 revealed an industry plagued by filth and disease, a condition that persisted until federal legislation was established and regular, mandatory inspections were instituted. The authors make a strong case that disease is too important to leave to market forces and that the government has an essential role in controlling zoonotic disease.

In addition to regulation, the authors emphasize the need to incentivize farmers and merchants to comply with health and safety regulations. For example, in the 1920s, after their own cattle had been cleansed of Texas fever, farmers started to demand vociferously that disease control be mandated for still-infected cattle populations, which were now a major threat for disease reintroduction. Compensation for culled animals and the (limited) legal provisions that entitle farmers to recover damages from disease are also well addressed in the book.

Written by two economists, the book features a number of terms that may not be familiar to readers from health backgrounds, such as “externalities,” “rent-seeking,” and “public choice theory.” There are also occasional infelicities of phrasing: Cattle herds are ravished (rather than ravaged) by disease, and scientists attain notoriety (rather than fame) from their discoveries. Apart from these quibbles, the book is comprehensive, is well written, and contains a substantial amount of original research. This, along with extensive notes and references, will make it useful to those who are grappling with the recent resurgence in zoonotic diseases brought about by the rapid expansion of the livestock sector in developing countries and elsewhere.

References

  1. ↵ National Archives and Records Administration, Records of the Bureau of Animal Industry, Chief of the Bureau to Fitts, 9 July 1920.
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Pedro Prieto on Population

Posted on May 7, 2015 by

[I haven’t always agreed with Pedro about population, but I think he’s right now. It’s too late to do anything about overshoot, and we probably could have never done anything about it because we are animals. Though still, it is a shame we couldn’t have had state level incentives like lower taxes or better education for families with 2 children or less, and lower immigration levels so that countries with high birth rates didn’t have escape valves, but it’s too late now. Given how the rich benefit from excess population by paying lower wages, and the Ponzi scheme of pensions and SSN requiring ever more workers, and businesses and religions to grow their customers, overshoot and dieoff were inevitable.  If there is a dim light, perhaps the length of the dark times will be less since the overshoot is so high. Alice]

May 7, 2015 Pedro replies within a thread about population

Evidence #1. Population is in global overshoot today.

Evidence #2. All living beings have, by nature, exponential reproduction capabilities and rates, limited only by the access to resources in their environment.

But I have always found difficult and sometimes immoral or even useless to suggest, propose, mandate, legislate, etc. to my fellow humans, how they should -must- proceed with their natural instincts to solve this imbalance. If we force humans by legal coercion to limit their natural reproduction capabilities, we are doing something wrong, in my opinion.

Disclaimer #1. I am fully respectful for couples freely deciding to have an offspring below the minimum reproduction rate to sustain the species (below 2.2 per couple, for instance, as an average).

Disclaimer #2. I am also very respectful with couples that freely decide not to have babies.

Disclaimer #3. I am finally very respectful for couples that voluntarily take, if available to them, whatever the contraceptive methods.

But I believe we are totally mistaken when we plan to force millions of couples to “decouple” from their natural instincts and put in place policies like the “one child policy” in China. The fact that some demographers still believe it was a success (now it is being abandoned), because otherwise China could have today some 400 million inhabitants than the 1.3 billion of today, is not sufficient evidence that this type of policies are going to the heart of the population overshoot. It is only a temporal delay.

I am contrary, absolutely contrary, to sending missionaries or doctors to impoverished countries to sterilize women without their informed consent, with the alibi of attending them in giving birth or just launching preservatives with how to use pamphlets from planes, to populations that are rather waiting vaccines, aspirins, potable water or means to have it, anti-diarrhea pills or just a barefoot doctor. First things first.

If we are in overshoot, we would require, to this effect, to know first HOW MUCH we are in overshoot.

Then, in second place, we would need to understand WHY something that was not needed for 2 million years (reproduction legal coercion) is now needed or badly needed and if it the proposed measures have some sense or minimum possibility to succeed.

The most probable answer to this second question is that the core of the population overshoot lies more in our reversible industrial and technological way of living (even in our agricultural way of living), than in our irreversible natural way of reproduction in itself.

This will bring then the question of what way of living we think we aspire to for a given population.

Nate projects a chart, in some of his presentations, on the evolution of live beings since the Earth was formed (credit from William Stanton). We had never been in global overshoot ever before to the best of anthropological knowledge. Perhaps we were in overshoot in some specific, limited areas or regions and for a limited human groups and in a very limited period of time.

We have managed to live without overshoot all the period through which we evolved from erectus to habilis then to sapiens and then to sapiens-sapiens, when clearly differenced from non human great apes. During all this long period of time, a) we managed very well to survive as species and also managed, in all our absolute savageness (Rousseau), to respect other species (of course not individuals of other species we hunted or gathered for our own survival).

 

And we kept, very well, in a stationary population level of few hundred of thousands or at most very few million individuals within our particular species.

 

What Stanton called the “human population spike” it is a modern deadline since we started to manage agriculture and domesticate animals, about 10,000 years ago. Then, we had a spike within the spike with the fossil fuel powered machines about 150 years ago and finally a hyper spike within the spike about 30-50 years ago, with the technological advent.

I am very much convinced that we are going to return, sooner than later, to a stationary population level of the order of magnitude previous to the Stanton population spike. Difficult and dramatic as it may seem, I hope and wish humans will be able at least to keep at the original levels, rather than disappearing.

That is why I cannot understand very well the worries and concerns of many in developed countries, about global population growth per se.

The drama of falling from 7.2 or perhaps 8 billion, depending on the population inertia, to few hundreds of thousands or few millions is going to last perhaps one or two generations. That is all –and it won’t be little in human suffering-. Then, we will return to normality for another (I hope so) long period of time.

The present global population status is an obvious anomaly, for which we cannot blame Yanomamis in the Amazonia, Jivaros in Africa or Asmat in Irian Jaya or hunter gatherers having an offspring as large as they can, when nature takes the decision to balance it to the sustainable level.

The anomaly, in my opinion, resides more in the model of society we have created and that even most of the environmentalists hate to abandon or give up, than in trying to stay in this ultra consumerist society and correct or suppress the natural exponential reproduction capabilities to avoid the unavoidable.

Posted in Pedro Prieto, Population | Tagged , , | 1 Comment

The Banking system is a House of Cards

Posted on May 2, 2015 by

Lynn Parramore. April 21, 2015. Our Banking System is a Giant House of Cards. Money & Banking.

It Could Fall On You.

Anat Admati teaches finance and economics at the Stanford Graduate School of Business and is co-author of The Bankers’ New Clothes, a classic account of the problem of Too Big to Fail banks.

On May 6th, at the Finance and Society Conference sponsored by the Institute for New Economic Thinking, she will join Brooksley Born, former chair of Chair of the Commodities Futures Trading Commission, to discuss how effective financial regulation can make the system work better for society.

Seven years after the worst financial crisis since the Great Depression, Admati warns that we are not doing nearly enough to confront a bloated, inefficient, and dangerous financial system. The system can’t fix itself. Here’s what you need to know.

Lynn Parramore: How would you describe the problem of Too Big to Fail banks. Whey does it matter to an ordinary person?

Anat Admati: Too Big to Fail is a license for recklessness. These institutions defy notions of fairness, accountability, and responsibility. They are the largest, most complex, and most indebted corporations in the entire economy.

We all have to be really alarmed by the fact that not only do we still have such institutions, but many of them are ever-larger and more complex and at least as dangerous, if not more so, than they were before the financial crisis.

They are too big to manage and control. They take enormous risks that endanger everybody. They benefit from the upside and expose the rest of us to the downside of their decisions. These banks are too powerful politically as well.

As they seek profits, they can make wasteful and inefficient loans that harm ordinary people, and at the same time they might refuse to make certain business loans that can help the economy. They can even break the laws and regulations without the people responsible being held accountable. Effectively we’re hostages because their failure would be so harmful. They’re likely to be bailed out if their risks don’t turn out well.

Ordinary people continue to suffer from a recession that was greatly exacerbated or even caused by recklessness in the financial system and failed regulation. But the largest institutions, especially their leaders — even in the failed ones — have suffered the least. They’re thriving again and arguably benefiting the most from efforts to stimulate the economy.

So there’s something wrong with this picture. And there’s also increasing recognition that bloated banks and a bloated financial system – these huge institutions—are a drag on the economy.

LP: Have we made any progress in dealing with the problem?

AA: The progress has been totally unfocused and insufficient. Dodd-Frank claims to have solved the problem and it gives plenty of tools to regulators to do what needs to be done (many of these tools they actually already had before). But this law is really complex and the implementation of it is very messy. The lobbying by the financial industry is a large part of the reason that the law has been implemented so poorly and inefficiently with so much difficulty. We are failing to take simple steps and at the same time undertaking extremely costly steps with doubtful benefits.

So we’ve had far from enough progress. We are told things are better but they are nowhere near what we should expect and demand. Much more can be done right now.

LP: Banks, compared to other businesses, finance an enormous portion of their assets with borrowed money, or debt – as much as 95%. Yet bankers often claim that this is perfectly fine, and if we make them depend less on debt they will be forced to lend less. What is your view? Would asking banks to rely more on unborrowed money, or equity, somehow hurt the economy?

AA: Sometimes when I don’t have time to unpack everything I use a quote from a book called Payoff: Why Wall Street Always Wins by Jeff Connaughton. He relates something Paul Volcker once said to Senator Ted Kaufman: “You know, just about whatever anyone proposes, no matter what it is, the banks will come out and claim that it will restrict credit and harm the economy…It’s all bullshit.”

Here’s one obvious reason such claims are, in Volcker’s vocabulary, bullshit: Lending suffered most when banks didn’t have enough equity to absorb their losses in the crisis — and then we had to bail them out. The loss they suffered on the subprime fiasco was relatively small by comparison to losses to investors when the Internet bubble burst, but there was so much debt throughout the system, and indeed in the housing markets, and so much interconnection that the entire financial system almost collapsed. That’s when lending suffered. So lending and growth suffers when the banks have too little equity, not too much.

Now, banks naturally have some debt, like deposits. But they don’t feel indebted even when they rely on 95% debt to finance their assets. No other healthy company lives like that, and nobody, even banks, needs to live like that — that’s the key. Normally, the market would not allow this to go on; those who are as heavily indebted feel the burden in many ways. The terms of the debt become too burdensome for corporations, and reflect the inefficient investment decisions made by heavily indebted companies. But banks have much nicer creditors, like depositors, and with many explicit and implicit guarantees, banks don’t face trouble or harsh terms. They only have to convince the regulators to let them get away with it. And they do.

So the abnormality of this incredible indebtedness is that they get away with it. There’s nothing good about it for society. If they had more equity then they could do everything that they do better —more consistently, more reliably, in a less distorted fashion.

Today’s credit market is distorted. A key reason is that bankers love the high risk and chase returns. They are less fond of some of the lending where they are needed the most — like business lending, for example. Instead, most people get many credit cards in the mail and too many people live on expensive revolving credit. Effectively, the poor may end up subsidizing the credit card of the person who pays on time and has zero interest (and we all end up paying the enormous fees merchants are charged). So we can have too much or too little lending and live through inefficient booms and busts. Part of the reason for that is that banks are continually living on the edge in a way that nobody else in the economy would, and regulations meant to correct it are insufficient and flawed in their design.

LP: Banking has been a very profitable business. Is it profitable because the risks are born by the taxpayer? Do you think the bank bonus system is part of the problem?

AA: Yes, banking is partly profitable because of subsidies from taxpayers. There are probably other reasons, and not all of them good ones, in terms of the way competition works and other things. The bonus system encourages recklessness, and recklessness increases the value of the subsidies from taxpayers. Bankers are effectively paid to gamble.

It is profitable for the banks to become big even when this is inefficient, because they can do so with subsidized borrowing on easy terms. Guarantees, explicit and implicit, are a form of free or subsidized insurance. We don’t control whether what banks do with the cheap funding benefits the economy or just bankers and some of their investors. We must reduce these large subsidies that end up rewarding recklessness and harming us. (See Admati’s July 2014 testimony before Congress on bank subsidies).

LP: We often hear about financial innovations that helped bring the global economy to its knees in 2008. Back in December, Congress rolled back a key taxpayer protection concerning derivatives, which Robert Lenzner of Forbes Magazine called a “Christmas present for the banks.” What do Americans need to know about derivatives? How do they affect the Too Big to Fail problem?

AA. The Christmas present was just one more small thing in a much bigger problem. The largest financial firms in America can hide an enormous amount of risk in derivatives. That’s very dangerous because it makes banks more interconnected, since much of the derivatives trading happens within the financial system. It creates a house of cards — a very fragile system.

We also have bankruptcy laws in this country that perversely give unusual priority to derivatives contracts and other reckless practices.

Derivatives exacerbate Too Big to Fail dramatically because there’s so much opacity in the system. Policy-makers get scared into bailing our or guaranteeing a lot of their commitments made in those markets because they won’t quite know the consequences of letting them fail. It’s very intimately related to Too Big to Fail. It’s as if they hold a gun to your head. You don’t know whether they have bullets so you may get scared into paying the ransom.

LP: Is breaking up the banks is a solution?

AA: People say those words but what does it mean? How would you do it? That’s the big problem. Banks are multiple times bigger than most of the corporations you think of as big. I once made a mistake rushing through a HuffPost piece in 2010 saying that Jamie Dimon wants to be as big as Walmart. Well, at the time, JP Morgan was already 10 times bigger than Walmart by assets! When it comes to the financial sector, big is really big. People don’t even appreciate how big we’re talking about. Nobody else gets to be as big, and in fact, In other parts of the economy, companies that get so big often break up on their own. But that doesn’t happen in banking partly because of the perverse subsidies taxpayers provide.

The most sensible approach is to force banks and other financial institutions to have more equity, which is actually going to expose their inefficiencies and bring more investor pressure for a break-up to happen naturally without us doing it actively. Regulators can also put significantly more pressure on banks to simplify their structure and divest unnecessary lines of businesses such as commodities (energy, aluminum, etc.). The size appears unmanageable and makes regulation difficult.

LP: What would make banking regulation more effective?

AA: First of all there could be simpler regulation in some places and some cost-ineffective things could be used a bit less. Right now, we know too little about the risk and we have too little margin for error. We must reduce the opacity and increase the safety margins dramatically. Regulators make it complicated because we are unnecessarily living at the edge of a cliff all the time. We live so dangerously! There’s no need for that. We are told that we have to live like that, but it’s that’s completely false. The system has to be made a lot more resilient. Then we can worry less and sleep better.

In addition to making things simpler, it’s very important that we are able to see more of the risk and then to enforce much stronger and simpler rules. And, of course, regulators need to be watching where the risks are going. They should not believe that just because the risks are off the accounting balance sheets that they are gone. That was a trick to get around regulations and get around accounting rules in cases like Enron. A lot of the risks were hiding — but they can be traced. Some laws that are counterproductive and make regulation harder should also be examined, including the tax code that encourages debt over equity, and the bankruptcy law that overly protects certain financial practices.

LP: If we don’t deal with the problem of Too Big to Fail, what happens?

AA: An ordinary person doesn’t realize it, but the impact of this unhealthy system on them happens every day. It’s doesn’t feel as acute as something like leakage from a nuclear facility because harm from the financial system is a little more abstract. You only see it when it blows. But it’s an unhealthy, inefficient, bloated and dangerous system. Because this system is so fragile, it can implode again, and our options next time will be dire again. We will either suffer a lot or bail out the system to suffer a little bit less.

I recently shared with my students a quote by the Rothschild brothers of London, writing to associates in New York in 1863: “The few who understand the system will either be so interested in its profits or be so dependent upon its favours that there will be no opposition from that class, while the great body of people, mentally incapable of comprehending the tremendous advantage that capital derives from the system, will bear its burdens without complaint, and perhaps without even suspecting that the system is inimical to their interests.”

This is a great quote! We get tricked into thinking that we have a great financial system because we have our credit cards and whatnot. We don’t see the enormous risks that are taken in derivatives markets and some of the other practices that can topple the entire system again and which extracts fees and bonuses. The truth is that we can have a safer system that serves the economy and society better. But getting there requires that better laws and regulations are implemented and enforced. The system will not correct itself; we must demand that policymakers do a better job for the public.

 

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David Hughes: Has Well Productivity Peaked in the Nation’s Largest Shale Gas Play, the Marcellus?

Posted on April 29, 2015 by

[This is big news since other major plays have already peaked.  It looks like the Marcellus is on Hughes predicted by 2018 peak with the latest data published]

Has Well Productivity Peaked in the Nation’s Largest Shale Gas Play?

By David Hughes, April 28, 2015. Postcarbon.org

The Marcellus shale gas play of Pennsylvania and West Virginia came onto the scene in 2007 in a big way and has grown to become the nation’s largest. It has accounted for much of the growth of U.S. shale gas production, and made up for declines in former shale gas giants like the Haynesville and Barnett plays of Louisiana and eastern Texas. Companies have scrambled to build pipeline infrastructure to connect the Marcellus to consumers in the U.S. northeast. Canadians, once supplied by gas from western Canada, are also looking to the Marcellus (and the much smaller Utica play in Ohio) for future supply; the pipelines that delivered gas to the east might be converted to instead deliver bitumen from the western tar sands. Companies in both the northeastern U.S. and eastern Canada are looking to build LNG terminals to export the shale gas bounty, and the first LNG export terminal on the Gulf coast will open later this year.

The prognosis for the Marcellus is therefore very important, as it is being counted on to supply abundant cheap gas to the northeast and elsewhere for decades to come. One of the big problems in figuring out what is happening with the Marcellus is the tardiness with which the states provide production data to the general public and to data vendors such as Drillinginfo, which I utilize extensively to analyze shale plays. West Virginia provides data in one-year chunks, and won’t release what happened in 2014 until mid-2015. Pennsylvania is somewhat better, releasing data in six-month chunks. In the absence of recent accurate production data, there has been much speculation on Marcellus production using proxies such as pipeline receipts and algorithms to estimate what production might be. Pennsylvania’s recent release of data from the last half of 2014, however, provides an opportunity to take an updated look at the Marcellus, considering that Pennsylvania comprises 85% of Marcellus production.

In my recent Drilling Deeper report, I looked at Marcellus data through mid-2014 with a view to determining what future production might look like. Critical observations included:

  • Field decline averages 32% per year without drilling, requiring about 1000 wells per year in Pennsylvania and West Virginia to offset.
  • Core counties occupy a relatively small proportion of the total play area and are the current focus of drilling.
  • Average well productivity in most counties is increasing as operators apply better technology and focus drilling on sweet spots.
  • Production in the “most likely” drilling rate case is likely to peak by 2018 at 25% above the levels in mid-2014 and will cumulatively produce about what the Energy Information Administration (EIA) projected through 2040. However, production levels will be higher in early years and lower in later years than the EIA projected, which is critical information for ongoing infrastructure development plans.

The following analysis provides updates using all available production data for 2014 and reveals:

  • The EIA overestimates Marcellus production by between 6% and 18%, for its “Natural Gas Weekly” and “Drilling Productivity” reports, respectively.
  • Five out of more than 70 counties account for two-thirds of production. Eighty-five percent of production is from Pennsylvania, 15% from West Virginia and very small amounts from Ohio and New York. (The EIA has published maps of the depth, thickness and distribution of the Marcellus shale, which are helpful in understanding the variability of the play.)
  • The increase in well productivity over time reported in Drilling Deeper has now peaked in several of the top counties and is declining. This means that better technology is no longer increasing average well productivity in these counties, a result of either drilling in poorer locations and/or well interference resulting in one well cannibilizing another well’s recoverable gas. This declining well productivity is significant, yet expected, as top counties become saturated with wells, and will degrade the economics which have allowed operators to sell into Appalachian gas hubs at a significant discount to Henry hub gas prices.
  • The backlog of wells awaiting completion (aka “fracklog”) was reduced from nearly a thousand wells in early 2012 to very few in mid-2013, but has increased to more than 500 in late 2014. This means there is a cushion of wells waiting on completion which can maintain or increase overall play production as they are connected, even if the rig count drops further.
  • Current drilling rates are sufficient to keep Marcellus production growing on track for its projected 2018 peak (“most likely” case in Drilling Deeper).

Production

Figure 1 illustrates production from the Marcellus through December 2014 compared to estimates from the EIA. Total production was about 13.7 billion cubic feet per day (bcf/d). Estimates from the EIA for December are 14.5 and 16.1 bcf/d for its “Natural Gas Weekly” and “Drilling Productivity” reports, respectively. The Utica play of Ohio and western Pennsylvania also added an estimated 1.9 bcf/d to northeast supply in December, for a total of 15.6 bcf/d. This compares to claims of more than 19 bcf/d by some analysts, an overestimate of 22%.

Marcellus Production Figure01

Figure 1 – Production from the Marcellus based on well production data through December, 2014, for Pennsylvania, and well production data through December, 2013, for West Virginia (2014 WV production is estimated assuming the continuation of growth rates observed in the latter half of 2013). Also shown for comparison are EIA estimates from its “Natural Gas Weekly” and “Drilling Productivity” reports, and the number of producing wells.

Marcellus gas production is highly concentrated in a few counties out of the more than 70 counties that have some production, as illustrated in Figure 2. Three counties account for nearly half of the play’s production, five counties account for two-thirds, and 12 counties account for 90%. Drilling is concentrated in the top counties which have the greatest economic payback; the cheapest gas is being produced, now leaving the expensive gas for later.

Marcellus Production Figure02

Figure 2 – Production by county for the top 15 counties in the Marcellus play illustrating the highly concentrated nature of production in sweet spots. The total number of counties with at least some Marcellus production is more than 70.

New maps published by the EIA (reproduced in Figure 3) illustrate two key Marcellus play parameters: elevation (from which one can determine depth) and thickness (an indicator of potential reservoir volume and gas concentration per unit area). These maps show the variability over the play’s extent and why it is not surprising that production is concentrated in relatively small core areas. Other parameters which factor into productivity include organic matter content, thermal maturity, presence of natural fractures, sediment composition in terms of its ability to propagate fractures, pressure, gas saturation, permeability and porosity.

Sweet spots have the most favorable combination of these parameters and are clearly concentrated in northeast Pennsylvania, northern West Virginia southwest Pennsylvania, as illustrated in Figure 4. The play’s future production trajectory depends on drilling rates and trends in well productivity as sweet spots become saturated with wells and drilling moves into lower-quality rock.

Marcellus Production Figure03

Figure 3 – Elevation (top) and thickness (bottom) of the Marcellus shale. The thickness controls the volume of the potential reservoir and potential gas distribution and the elevation determines reservoir depth which controls pressure and other critical parameters. From EIA, April, 2015.

Marcellus Production Figure04

Figure 4 – Distribution of wells in Marcellus play as of mid-2014, illustrating highest one-month gas production (from Drilling Deeper Figure 3-80).

Drilling Rates

Drilling rates and well productivity are key factors in offsetting the unceasing decline of existing wells (field decline), which in the Marcellus amounts to 32% of the play’s production that needs to replaced each year through more drilling. At the time of publication of Drilling Deeper, offsetting field decline in the Marcellus as a whole required 1,003 new wells per year, and in Pennsylvania 899 wells per year. Production is now about 10% higher but the productivity of wells has also increased on average such that the number of wells needed to offset field decline in Pennsylvania is still just over 900 per year.

Figure 5 illustrates the drilling rate in Pennsylvania and the average amount of gas added to the play’s production for each new well drilled. The current rate of about 1,050 wells per year is sufficient, should it continue, to see production rise overall until it is 15% above current levels.

Marcellus Production Figure05

Figure 5 – Annual number of producing wells added and Marcellus play production added per new well from 2007 through December 2014 in Pennsylvania.

Another important factor is wells that have been drilled but not completed, or wells waiting on a pipeline connection. A major issue in the Marcellus has been the lack of takeaway capacity as gathering pipelines must be constructed to new wells and larger pipelines constructed to markets. Another strategy, purportedly widely used, is to drill wells without completing them, putting them in abeyance until prices are higher; as the cost of hydraulic fracturing is half or more of the total cost of a well, this practice allows producers to get a head start while rig costs are low due to the number of rigs looking for work as a result of the drop in oil prices.

Figure 6 illustrates a comparison of the rate at which wells are spudded (based on well permits) and the rate at which new producing wells are added to the play. From this it is apparent that a large backlog of drilled but not connected wells was worked off in late 2012 through 2013; the backlog has since grown again, however, with 550 more wells drilled than connected in the 12 months prior to December, 2014. The current rig count in the Marcellus is down 50% from its highs in early 2012, so even with improved rig efficiency and the ability to drill more wells per unit of time, falling rig count will ultimately limit drilling rates and impact play production.

Marcellus Production Figure06

Figure 6 – Comparison of the annual rate of wells spudded to producing wells added each year to the Marcellus in Pennsylvania, illustrating the backlog of wells waiting to be connected to production infrastructure.

Well Productivity

Well productivity is key to maintaining and growing Marcellus production, which is a function of new well productivity times drilling rate minus field decline, and to the economics of drilling the wells. We were told the following at this year’s Ceraweek conference by a Marcellus operator:

Not only are we drilling longer wells, not only are we drilling them more cheaply, but we’re getting more recovery. Today, we’re drilling the best wells we’ve ever drilled. Some of it is advances in technology. Some of it is advances in our ability, and some of it is geology — we’re in areas where we have the ability to drill longer laterals. So you can see the problem. As gas prices come off… we continue to do better and better at drilling wells.

Is this really true? The answer varies depending on where an operator’s land holdings lie and the maturity of their development. Figure 7 illustrates daily well productivity over the highest month, first 6 months, first 12 months and first 24 months for all producing wells drilled in the Marcellus in Pennsylvania from January 2010 to December 2014. It is certainly true that productivity has increased markedly over this period up to early 2014 but has decreased since, suggesting the tide has turned in the inexorable battle between technology and geology.

Marcellus Production Figure07

Figure 7 – Average daily production for all wells drilled in the Marcellus play between 2010 and December 2014. Dots indicate production over each well’s highest month (red), first 6 months (yellow), first 12 months (green), and first 24 months (blue). Lines indicate average daily production for all wells at these same points in time of well life (polynomial best-fit trend lines).

Figure 8 accentuates trends in well productivity in the Marcellus by fitting a moving average to the data. This figure indicates that:

  • Well productivity increased by 70% between early 2012 and early 2014. This is a testament to both better technology and focusing on sweet spots.
  • Productivity peaked in mid-2014 and has fallen in the last half of 2014.
  • Highest month productivity is a key indicator of productivity over the longer term, as it is reflected in 6 month-, 12 month- and 24 month-average production.

Marcellus Production Figure08

Figure 8 – Average daily production for all wells drilled in the Marcellus play between 2011 and December 2014. Data have been fitted with a trailing 150-well moving average to make the trends more apparent. Dots indicate production over each well’s highest month (red), first 6 months (yellow), first 12 months (green), and first 24 months (blue). Lines indicate average daily production for all wells at these same points in time of well life (polynomial best-fit trend lines).

It is instructive to examine comparable data for the most productive and densely drilled counties, as these will be the first to experience saturation of available drilling locations (the top four counties are analyzed below).

Susquehanna County

Susquehanna is the top producing county and also has the highest average well productivity. It is second only to Bradford County in terms of the number of wells drilled. Figure 9 illustrates average daily well production in Susquehanna County over various periods. This figure indicates that:

  • Well productivity nearly doubled from early 2012 until late 2013 but has declined by nearly 20% during 2014. Susquehanna wells are still the top producers in the play.
  • The fall-off in well productivity is likely due to the density of current drilling (resulting in early signs of well interference) and to drilling more marginal parts of the county.
  • Geology appears to be trumping technology in Susquehanna County, which is the most productive of the play. Well density was 1.48 wells per square mile in mid-2014 (see Table 3-5 in Drilling Deeper) with the assumption that 4.3 wells per square mile could be drilled; this may be overly optimistic.

Marcellus Production Figure09

Figure 9 – Average daily production for all wells drilled in Susquehanna County between 2011 and December 2014. Data have been fitted with a trailing 50-well moving average to make the trends more apparent. Dots indicate production over each well’s highest month (red), first 6 months (yellow), first 12 months (green), and first 24 months (blue). Lines indicate average daily production for all wells at these same points in time of well life (polynomial best-fit trend lines).

Bradford County

Figure 10 illustrates average daily well production in Bradford County over various periods. This figure indicates that:

  • Well productivity increased by 50% from early 2012 until early 2014 but has declined by more than 10% since then. Bradford County has the most producing wells in the play.
  • The fall-off in well productivity is likely due to the density of current drilling, resulting in early signs of well interference, and to drilling more marginal parts of the county.
  • Geology appears to be trumping technology in Bradford County. Well density was 1.22 wells per square mile in mid-2014 with the assumption that 4.3 wells per square mile could be drilled; this may be overly optimistic.

Marcellus Production Figure10

Figure 10 – Average daily production for all wells drilled in Bradford County between 2011 and December 2014. Data have been fitted with a trailing 50-well moving average to make the trends more apparent. Dots indicate production over each well’s highest month (red), first 6 months (yellow), first 12 months (green), and first 24 months (blue). Lines indicate average daily production for all wells at these same points in time of well life (polynomial best-fit trend lines).

Lycoming County

Figure 11 illustrates average daily well production in Lycoming County over various periods. This figure indicates that:

  • Well productivity increased by 100% from early 2011 through 2014 but appears to be decreasing as of late 2014. Lycoming County is now second only to Susquehanna in average well productivity and third overall in production.
  • It is too early to say if growth in well productivity in Lycoming County has stalled out but it appears likely. Well density was 1.35 wells per square mile in mid-2014.

Marcellus Production Figure11

Figure 11 – Average daily production for all wells drilled in Lycoming County between 2011 and December 2014. Data have been fitted with a trailing 30-well moving average to make the trends more apparent. Dots indicate production over each well’s highest month (red), first 6 months (yellow), first 12 months (green), and first 24 months (blue). Lines indicate average daily production for all wells at these same points in time of well life (polynomial best-fit trend lines).

Washington County

Figure 12 illustrates average daily well production in Washington County over various periods. This figure indicates that:

  • Well productivity increased by 100% from late 2012 until early 2014 but has declined by about 10% since then. Washington County produces wet gas and most of the liquids in the Marcellus. It has generally lower well productivity than the top three counties but the liquids production has bolstered the economics.
  • The fall off in well productivity is likely due to the density of current drilling, resulting in early signs of well interference, and to drilling more marginal parts of the county.
  • Geology appears to be trumping technology in Washington County. Well density was 1.28 wells per square mile in mid-2014 with the assumption that 4.3 wells per square mile could be drilled; this may be overly optimistic.

Marcellus Production Figure12

Figure 12 – Average daily production for all wells drilled in Washington County between 2011 and December 2014. Data have been fitted with a trailing 50-well moving average to make the trends more apparent. Dots indicate production over each well’s highest month (red), first 6 months (yellow), first 12 months (green), and first 24 months (blue). Lines indicate average daily production for all wells at these same points in time of well life (polynomial best-fit trend lines).

Future Production

At this point there is little reason to change the “most likely” production trajectory for the Marcellus published in Drilling Deeper (reproduced in Figure 13), other than to say it may be a bit too optimistic as drilling rates including West Virginia have fallen below the 1320 wells per year assumed (although not by much). If drilling rates fall significantly from current levels the play will peak sooner and declines will lessen after peak. Also, the observed decline in well productivity in top counties suggests that drilling densities of 4.3 wells per square mile may be too optimistic which, if so, would serve to further reduce ultimate recovery, result in more rapid declines in well productivity than assumed, and further lower production rates after peak.

Marcellus Production Figure13

Figure 13 – Projection of future Marcellus production (“most likely” case from Drilling Deeper Figure 3-99). Cumulative recovery through 2040 is estimated at 129 tcf, which is more than 10 times the 12.6 tcf recovered to date.

Summary and Implications

Central points from this analysis include:

  • The northeastern U.S. and eastern Canada are counting on abundant cheap gas from the Marcellus and Utica plays for the foreseeable future, based in part on rosy projections from the EIA that expects production to grow well into the next decade. Large investments are being made in infrastructure to transport and use this gas, including pipelines, processing plants, LNG export terminals, gas-fired generation and other residential, commercial and industrial uses. Like other shale gas plays, Marcellus wells exhibit steep production declines and the play has a field decline of 32% per year that must be offset by continuous drilling. In Pennsylvania this amounts to more than 900 wells per year simply to maintain production at current levels.
  • The Marcellus play, although very large, has two-thirds of its production concentrated in 5 of 70+ counties. Although top counties have generally seen impressive increases in new well productivity over the past three years due to improved technology, most have exhibited declines in well productivity in 2014, with the top county, Susquehanna, down 20%. This is likely a result of well interference and/or moving to poorer quality locations within these counties, which suggests the assumption of a final well density of 4.3 wells per square mile may be too optimistic.
  • Although production will likely grow over the next two years, barring a radical reduction in drilling rates from current levels, projections of a peak in 2018 appear on track, followed by a terminal decline (which assumes gradual increases in price; sudden major increases in price could temporarily check this decline if reflected in significantly increased drilling rates). The backlog of wells waiting on connection to infrastructure will shield production from falling for some months should there be a large drop in rig count.
  • Industry invariably drills its best prospects first, hence the cheapest gas is being exploited now. Infinite faith in technology cannot make up for the realities of geology. These realities are showing up now in the most productive counties.
  • As for the massive investments in infrastructure on the assumption of cheap and abundant gas for the foreseeable future – CAVEAT EMPTOR.
Posted in Other Experts | Comments Off on David Hughes: Has Well Productivity Peaked in the Nation’s Largest Shale Gas Play, the Marcellus?

Natural Gas limits: 20-40% of recoverable resources are low EROI Sour Gas

Posted on April 27, 2015 by

SBC. October 2014. Factbook Natural Gas Factbook. SBC Energy Institute

Sour gas

 

 

 

 

 

 

 

 

 

 

 

 

 

There are 855 trillion cubic meters (tcm) of technically recoverable resources, which means that regardless of cost we could get at them, and would last 240 years at the current rate of 3.5 tcm produced per year — but 20 to 40% are sour and very expensive and difficult to produce, reducing the resource to 145 to 195 years.

In some fields, contaminants can be found in very high concentrations. This increases investment needs and production costs to the extent that production may even be rendered uneconomic. Natural gas rich in hydrogen sulfide (H2S) or carbon dioxide (CO2) is called sour gas or acid gas. CO2 and H2S are both extremely corrosive and H2S is also toxic. When these gases are present, special equipment is needed (e.g. special alloys for tubing and piping) to ensure that the natural gas can be safely transported and processed, prior to being sold.

20-40% of global recoverable gas resources could be considered, to varying degrees, to be sour gas, especially in the Middle East and Central Asia, but also in North America, Australia and Russia. Even if sour gas fields have a long history of successful development in several places, lowering the costs of sour-gas operation is essential if its potential is to be fully tapped. This could be through innovation in gas-separation technologies used in processing plants or more advanced deployment of capture and re-injection, including enhanced oil recovery.

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Coal or Biomass & Coal to Liquids: CTL, DCL, & CBTL technology

Posted on April 26, 2015 by

Gray, D., et al. August 1, 2012.  Topic Paper #8 Production of Alternative Liquid Hydrocarbon Transportation Fuels from Natural Gas, Coal, and Coal and Biomass (XTL). National Petroleum Council

CTL plant configuration

CTL plant configuration

Background

With national energy security still being a dominant concern because of increasing dependence on imported oil, there is interest in producing more of our oil from domestic sources. By far the largest single supplier of oil to the U.S. is Canada. But, we must be concerned that an equal amount of imports comes, in total, from four countries wracked by instability or with governments hostile to the U.S.: Algeria, Angola, Iraq, and Venezuela.

In addition, the global trade in oil means that, even though the U.S. imports no oil from Iran, and little from Libya, if further unrest in the Middle East should happen to take Iranian and/or Libyan crude off the world market for a time, global oil prices would skyrocket, directly impacting the American economy. Oil is truly the life blood of any industrialized society. Without it, continued and sustained economic growth and social stability would be impossible. Oil provides us with transportation fuels that give us the freedom of personal mobility. About two-thirds of petroleum consumption in the U.S. is in the transportation sector; from the other perspective, some 95-97% of transportation energy derives from petroleum. A second aspect of the vital importance of petroleum is that it provides key petrochemicals for plastics, urethanes, and synthetic fibers. This application accounts for an estimated 16% of petroleum used in the U.S., and over 25% of petroleum processed in the Gulf Coast region.

XTL is coal and/or biomass liquefactoin via Fischer Tropsch synthesis

XTL is the conversion of carbonaceous feedstocks to a mixture of hydrogen and carbon monoxide, called synthesis gas, followed by the separate step of producing liquid hydrocarbon fuels from the gas via Fischer-Tropsch synthesis. In principle, any carbonaceous feedstock could be used (given appropriate technology for its conversion to synthesis gas), including biomass, coal, coal/biomass blends, natural gas, municipal solid waste, natural bitumens and heavy oils, and waste tires. Synthesis gas conversion technologies also offer potential routes to hydrogen, substitute natural gas, and various solvents or intermediates such as alcohols and aldehydes.

How DCL differs from XTL

The principal alternative to XTL is direct coal liquefaction (DCL), which is the conversion of coal to liquids without the intervening step of producing synthesis gas. The primary DCL technology is hydroliquefaction, the reaction of coal with hydrogen and/or a hydrogen-donor solvent, usually in the presence of a catalyst. Liquids can also be obtained from coal by pyrolysis, and by solvent extraction with various solvents in the sub- or supercritical regimes. Some work has been done on the co-liquefaction of coal blended with materials such as scrap plastic, scrap rubber, or heavy oils. A second major difference between DCL and XTL is that usually XTL products are clean liquids that can be used as transportation fuels with minimal refining, whereas the primary liquids from DCL are usually aromatic with nitrogen, oxygen, and/or sulfur incorporated, so will require substantial downstream refining to meet performance and environmental requirements for transportation fuel usage.

The Shenhua Process The world’s only commercial-scale hydroliquefaction plant is the so-called Shenhua plant, built by the Shenhua Group Corporation in Majata, Inner Mongolia. The Shenhua process represents evolutionary development of earlier work beginning with the H-Coal process (Hydrocarbon Research, Inc.), with further improvements by Hydrocarbon Technology Inc. and Headwaters. Bituminous coal is slurried with recycle solvent and catalyst. The slurry is fed to a liquefaction reactor (the largest one ever built, with a 6000 ton/day capacity), followed by solid-liquid separation. The primary liquids are hydrotreated to produce primarily diesel fuel and naphtha, in amount of 24,000 barrels per day. On an annual basis, the Shenhua plant expects to utilize about 3.5 million metric tons of coal, producing 715,000 metric tons of diesel fuel, 250,000 metric tons of naphtha, 120,000 metric tons of LPG, and about 3,500 metric tons of phenols. On a dry, ash-free basis, about 57% of the coal is converted to liquids.

There are no Coal/Biomass CBTL plants

CBTL process

CBTL process

The concept of gasifying mixtures of coal and biomass together in the same plant to produce liquid fuels is novel and no such plant currently exists. There are many gasifiers that can gasify biomass but most of these are usually small scale, use air instead of oxygen, operate at lower temperatures thus producing tars, and operate at low or atmospheric pressure. All of those characteristics would make them unsuitable for producing FT liquid fuels.

CTL technology has a proven track record and is technically viable. However, although Sasol has successful commercial plants in operation, the integration of modern entrained-flow coal gasification with advanced FT synthesis has yet to be demonstrated commercially. There are no commercial or even small scale plants are currently in operation to convert mixtures of coal and biomass to liquid fuels.

If a CBTL plant did exist it would work like this

The plant would operate just like a CTL plant except that biomass is gasified in addition to the coal. Separate gasifiers could theoretically be used for the biomass and the coal; however it may be more efficient and less costly if the same gasifier could convert both feeds simultaneously. This would be similar to the situation at NUON where the Shell gasifier was able to gasify both wood and biomass. In this conceptual plant, high pressure, entrained-flow gasification with oxygen is used to convert the coal and biomass into synthesis gas. This synthesis gas is cleaned using conventional gas cleaning technology. Slurry-phase FT reactors are used to convert the clean synthesis gas into raw FT products. Hydrotreating and hydrocracking/hydroisomerization are used to convert the raw FT products into naphtha and diesel. All power required in the plants is generated on-site. Unfortunately, there is very little data in the literature for the gasification of biomass in entrained high pressure gasifiers. Because of the fibrous nature of most biomass sources, the material is very difficult to pretreat and feed into a high pressure gasifier. Typical problems include clumping and bridging. However, the successful demonstration at the NUON plant does indicate that co- gasification is technically feasible provided that the biomass receives the appropriate pretreatment and preparation.

Barriers to XTL plants being built

Although the United States still imports about 11 MMBPD of oil from the unstable Middle East and other potentially hostile countries and world oil prices are currently hovering around $90 to $100 per barrel, no commercial U.S. XTL plants are being built. This is because of the considerable number of barriers to deployment of XTL. These barriers can be classified as technical, economic, environmental, commercial, and social.

Under economic barriers, the uncertainties about future oil prices are a significant barrier. The high capital expenditures needed for large scale CTL plants is a major barrier. It is anticipated that the capital for large (greater than 50,000 BPD) CTL plants will be over $150,000 -$160,000 per daily barrel. Therefore, a 50,000 BPD FT CTL plant could cost over $8 billion. The investment risk for such a large sum is considerable. For GTL the capital cost is lower but a 50,000 BPD plant would still require an investment of over $3.5 billion. Also for CBTL the cost of delivered biomass is very high.

Water use in CTL plants is also an important environmental issue particularly in geographical areas of low rainfall.

Significant deployment of CTL facilities will require the use of large quantities of coal and this will mean an expansion of the coal mining industry. For example, a 50,000 BPD CTL plant will use approximately 7 million tons of coal per annum. There is considerable opposition to increased coal mining. Another issue concerns actual commercial deployment of CTL. Who would take the lead in commercial deployment of XTL technologies?

If many XTL plants were to be built worldwide at the same time then there will be competition for critical process equipment and engineering and labor skills. There is already evidence that this bottleneck is being encountered worldwide because of the large number of simultaneous construction projects. Finally, there are the issues of permitting and the usual public reluctance to accept the need for new facilities especially coal based plants. Particular barriers to deployment of CBTL technologies include the high cost of biomass feedstock, the availability of sustainable quantities of biomass feed stock, the GHG and energy penalties associated with the cultivation, harvesting, and preparation of the biomass feed, the high cost of biomass transport, and the technical problems with feeding biomass to high pressure gasification systems.

If water availability presents no problems and water cooling is used for all applications the expected use would be in the range 7-10 barrels of water per barrel of liquid fuel product for CTL and CBTL plants. On the other hand, if water is scarce, in Western locations for example, then maximum use of air cooling could be made.

Because no FT CTL plants have been built since Sasols II and III in South Africa in the early 1980s, it is very difficult to accurately estimate the capital costs of new FT CTL plants that would be built in the U.S. in today’s economic climate. The tight EPC market has resulted in large escalations of capital costs for major projects. For example, costs for new IGCC plants are estimated to be over $4,000/kW compared to estimates of around $2,500/kW just a few years ago. Likewise, the costs for new Oil Sands projects in Canada have experienced escalations of 70% or more.

DCL deployment faces many of the same barriers that have already been identified and discussed in the XTL section of this white paper. These include the significant technical risks (especially given only one commercial-scale DCL plant running in the world, and that only for about two years) with the attendant question of who would take the lead in building the first plant(s); the very high capital expense, at least for hydroliquefaction, and the related investment risk; questions of permitting, which will be made all the more complicated by the antipathy of the public and many NGOs to coal; likely shortages of process equipment and skilled labor; the need for substantial expansion of the mining industry; and a need to deal with CO2 and other environmental issues.

The primary liquid from hydroliquefaction, carbonization, or solvent extraction is likely to be highly aromatic, also containing various compounds of oxygen, nitrogen, and sulfur. It will require significant downstream refining to produce liquid fuels that meet market and environmental specifications. These additional downstream processes will add capital and operating costs. These processes, especially hydroliquefaction, will consume substantial amounts of hydrogen. The likely way of obtaining hydrogen is via coal gasification. Not only does this also add to capex and opex, it implies that all of the various operations of a gasification plant must be embedded inside a hydroliquefaction plant. If one needs to install gasifiers and ancillary equipment anyway, perhaps XTL would be a better choice. Especially with low-temperature carbonization, and somewhat will solvent extraction, inevitably there will be a solid product containing unreacted or partially reacted coal and ash. Unless a use exists for the solid, it will be a major cost to collect and dispose of in an environmentally acceptable manner.

Barriers to economically successful, commercial-scale direct liquefaction of coal include:

  • Selection of materials of construction for reactor vessels and ancillary equipment, to withstand high-temperature, high- pressure hydrogen environments and abrasive coal or mineral slurries.
  • Finding an inexpensive and convenient source of process heat.
  • Finding an inexpensive source of hydrogen, ideally one that does not contribute to the carbon footprint.. Separation of coal mineral matter and unreacted or partially reacted coal particles from the process stream.
  • Subsequent post-liquefaction upgrading and refining of the “synthetic crude oil” from liquefaction into commercial-quality, marketable liquid fuels. It has been presumed that the primary liquids would be treated in the standard unit operations of an oil refinery, but there seems to be little verification of this. A related issue is that the final, upgraded products of DCL have been assumed to be fungible with the comparable petroleum-derived products. This point does not seem to be fully demonstrated either.

Estimated Economics for DCL Plants It has been nearly twenty years since a detailed economic analysis was done for hydroliquefaction, and possibly much longer for solvent extraction or carbonization. A hydroliquefaction plant capital cost, for coal being converted to clean, specification-grade transportation fuels, is likely in the range of $120,000 per daily barrel of capacity. Estimated cost of the finished liquid products is $0.20 per gallon higher than from a CTL plant. It should be noted that the estimated cost of $120,000 per daily barrel is about double of the claimed cost of the Shenhua plant ($62,500). The figure for the Shenhua plant was based on 2008 dollars; the world has seen significant increases in capital equipment prices since then. In addition, it is not clear what basis was used for conversion of yuan to US dollars. Therefore, this is not to say that one figure or the other is grossly in error, but they probably can be taken as “bookends” for the cost of a plant.

 

Posted in Coal to Liquids (CTL) | Tagged , , , | Comments Off on Coal or Biomass & Coal to Liquids: CTL, DCL, & CBTL technology

Better truck fuel efficiency to delay the end of the oil age

Posted on April 26, 2015 by

NAS. 2010. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles (National Academy of Sciences Study)

This free, 251 page document is one of the best I’ve seen on the myriad ways trucks could double their miles-per-gallon.  Below are some of the main overview charts. If you don’t have the time to read this paper, the NPC Chapter 10 Heavy-duty Engines & Vehicles is just 26 pages long and explains some of the unfamiliar terms well (see their excellent chart of priorities and obstacles at the end of this post).

Figure 14-31. Energy Balance of a Fully Loaded Class 8 Tractor-Trailer on a Level Road at 65 mph

Figure 14-31. Energy Balance of a Fully Loaded Class 8 Tractor-Trailer on a Level Road at 65 mph

fuel eff consumption by class

 

 

 

 

 

 

 

 

 

 

 

 

The first thing to know about trucks is that they are custom built to perform specific duties. What’s  good for a long-haul truck might not do as much for an urban delivery truck as shown in Figure S-1.  For example, all trucks and buses benefit from better engines, but long-distance trucks and coach buses don’t stop enough to benefit as much from Hybrid batteries that store braking energy as delivery and refuse trucks do, but benefit more than other trucks from aerodynamic improvements.

fuel eff varies by truck type

 

FIGURE S-1 Comparison of 2015-2020 new-vehicle potential fuel-saving technologies for seven vehicle types: tractor trailer (TT), Class 3-6 box (box), Class 3-6 bucket (bucket), Class 8 refuse (refuse), transit bus (bus), motor coach (coach), and Class 2b pickups and vans (2b).  Optimal driver management and coaching would also help but this has never been quantified.

FIGURE 2-7 Energy “loss” range of vehicle attributes as impacted by duty cycle, on a level road

FIGURE 2-7 Energy “loss” range of vehicle attributes as impacted by duty cycle, on a level road

 

According to the Transportation Energy Data Book, trucks move over 8.7 billion tons of freight annually in the United States, accounting for more than two-thirds of national freight transport. There are over 8 million Class 3–8 trucks on the road, according to the American Trucking Association. A significant share of trucking companies are small businesses, with 96% operating fewer than 20 trucks and nearly 88% operating six trucks or less. Consequently, the trucking industry is a highly fragmented industry, resulting in intense competition and low profit margins.

Class 7 & 8 trucks account for over 4.5 million units. These trucks represent heavy working trucks consuming typically 6,000–8,000 gallons of fuel per year for Class 7 and 10,000–13,000 gallons of fuel per year for Class 8a. Class 8b trucks are typically long-haul trucks weighing more than 33,000 pounds that have one or more trailers for flatbed, van, refrigerated, and liquid bulk. Class 7 represents some 200,000 vehicles while Classes 8a and 8b consist of 430,000 and 1,720,000, respectively. These trucks consume typically 19,000–27,000 gallons of fuel per year and account for more than 50% of the total freight tonnage moved by trucks.

The Class 8 truck market is 98% controlled by 6 brands owned by 4 companies: Freightliner, International, Peterbilt, Kenworth, Volvo, and Mack. Many of them also make Class 3-6 trucks and buses. These companies either develop their own engine platforms or buy them from independent engine manufacturers, dominated by a small number of players: Cummins, Detroit Diesel, Navistar, and Volvo Powertrain, with GM holding a key position in the Class 3-6 truck space.

TABLE S-1 Fuel Consumption Reduction Potential for Power Train Technologies
Diesel engines:  15 to 21%
Gasoline engines: Up to 24%
Diesel over gasoline engines: 6 to 24%
Improved transmissions: 4 to 8%
Hybrid power trains: 5 to 50%

TABLE S-2 Fuel Consumption Reduction Potential for Vehicle Technologies
Aerodynamics: 3 to 15%
Auxiliary loads: 1 to 2.5%
Rolling resistance (tires): 4.5 to 9%
Mass (weight) reduction: 2 to 5%
Idle reduction: 5 to 9%
Intelligent vehicle: 8 to 15%

TABLE S-3 Overall Fuel Consumption Reduction Potential for Typical New Vehicles, 2015-2020
51% Tractor-trailer
47% Class 6 box truck
50% Class 6 bucket truck
45% Class 2b pickup
38%  Refuse truck
48%  Transit bus
32% Motor coach

fuel eff NPC technology pct by truck class

 

fuel eff NPC technology price by truck class

Class Applications Gross Wt Range (lb)
1c Cars only 3200-6000
1t Minivans, small SUVs, small pick-ups 4000-6000
2a Large SUVs, standard pick-ups 6001-8500
2b Large pick-ups, Utility Van, Multi-porpose, Mini-bus, Step Van 8501-10000
3 Utility Van, Multi-purpose, Minibus, Step Van 10001-14000
4 City Delivery, Parcel Delivery, Large Walk-in, Bucket, Landscaping 14001-16000
5 City Delivery, Parcel Delivery, Large Walk-in, Bucket 16001-19500
6 City Delivery, School Bus, Large Walk-in, Bucket 19501-26000
7 Furniture, refuse, concrete, tow, fire engine, tractor-trailer 26001-33000
8a Dump, refuse, concrete, furniture, tow, fire engine, city bus 33001-80000
8b Tractor-trailer, Bulk Tanker, Flat bed 33001-80000

 

The 6 miles per gallon (mpg) fuel economy of a line-haul truck seems paltry compared to the 40 mpg of a car. But when the fuel used to move cargo weight is considered, the big truck looks pretty good. A large class 8 truck carrying 42,000-pounds of goods at 6 mpg of fuel economy is carrying 126 tons of freight per mile, or 126 ton mpg. But a car with 500 pounds of people and luggage is only getting 10 ton mpg, less than 10% of the large truck.

So when diesel and gasoline are rationed, someone needs to figure out situations where it makes more sense to delivery food and other essential items to homes rather than having each household drive to stores.

Cl
 Gross Weight Range (lb) Empty Weight Range (lb) Typical Payload (cargo) weight Payload capacity Max (% of Empty) 2006 Unit sales volume Typical mpg range 2007 Avg ton mpg
1c 3200-6000 2400-5000 250-1000 10-20 7,781,000 25-33 15
1t 4000-6000 3200-4500 250-1500 8-33 6,148,000 20-25 17
2a 6001-8500 4500-6000 250-2500 6-40 3,020,000 20-21 26
2b 8501-10000 5000-6300 3700 60 545,000 10-15 26
3 10001-14000 7650-8750 5250 60 137,000 8-13 30
4 14001-16000 7650-8750 7250 80 48,000 7-12 42
5 16001-19500 9500-10800 8700 80 41,000 6-12 39
6 19501-26000 11500-14500 11500 80 65,000 5-12 49
7 26001-33000 11500-14500 18500 125 82,411 4-8 55
8a 33001-80000 20000-34000 20000-50000 100-150 45,600 2.5-6 115
8b 33001-80000 23500-80000 40000-54000 125-200 182,395 4-7.5 155

 

FIGURE 3-7 Some aerodynamic technologies

FIGURE 3-7 Some aerodynamic technologies

 

 

 

FIGURE 4-15 Battery type versus specific power and energy. SOURCE: Kalhammer et al. (2007).

FIGURE 4-15 Battery type versus specific power and energy. SOURCE: Kalhammer et al. (2007).

 

 

 

 

 

 

 

 

 

 

It’s easy to see why lithium ion batteries are winning out over other battery technologies — they have both higher power (I want it NOW) and higher energy (long distance for hours) and weigh less. But li-ion perform poorly, and don’t achieve their optimal driving range under 32 F and over 95 F. Hot temperatures also shortens li-ion battery life.

% of weight lbs Major Description
24 4080 Powertrain Engine and cooling system, transmission, accessories
19 3230 Truck body structure Cab-in-white, sleeper unit, hood & fairings, Interior & glass
18 3060 Misc Accessories/systems Batteries, fuel system, exhaust hardware
17 2890 Drivetrain & Suspension Drive axles, steer axle, suspension system
12 2040 Chassis / Frame Frame rails & crossmembers, Fifth wheel and brackets
10 1700 Wheels and Tires Set of 10 aluminum wheel + tire

Figure 5-32 Weight distribution of major component categories in Class 8 tractors. SOURCE: Smith and Eberle (2003).

fuel eff weight of different parts class 8 trucks

 

Potential for Lightweighting Trucks

Class 8 trucks, per 1,000 pounds lighter, get up to 1% better fuel efficiency on level ground, 1.6% better in stop and go traffic, and up to 2.4% better going uphill (Table 5-16, not shown).

Trucks, trailers, and buses are benefiting from greater use of lightweight materials and structures. Components already making use of aluminum include the cab structure, wheels, fifth wheel, bellhousing, and more (see Table 5-17). Aluminum composite panels have been introduced on trailers, and the use of wood in trailers is diminishing. The barrier to additional use of aluminum or carbon composites is primarily cost effectiveness, with carbon fiber composites, for example, costing several times more per unit mass than aluminum. Some technical and cost-effectiveness issues with carbon composites and have been studied in DOE programs with industry (Rini, 2005).

While progress is being made in weight reduction through materials and design, certain weight-adding components have been necessary. Emissions control components are adding roughly 400 lb, and aerodynamic devices another 200 lb, but are deemed a positive tradeoff with aerodynamic drag reduction. Similarly, the weight addition from efficiency technologies such as waste heat recovery are projected to provide net benefits. In hybrid applications, batteries and other hybrid components add 300 to 1000 lb for trucks and even more in bus applications.

FIGURE 5-38 Weight reduction opportunities with aluminum.

FIGURE 5-38 Weight reduction opportunities with aluminum.

 

 

 

 

 

 

 

 

Technologies Class 8 Class 3-7 Refuse Truck
Trailer aerodynamics X
Cab aerodynamics X X
Tires and Wheels X X X
Weight reduction X X X
Transmission & driveline X X X
Accessory electrification X X
Overnight idle reduction X
Idle reduction X X
Engine efficiency X X X
Waste heat recapture X
Hybridization X X X
Dieselization (from gasoline) X
TABLE 6-1 Technologies and Vehicle Classes Likely to See Benefits
Fuel Consumption reduction %
Engine 20 11-14 14
Aerodynamics 11.5 6 0
Rolling Resistance 11 3 1.5
Transmission & driveline 7 4 4
Hybrids 10 30-40 35
Weight 1.25 4 1
TABLE 6-2 Fuel Consumption Reduction (percentage) by Application and Vehicle Type

fuel eff NPC technology pct tech improvement

 

 

 

 

 

 

fuel eff NPC technology pct cost improvement

 

 

 

 

 

 

fuel eff NPC cruise cntrl pct by truck class

 

 

 

 

 

fuel eff NPC cruise cntrl cost by truck class

 

 

 

 

fuel eff NPC obstacles

 

Tractors designed with aerodynamics in mind have been on the market for almost 30 years. A relatively wide range of aero-related improvements have been implemented on modern truck tractors, which has substantially improved their fuel economy. Figure 10-7 shows a summary of aerodynamic

More on aerodynamic design

[I think that this will be less of an issue as roads crumble and long-haul trucks can’t go fast, and hopefully railroads will be carrying a larger share of long-distance freight since they’ll have plenty of room once a great depression hits and less goods are traveling]

Some measures, such as roof fairings and deflectors, have been widely adopted throughout the trucking industry, while others are less prevalent. Improvements in fuel economy on the order of 10% have already been documented, owing to a combination of tractor aerodynamic measures.

The prospect of high fuel prices has renewed industry interest in active aerodynamics. Examples of active aerodynamic systems include the following: Grille shutters to close off the grille when active y engine cooling is not needed.

Active ride height control to lower the tractor and trailer at highway speeds. This technology lowers the total vehicle by 0.75 to 1.0 inch, which reduced overall form drag by reducing frontal area. Deployable mirrors or in-cabin vision systems to take over mirror functionality at highway speeds when the mirrors would be stowed for improved aerodynamics. Current safety regulations, which require fixed mirrors, prevent this technology from being deployed.

Trailer side skirts, mounted under the trailer and deflecting airflow from sweeping the trailer underside, have been shown to have a substantial aerodynamic effect. Fuel economy improvements of between 3.8 and 5.2% have been reported for such devices. However, while aerodynamically compelling, these features cause a wide variety of problems for fleet operators. Service, inspection, tire storage, and tire maintenance are all hindered by lack of easy access to the trailer underside. And skirts are prone to damage and breakage in the harsh environment where trailers must operate. These include the conditions at work sites, around fork trucks, in ice and snow, at steep loading docks, and similar conditions.

The rear of the trailer can be optimized for low drag using a “boat-tail” or similar device to reduce the massive separation bubble that follows the trailer back surface. Improvements in fuel economy ranging from 2.9 to 5.0% have been reported. As with side skirts, however, such devices have been resisted by the truck-buying fleets due to practical concerns.

Generally speaking, aerodynamic improvements to trailers have been slower and less noticeable than those on the tractor. This is largely due to the different ownership models of tractors versus trailers. Tractors are specified meticulously, and represent a major investment for their owners. A trailer costs much less, and is often seen as an interchangeable commodity with substantial cost pressure. Further, trailers are far more numerous than tractors, by a factor of 4:1 in a typical fleet. Many trailers are therefore sitting idle at any given time; the net result is a much longer payback time for investments in trailer efficiency. And finally, in some cases, the trailer is not owned by the same entity that owns the tractor and pays for the fuel. This misalignment of incentives is a hurdle to more aggressive implementation of trailer aerodynamic measures.

Tires

Rolling resistance accounts for roughly one-third of the power required to move a heavy truck over a level road at highway speeds. Rolling resistance comes primarily from inelastic deformation of the tire as it rotates. This deformation is a complex function of the load level, tire materials, tire and tread design, inflation levels, and the road surface itself. Generally speaking, the resistive force is proportional to the weight of the vehicle. In terms of energy consumption, the impact of rolling resistance is directly proportional to vehicle speed. Opportunities for reducing tire resistance are highly dependent on application as discussed below.

Wide-Base Single Tires. In Class 8 line-haul applications, operation is exclusively on-road and most time is spent at higher speeds, which provides several opportunities for optimization. The most significant development is the so-called “New-Generation Wide-Base Single” (NGWBS) tire, which employs a wider tread to replace two traditional truck tires with a single tire. Studies show fuel economy improvements in the range of 5 to 10% for the use of NGWBS tires in line-haul applications. These gains must be traded off against several downsides of such tires, including an added capital cost of around $3,600 per vehicle, and a perception of reduced safety.

NGWBS tires are not the only means to reduce tire rolling resistance. Proper inflation and alignment can also contribute to better fuel economy. Maintenance of proper inflation levels can be improved by tire pressure monitoring, and in some cases by the use of nitrogen gas in the place of air. The total effect of such changes is around 1.5 to 3%. However, with the exception of pressure monitoring, these modifications are very low-cost options, requiring only basic service and attention to the vehicle. The cost of such activity is estimated at only around $300 per vehicle, for both Class 3-6 vehicles and vocational Class 8 trucks. These improvements are particularly relevant for non-line-haul vehicles, where NGWBS tires are often not an option.

Vehicle Weight

Vehicle weight is a significant factor in fuel economy and puts stress on roads causing billions of dollars of needed repairs every year. It has an impact on the power required to accelerate, and the power dissipated in the form of braking.

Vehicle weight also impacts such factors as rolling resistance and transmission performance, so that weight is an ever-present factor in truck fuel economy. It is most prevalent for vehicles with frequent changes in speed, which tends to dissipate more energy braking than constant-speed

The benefit of lower weight has been studied for a wide class of vehicle types, with varying results.

For line-haul trucks over level terrain, a benefit of between 0.4 and 1.0% in fuel economy is reported per 1,000 pounds of weight reduction. The benefit improves to 1.5– 2.0% for uphill climbing routes, where more energy is invested in pulling the weight of the vehicle to higher elevation. Data on other types of vehicle are less consistent, with results generally in the low single-digits of fuel economy improvement, depending on vehicle class and duty cycle.

All-electric truck battery weight

The battery weight for a class 8 truck is roughly 55,000 lbs and the max cargo weight is 59,000 lbs, so clearly it is impossible to electrify class 7-8 trucks unless battery energy density increases at least 10-fold.

All-electric truck batteries weight about 22 kg per kwh, and a typical class 3-6 battery is 80 kWh, so 1760 kg or 3880 lbs, and that will not only lower the distance the truck can go, but the amount of cargo weight it can carry.

Idling. Line-haul truck engines spend many hours idling in a given 24-hour period. Engine idling is used for a variety of functions when the truck is stationary, such as powering air-conditioners, providing electrical power for TVs, laptops, kitchenettes, etc., providing cabin heat in cold temperatures, and maintaining engine temperature. Though an idling diesel engine is not efficient, it is a simple and easy way to provide these functions to the typical long-haul trucker.

Reducing a single truck’s idling time by 15 minutes per day can save hundreds of dollars per year in fuel costs.

Telematic systems provide information to fleet managers and truckers with the primary objective of improving fleet efficiencies and fuel economy. Idle reduction and route management are examples of telematic applications. Idle time can be reduced using telematics in multiple ways. For example, with real-time knowledge of truck location and route traffic, a fleet manager can direct drivers to nearby trucks stops with hotel-load capacity or similar idle-elimination capabilities. By using telematic technologies to keep trucks on-route, fewer loads are delayed through unplanned route changes, and more trucks arrive at their destination on-time without overnight stops. These advantages can have a sizeable impact on fleet fuel economy.

Telematic technologies are also instrumental in route management. This includes both planning of routes based on past history of truck routes and active real-time management of truck route following. A study conducted for a report by TIAX in 2009 found that route optimization software was able to reduce pick-up and delivery fleet mileage between 5 and 10% per year. For regional and line-haul fleets, which spend relatively less time in traffic, the fuel savings potential was approximately 1% per year according to the NRC.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

fuel eff NPC obstacles 2

 

Posted in Transportation What To Do, Trucks | Tagged , , , , , , , | Comments Off on Better truck fuel efficiency to delay the end of the oil age