The electric grid, critical interdependencies, vulnerabilities: U.S. House hearing 2003

Preface.  Of course, this website explains why the grid can’t stay up without fossil fuels, so by 2050 the grid will only be up in a few places, perhaps China, the Middle East, and Russia if war hasn’t brought on the end of our fossil fueled civilization.

Related articles:

  • Russian hackers suspected in attack that blacked out parts of Ukraine
  • How the weapon works (pdf): CRASHOVERRIDE Analyzing the Threat to Electric Grid Operations
  • The EMP Commission estimates a nationwide blackout lasting one year could kill up to 9 of 10 Americans through starvation, disease, and societal collapse
  • Electromagnetic pulse threat to infrastructure (U.S. House hearings 2012 & 2014)
  • The Devil’s Scenario – near miss at Fukushima is a warning for U.S.
  • A Nuclear spent fuel fire at Peach Bottom in Pennsylvania could force 18 million people to evacuate
  • The electromagnetic pulse EMP Threat. May 13, 2005 House of Representatives hearing
  • The electric grid, critical interdependencies, vulnerabilities. House of Representatives 2003
  • Electromagnetic Pulse EMP from solar flares or high-altitude nuclear weapon explosion

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

House 108-23. September 4 & 23, 2003. Implications of power blackouts for the nation’s cyber-security and critical infrastructure protection. House of Representatives. 246 pages.

THE ELECTRIC GRID, CRITICAL INTERDEPENDENCIES, VULNERABILITIES, AND READINESS

Curt Weldon, Pennsylvania. The greatest threat would be a low-yield nuclear weapon, which we now know that North Korea has and Iran is trying to obtain, and the ability to put it up into the atmosphere, which we know that both Iran and North Korea have, a low-complexity missile; and by detonating that low-yield nuclear weapon off of the coast in the atmosphere The electro-magnetic pulse (EMP) would fry all the electronic components within a given range within the U.S. In fact, our military has tested this type of capability in the past. In testimony before the Armed Services Committee, we have not hardened our systems. Only our ICBM system is hardened, and almost the entirety of our energy complex in America would be vulnerable to any EMP laydown.

I am familiar with Russian nuclear doctrine. Their first attempt at attacking us would be to lay down an EMP burst off of our coast with a nuclear weapon that would not hurt one person, but would fry all of our electronic components, including our electrical grid system. It would shut down America, including our vehicles, which have chips in them that would stop on the roads. Now, we tested this capability in 1962 when we did four tests at the Kwajalein Atoll in the Pacific. We were startled that within 800 miles everything was shut down, streetlights. We stopped cars dead in their tracks, and we fried the major electronic components of our telephone system. We did those tests in 1962. That is not classified. That has been reported in the media, and in fact it was just in a book put out by Dan Verton called ‘‘The Black Ice.’’ In 1999, we in the House held hearings on this phenomenon, not because of 9–11, but because we knew of the implications. Directed energy has become the weapon of choice for the future for nations that want to bring us down or harm us. We are doing research ourselves, and so are other countries on directed energy, let alone the EMP phenomenon.

There is no greater threat to our security and our quality of life than a terrorist using electromagnetic pulse (EMP), and there are now 10 countries that have nuclear capability, and 70 countries with missiles that they could launch off of our coast using low-yield weapons that would not harm one person. 

COFER BLACK, Office of the coordinator for counter terrorism, department of stateThe phrase ‘‘critical infrastructure’’ covers many elements of the modern world. To cite a few examples: the computers we use to transfer financial information from New York to Hong Kong and other cities, the air traffic control systems for international and domestic flights and, of course, the electric grid systems. The global critical infrastructure is both a contributor to, and a result of, the interdependence that exists among nations today. Critical infrastructure essentially means all the physical and virtual ties that bind us together, not only as a society but as a world. Terrorists know this, and they see attacking the very bonds that hold us together as one more way to drive us apart.

Christopher Cox, California, Chairman Select committee on Homeland Security. The blackout shutdown over 100 power plants, including 22 nuclear reactors, cutoff power for 50 million people in 8 states and Canada, including much of the Northeast corridor and the core of the American financial network, and showed just how vulnerable our tightly knit network of generators, transmission lines, and other critical infrastructure is.

Cyber attacks are a real and growing threat. The problem of cyber-security is unique in its complexity and in its rapidly evolving character. Cyber attacks are different from physical attacks since they can be launched from anywhere in the world and be routed through numerous intermediate computers. Cyber attacks require a different skill set to detect and counter, and are not limited to the risks posed from Al-Quaida. They include threats posed by those criminals and hackers who are already attacking our infrastructure for their own amusement or using it to steal information and money. As the most information technology-dependent country in history, we remain uniquely vulnerable to cyber attacks that can disrupt our economy or undermine our national security.

The dependence of major infrastructural systems on the continued supply of electrical energy, and of oil and gas, is well recognized. Telecommunications, information technology, and the Internet, as well as food and water supplies, homes and work sites, are dependent on electricity; numerous commercial and transportation facilities are also dependent on natural gas and refined oil products.

Physical or cyber attacks can amplify the impact of physical attacks on this critical infrastructure, and diminish the effectiveness of emergency responses.

Blackout effects:

  1. Harlem’s sewage treatment plant shut down without power for its pump.
  2. Seven oil refineries in the U.S. and Canada temporarily shut down, worsening an already tight gasoline supply situation.
  3. Many airports were closed because of inoperable systems on the ground. Refueling of aircraft stopped as hydrant systems and fuel farms lacked power.
  4. Nearly all manufacturers in southeast Michigan ground to a halt with the blackout.
  5. The 911 emergency systems in New York and Detroit failed during the blackout.
  6. New York City’s computer-aided dispatch system for its fire department and rescue squad crashed. Water systems in Cleveland and Detroit could not handle the drop in power.
  7. Ohio Governor Bob Taft declared a state of emergency in Cleveland after all four pumping stations that lift water out of Lake Erie went out and residents were ordered to boil their water for days.
  8. The beaches were off limits for swimming after a sewage discharge into Lake Erie and the Cuyahoga River sent bacteria levels soaring.
  9. More than 50 assembly and other plants operated by General Motors Corp., Ford Motor Co., DaimlerChrysler, and Honda Motor Co. were idled by the cascading blackout.
  10. NOVA Chemicals shutdown plants in Pennsylvania, Ohio, and Ontario, Canada.
  11. Walmart closed 200 stores in Canada and the United States.
  12. Marriott International saw 175 of its hotels in the Northeast lose power at the height of the blackout.
  13. Hundreds of airline flights were cancelled. For many airports throughout the U.S. and Canada, the power failure exposed the risk of fuel supply interruptions from electricity outages, since most hubs in North America are fed by pipeline systems.
  14. Tightened security measures established after 9–11 could not be maintained as power was not available for baggage screening machines.
  • Without railroads to deliver coal, the nation loses 60% of the fuel used to generate electricity.
  • Without electricity, fueling stations cannot pump fuel.
  • Without diesel, the railroads will eventually stop running.
  • When railroads stopped running after 9/11 to guard hazardous materials in only two days the city of Los Angeles was out of chlorine and faced the threat of no drinking water—the railroads began operating again on the third day.

Blackstart of grid – restoring power. Restoring a system from a blackout required a very careful choreography of re-energizing transmission lines from generators that were still online inside the blacked-out area, from systems from outside the blacked-out area, restoring station power to off-line generating units so they could be restarted, synchronizing the generators to the interconnection, and then constantly balancing generation and demand as additional generating units and additional customer demands are restored to service.  Many may not realize it takes days to bring nuclear and coal fired power plants back on-line, so restoring power was done with gas-fired plants normally used for peak periods to cover baseload needs normally coal and nuclear-powered. The diversity of our energy systems proved invaluable.

Robert Liscouski, assistant secretary, Infrastructure protection, Department of homeland security.  While the national focus was primarily on the blackout and its cause, our teams were hard at work assessing the cascading effects into other sectors. Interdependencies among the sectors were again demonstrated by this event. Seven major petroleum refineries suspended operations, many chemical manufacturing plants were shut down, grocery stores lost perishable inventories, air traffic ceased at several major airports, and emergency services capacity was tested. Web sites were shut down. ATMs did not work in the affected areas and the American Stock Exchange did not operate for a period of time. The effect of the blackout highlighted what we already knew at the department. If one infrastructure is affected, many other infrastructures are likely to be impacted as well. Indeed, all the critical infrastructure sectors were affected by this event. Understanding the vulnerabilities and interdependencies associated with cascading events is an area of great importance to the department.

Jim Turner, Texas. This incident demonstrated that there are literally hundreds of thousands of potential targets that terrorists could choose to strike. These include power systems, chemical and nuclear plants, commercial transportation and mass transit, skyscrapers, and sports and concert venues. In addition to physical assets, we also need to protect cyber assets. Recent computer disruptions have had unexpected consequences on nuclear plants and other utilities. Eighty-five percent of our critical infrastructure assets are privately owned. We must, therefore, work in partnership with the private sector to improve our national security. But we can’t rely too heavily on voluntary private action. Companies seeking to maximize profits simply are unlikely to have the economic incentives to voluntarily make the investments necessary to raise security levels to where they need to be.   In the absence of sufficient action by critical infrastructure owners, we have a duty to take the initiative to protect the American people.

Paul H. Gilbert. Gilbert us a member of the National Academy of Engineering and was Chair of the National Research Council Panel responsible for the Chapter on Energy Systems for the NRC Branscomb-Klausner Report, Making the Nation Safer: The Role of Science and Technology in Countering Terrorism

Over the past decade our electric supply system has been tasked to carry ever-increasing loads. It has also undergone a makeover from being a highly regulated, vertically integrated utility to one that is partially deregulated, far less unified, not as robust and resilient as it was. The generation side is essentially deregulated and operating under an open market set of conditions. At the same time the transmission sector remains fully regulated, but under voluntary compliance reliability rules, resulting in diminished investments in maintenance and spare parts and lower reliability. Another concern is that in seeking to reduce operating costs, the operating companies have installed automated cyber-controllers, or SCADA systems, to perform functions that people previously performed. These open architecture cyber units are an invitation for those who would seek to use computer technology to attack the grid.

The in-place electrical utility assets today are typically being operated at close to the limit of available capacity. In this mode another characteristic of such complex systems appears. When operated near their capacity, these systems are fragile, having little reserve within which to handle power or load fluctuations.

When load and capacity are out of balance, shutting down becomes the only way a system element has to protect itself from severe damage. However, the loss of a piece of the grid, let us say a transmission line, does not end the problem. A line down takes down with it the power that it was transmitting. The connected power plant that was producing that power, having no connected load, must also shut down. In these highly integrated grids, more lines have imbalance problems, and more plants sense the capacity limitations and they all shut down. The cascading effect spreads rapidly in many directions, and in seconds an entire sector of the North American grid can be down. And this is what we experienced a few weeks ago from an accident.

The exact same consequences could, however, too easily be produced by a terrorist attack from a small, trained team. This was the scenario assumed in the Making the Nation Safer report, where several critical nodes in the grid were taken out in a well planned and executed terrorist attack. The cascading system failures resulted in region-wide catastrophic consequences.

Recovery was estimated to take weeks or months, not hours or days.

Now, while the report does not speculate in any detail on the extended consequences of such an event. I have been asked to do so here, and so I offer the following as a personal opinion. Based on the critical infrastructure, and because that critical infrastructure is so extensively integrated, with power out beyond a day or two in our cities, both food and water supplies would soon fail.

Transportation systems would come to a standstill. Waste water could not be pumped. And so we would soon have public health problems. Natural gas pressure would decline, and some would lose gas altogether, very bad news in the winter. Nights would become very dark with no lighting, and communications would be spotty or nonexistent. Storage batteries would have been long gone from the stores, if any stores were still open. Work, jobs, employment, business and economic activity would be stopped. Our economy would take a major hit. All in all our cities would not be very nice places to be. Some local power generators such as at hospitals would get back up, and so there would be islands of light in the darkness. Haves and have-nots would get involved. It would not be a very safe place to be either. Martial law would likely follow, along with emergency food and water supply relief. At our core we would rally and find ways to get by while the systems are being repaired. In time the power would start to come back, tentatively at first, with rolling blackouts, and then in all its glory.

Several weeks to months would have passed, and the enormous recovery and clean-up would begin. This is simply one person’s view, but based upon a fairly in-depth understanding of the critical interdependency of our infrastructure.

Our basic infrastructure systems include our electric power, food, and water supplies, waste disposal, natural gas, communications, transportation, petroleum products, shelter, employment, medical support and emergency services, and facilities to meet all our basic needs. These are a highly integrated, mutually dependent, heavily utilized mix of components that provide us with vitally needed services and life support. While all these elements are essential to our economy and our well-being, only one has the unique impact, if lost, of causing all the others to either be seriously degraded or completely lost. And that, of course, is electric power. Our technically advanced society is literally hard wired to a firm, reliable electric supply.

KENNETH C. WATSONPresident & Chairman of the Partnership for Critical Infrastructure Security (PCIS), currently the manager of Cisco Systems’ involvement in critical infrastructure

  • We all depend on telecommunications—in fact, when recently asked to list their dependence on other sectors, the sector coordinators rated telecommunications as first or second on their list.
  • Nearly equal to telecommunications was electric power. Without electricity, there is no ‘‘e’’ in e-commerce.
  • However, without railroads to deliver coal, the nation loses 60% of the fuel used to generate electricity.
  • Without diesel, the railroads will stop running.
  • Without water, there is no firefighting, drinking water, or cracking towers to refine petroleum.
  • Without financial services, transactions enabling all these commodity services cannot be cleared.

These are not just one-way dependencies. When the railroads stopped running after 9/11 to guard hazardous material, it only took the city of Los Angeles two days to demand chlorine or face the threat of no drinking water—the railroads began operating again on the third day. Throughout the Northeast, dependencies on electric power were obvious. Some areas had electric water pumps, and they had to boil their drinking water for days after the blackout.

All of our critical infrastructures are interlinked in complex, sometimes little-understood ways. Some dependencies are surprising, contributing to unusual key asset lists.

DENISE SWINK, ACTING DIRECTOR, OFFICE OF ENERGY ASSURANCE, DEPARTMENT OF ENERGY

As you know, our energy infrastructure is vast, complex and highly interconnected. It includes power plants, electric transmission and distribution lines, oil and gas production sites, pipelines, storage and port facilities, information and control systems and other assets. Many of these entities own, operate, supply, build or oversee their infrastructure. The private sector owns about 85% of these assets and a host of federal and state agencies regulate energy generation, transport, transmission and use.

We maintain collaborative relationships with [many entities]:

  1. We work closely with the Department of Homeland Security (DHS), which leads, integrates, and coordinates critical infrastructure protection activities across the federal government.
  2. To aid this effort, Department of Energy & DHS are working on a plan for collaboration and responsibilities (i.e. critical infrastructure protection of physical and cyber assets, science and technology, and emergency response).
  3. We are also beginning to work with the Coast Guard
  4. With Federal Emergency Management Agency (FEMA),
  5. Representatives of the Defense Intelligence Agency,
  6. The National Institute of Standards and Technology to consider options for developing a collaborative National SCADA Program.
  7. We work closely with the Department of Transportation’s Office of Pipeline Safety
  8. We coordinate with the Environmental Protection Agency (EPA) to avoid redundant efforts with petrochemical facilities.
  9. We partnered with the Federal Energy Regulatory Commission (FERC)),
  10. state regulators,
  11. and industry to assess the implications of a loss of natural gas supply in some regions of the country.
  12. DOE’s new Office of Electric Transmission and Distribution on issues related to the electric grid
  13. The Office of Security to improve the operations of DOE’s Emergency Operation Center.
  14. The Office of Energy Efficiency and Renewable Energy’s regional offices to support our meetings with state energy offices;
  15. The Office of Fossil Energy on new technologies to harden oil and gas pipelines;
  16. The Office of Science on visualization techniques through their Advanced Scientific Computing Research Program;
  17. The Office of Independent Oversight and Performance Assurance on cyber security protection.

Collaboration with the PRIVATE SECTOR is critical :

  1. American Petroleum Institute (API),
  2. American Gas Association (AGA),
  3. Interstate Natural Gas Association of America (INGAA),
  4. Gas Technology Institute (GTI),
  5. National Propane Gas Association (NPRA),
  6. Edison Electric Institute (EEl),
  7. Electric Power Research Institute (EPRI),
  8. National Rural Electric Cooperative Association (NRECA),
  9. American Public Power Association (APPA),
  10. North American Electric Reliability Council (NERC).

Collaboration with STATES

  1. National Association of State Energy Officials (NASEO),
  2. National Governors Association (NGA),
  3. National Association of Regulatory Utility Commissioners (NARUC),
  4. National Conference of State Legislatures (NCSL)

Colonel Michael C. McDaniel.  Assistant Adjutant General for Homeland Security for the Michigan National Guard, Homeland Security Advisor to Michigan’s Governor, Jennifer M Granholm.

On Thursday, August 14, 2003, at 4:15 p.m., a massive power outage struck the Niagara-Mohawk power grid in the Northeast US and Ontario causing blackouts from New York to Michigan.  Within minutes, much of southeast and mid-Michigan was without power, with 60% of Michigan’s population, over 2.2 million households, affected by the outage

The State of Michigan and local governments spent $20.4 million on emergency measures to save lives, protect public health, and prevent damage to public and private property.

The Emergency Management Division of the Michigan State Police began to immediately monitor conditions around the state, including the state’s nuclear power plants.

Within minutes, the state’s Emergency Operations Center (EOC) was formally activated, and state agencies began to monitor state and national conditions.

Some of the major complications from the blackout:

  1. Gas stations were unable to supply peoples’ needs for their cars and portable generators, as without electricity the pumps were inoperable
  2. The Detroit Board of Water and Sewers, oversight board of the nation’s second largest water system, reported that its system was not functioning correctly. It issued a boiled water advisory for its entire service area.
  3. There was no system to notify all of the customers of the boiled water advisory, as notification was dependent on the public media. It became clear, on the morning of August 15, that the largest problem was the lack of potable water. Public and private entities delivered hundreds of thousands of gallons of water to those affected sites, but a boiled water advisory was not lifted until Monday, August 18.
  4. Widespread traffic signals not functioning and limited telephone communications.
  5. Marathon Refinery, Michigan’s largest refining facility, lost power and had to shut down. One unit did not shut down properly and began venting partially processed hydrocarbons. Because of the tank’s location, the city of Melvindale (with the assistance of the Michigan State Police) decided to evacuate 30,000 residents and shut down Interstate 75 for several hours until the situation was controlled. The Marathon Refinery was inoperable as a result of the loss of electricity and water, and out of production for approximately 10 days.
  6. The auto industry shut down operations for three days.
  7. A lot of first responders were relying upon cell phones that did not have an adequate radio system, and a number of cell towers did not have backup systems that worked.
  8. Radio and television stations reported broadcasting difficulties, with several small stations not operating at all.
  9. Many facilities lacked sufficient alternative energy sources. Portable generators were needed at hospitals and other public facilities, including the state mental institution.
  10. The Fermi II nuclear plant in Monroe County was shut down as a precaution. It returned to full power production and was reconnected to the power grid late a week later on August 21
  11. The Ambassador Bridge in Detroit, the busiest commercial landport in the United States with 16,000 tractor-trailers crossing daily, was also affected.
  12. Canadian customs lost their computer datalink, and their ability to verify trucking manifests electronically. As a result they were forced to visually and manually inspect the manifests and, if warranted, the freight itself. This resulted in an approximately four-mile backup of traffic for almost 24 hours on the U.S. side.
  13. Many computer systems were not functioning, including the Law Enforcement Information Network (LEIN).
  14. The Michigan State Police positioned 50 state troopers on stand-by for mobilization, if needed to maintain order in blackout areas . The Michigan National Guard also had troopers ready on stand-by.
  15. Metropolitan Detroit Airport was closed and all flights canceled until midnight on August 14.
  16. A number of public water issues arose from the blackout. Generators need an automatic activation switches and shouldn’t rely on telephone lines
  17. Almost every type of critical infrastructure that should have a generator did have some sort of generator. But no one had not tested those generators under load, so we had a lot of generators that just didn’t work. They might have fired them up before, but they never tested them under a load and actually had them producing electricity. When they did work, they ran out of fuel. We were starting to get calls from both hospitals and some of the utilities wanting to know if we could help them find kerosene diesel for their generators.
  18. A lot of people did not have old-fashioned phones. Everybody’s phone is portable, a hand-held device which requires electricity these days, or a cell device, and not all of those towers worked. So there were a number of instances where the communication systems were more reliant on electricity than we believed that they would be. Again, even those radio and TV stations that had generators, the generators didn’t work because they had never been tested. So they weren’t ready to work under load. They weren’t the right capacity generator. And then the other problem, as I said, was 24 hours later they were staring to run out of power. Both TV and radio, as well as the telephone companies, were calling as well.
  19. This was a very hot day in the summer where the usage on the Detroit water system was almost a billion gallons a day. The system, even after it came back up on generators, could only handle about 400 million gallons per day. If we had had a method, if we had some sort of warning that this was going to happen, and could have gotten out to decrease your electricity, decrease your water use ahead of time, it probably would have made it easier for the system to come back on.

The NIAC Interdependency and Risk Assessment Working Group submitted its final report to NIAC members October 14, 2003. That report included results of a survey of Sector Coordinators and key infrastructure owners and operators regarding their top dependencies. Respondents were asked to list the top three sectors on which they depend, and the top three sectors that depend on them. In terms of short-term dependencies, the overall top three were 1) telecommunications and IT, 2) electricity, and 3) transportation. However, adding long-term impacts broadens the list of critical dependencies. Without financial services, business comes to a grinding halt in a matter of days. Without safe food, clean drinking water, and available health care, public health also reaches a crisis in days. Without emergency police, fire, and medical services, the ability to respond and contain emergencies is severely impacted. Long-term impacts of transportation failures are far more severe than the short term.

Without consideration for what vulnerability analysis is underway and what protective measures are in place, the following sectors present the highest potential risk to national security: Energy Information and Communications Banking and Finance Transportation Postal and Shipping This priority scheme is based on (a) the ease at which problems propagate within the sector, (b) the extent of other sectors’ dependencies on it, and (c) the potential impact of a sector’s loss of crucial functionality.

CHRISTOPHER COX, CALIFORNIA, AND CHAIRMAN, SELECT COMMITTEE ON HOMELAND SECURITY

As a group, the critical infrastructure sectors are backbone services for our nation’s economic engine and produced approximately 31% of the Gross Domestic Product (GDP) in the year 2000. The blackout rippled through the economy. The examples are endless, and experience shows us that the blackout is not alone in its capacity to disrupt the economy. The information super highway of the Internet has become a fast lane for computer viruses. A computer virus launched one morning can infect computers around the world in one day. The Slammer virus, launched in January of this year, reportedly infected 100,000 computers in its first ten minutes alone. Because of the SoBig computer virus, some rail routes of CSX were recently shut down on August 20, until a manual backup system started the trains running again.

We know that terrorists have assessed the possibility of attacking our nuclear power plants and our transportation system. Al-Qaida computers seized in Afghanistan in 2001 had logged on to sites offering that offer software and programming instructions for the distributed control systems (DCS) and Supervisory- control and Data-acquisition (SCADA) systems that run power, water, transport and communications grids. All critical infrastructure industries are becoming increasingly dependent on information management and internal telecommunications systems to control and maintain their operations. The U.S. Dept. of Commerce’s National Telecommunications & Information Administration (NTIA) published a study in January 2002 that detailed the myriad of uses the internal wireless communications systems to meet essential operational, management and control functions including two-way emergency restoration and field communications, monitoring power transmission lines and oil and natural gas pipeline functions to instantaneously respond to downed transmission lines or changes in pipeline pressure; sending commands to various remote control switches; inspecting 230,000 miles of rail track; managing wastewater, processing drinking water, and protective relaying. SCADA systems could be attacked simply by overloading a system that, upon failure, causes other systems operations to malfunction as well.

While there is some debate about the ability of a terrorist to successfully launch a cyber attack against a SCADA system, there are several examples of people or groups who have tried. In March 2000 a disgruntled former municipal employee used the Internet, a wireless radio and stolen control software to release up to 1 million liters of sewage into the river and coastal waters of Queensland, Australia. Similarly, NERC reports that over the past two years, there have been a number of ‘‘cyber incidents that have or could have directly impacted the reliable operation of the bulk electric system,’’ including: • In January 2003, When the SQL/Slammer worm caused an electric utility company to lose control of their SCADA system for several hours, forcing the company operations staff to resort to manual operation of their transmission and generation assets until control could be restored. • In September 2001, the Nimda worm compromised the SCADA system of an electric utility, and then propagated itself to the internal project network of a major SCADA vendor via the vendor’s support communications circuit, devastating the vendor’s internal network and launching further attacks against the SCADA networks of the vendor’s other customers. More telling, perhaps, is a report issued in May 2002 by the Defense Department’s Critical Infrastructure Assurance Program (CIAP) claiming that there was evidence of a coordinated cyber reconnaissance effort directed against the critical assets of at least two electric utilities participating in the Defense Department sponsored program. The report revealed that the probing appeared to come from the People’s Republic of China, Hong Kong, and South Korea, with each probe building upon information previously garnered. The blackout is yet another wake-up call to our nation. It demonstrated the fragility of our electric transmission system, and reminds us of the interdependent nature of our infrastructure. Clearly, we need to encourage private industry and government to raise the standards of cyber security, and to further enhance our infrastructure security against attack.

KENNETH C. WATSON.

Some rudimentary research has been done on interdependencies, but it has only been sufficient to illuminate how important this type of modeling and analysis could be. Sandia and other national labs have initiated interdependency studies, looking at intersections with the energy sector. The National Security Telecommunications Advisory Committee (NSTAC) has done similar work, addressing intersections between telecommunications and other sectors. The National Infrastructure Advisory Council (NIAC) has a current effort to develop policy recommendations on interdependency risk assessments. The sector coordinators are involved in that study, which will become available after delivery to the President in the October timeframe. The PCIS is coordinating with this NIAC working group to ensure that the handbook we develop is in harmony with NIAC policy recommendations.

Network owners already know their key assets and critical nodes—what they don’t know is whether their key assets and critical nodes are in the same geographic vicinity as their competitors’ nodes, or whether underlying or supporting infrastructure is in fact, truly diverse. In highly competitive sectors, such as telecommunications or finance, it would not be unusual to find that each of the major providers has intended to buy diversity and redundancy from numerous entities, only to find that all these entities use the same underground conduit for transport that goes through the same underground tunnel, and they are powered by the same power generation plant. The NSTAC has studied the implications of these types of cross-sector dependencies and has developed a number of programs that the telecommunications sector uses to mitigate these risks. It is time, however to take it to the next level, covering all cross-sector and multisector interdependencies.

One of the challenges will be that much of the data required may be proprietary. To date, the NISAC has centered its modeling efforts on the energy sector. To understand the complexity of this modeling problem, consider the NISAC model of the energy sector as a baseline, and apply it as a level of magnitude to the telecommunications sector. While we do not know the precise amounts, it is our understanding that the current electrical sector modeling cost about $30–40 million to develop and was done over the course of 3 to 8 years. If you assume that the level of detail developed within the electrical sector model is appropriate (and we do not know that to be the case) and simply multiply this $30–40 million times the number of facilities-based networks that comprise the telecommunications sector, then you would conservatively multiply this estimate by a factor of 9 networks (5 wireless + 1 wireline + 2 IXC + 1 paging), resulting in a baseline model for telecommunications in the $270–$360 million range. Even if all $200 million was dedicated to telecommunications modeling, it would take 1 to 2 years of currently allocated funding, and an even longer actual modeling effort, to model telecommunications alone. Multiply that by 12 sectors, and then you can start on the cross-sector interdependency modeling.

I am not sure you can point to a single weak link. Over the last 20 years, all of the infrastructures have become more and more dependent on networks, and they have become more and more interconnected. I think the key that we need to study in research and modeling and exercises is interdependency. Each of the sectors is dependent on each of the others and sometimes we don’t even know what these dependencies are without modeling and exercises.

PETER R. ORSZAG1, PH.D., JOSEPH A. PECHMAN SENIOR FELLOW IN ECONOMIC STUDIES, THE BROOKINGS INSTITUTION

The blackout of 2003 has underscored concerns about the vulnerability of our nation’s critical infrastructure to both accidents and deliberate attack, providing an immediate connection to the nation’s homeland security efforts. But the blackout may offer a deeper lesson beyond the vulnerability of the nation’s electricity grid to terrorist attack. In particular, a common explanation for the problems facing the electricity system is that private firms have had inadequate incentives to invest in distribution lines.

The important point is that market incentives are extremely powerful. For that very reason, however, it is essential that they be structured properly. As Patrick Wood, chairman of the Federal Energy Regulatory Commission, has put it: ‘‘We cannot simply let markets work. We must make markets work.’’

Let me give you an example that I think is particularly timely, involving chemical facilities. Let’s say that you have a chemical facility. It is worth a billion dollars. It houses chemicals. There are 123 chemical facilities in the United States that contain chemicals that could injure or kill more than a million people. The value of a million lives can easily exceed, well exceed a billion dollars. You may well have some incentive to make sure that there is some level of security to ensure that your plant is not intruded upon and those chemicals are not dispersed and harm people. But it is not adequate because your financial loss is much smaller than society’s loss that would occur if a successful attack did unfortunately take place. And that kind of example occurs, you know, in a wide array of settings. And I—in my written testimony I provide lots of other types of examples, but I think that might be a particularly timely and compelling one, where any time that private financial losses that you suffer are vastly smaller than the losses that we as a society would suffer, you don’t have enough incentive, bottom line.

In homeland security, private markets do not automatically produce the best result.

We must therefore alter the structure of incentives so that market forces are directed toward reducing the costs of providing a given level of security for the nation, instead of providing a lower level of security than is warranted. Given the significance of the private sector in homeland security settings, structuring incentives properly is critical. To be sure, private firms currently have some incentive to avoid the direct financial losses associated with a terrorist attack on their facilities or operations. In general, however, that incentive is not compelling enough to encourage the appropriate level of security—and should therefore be supplemented with stronger market-based incentives in several sectors. My testimony argues that: • Private markets, by themselves, do not provide adequate incentives to invest in homeland security, and • A mixed system of minimum regulatory standards, insurance, and third-party inspections would better harness the power of private markets to invest in homeland security in a cost-effective manner. Incentives for homeland security in private markets

Private markets by themselves do not generate sufficient incentives for homeland security for seven reasons: • Most broadly, a significant terrorist attack undermines the nation’s sovereignty, just as an invasion of the nation’s territory by enemy armed forces would. The costs associated with a reduction in the nation’s sovereignty or standing in the world may be difficult to quantify, but are nonetheless real. In other words, the costs of the terrorist attack extend well beyond the immediate areas and people affected; the attack imposes costs on the entire nation. In the terminology of economists, such an attack imposes a ‘‘negative externality.’’ The presence of this negative externality means that private markets will undertake less investment in security than would be socially desirable: Individuals or firms deciding how best to protect themselves against terrorism are unlikely to take the external costs of an attack fully into account, and therefore will generally provide an inefficiently low level of security against terrorism on their own.3 Without government involvement, private markets will thus typically under-invest in anti-terrorism measures.4 • Second, a more specific negative externality exists with regard to inputs into terrorist activity. For example, loose security at a chemical facility can provide terrorists with the materials they need for an attack. Similarly, poor security at a biological laboratory can provide terrorists with access to dangerous pathogens. The costs of allowing terrorists to obtain access to such materials are generally not borne by the facilities themselves:

the attacks that use the materials could occur elsewhere. Such a specific negative externality provides a compelling rationale for government intervention to protect highly explosive materials, chemicals, and biological pathogens even if they are stored in private facilities. In particular, preventing access to such materials is likely to reduce the overall risk of catastrophic terrorism, as opposed to merely displacing it from one venue to another. • Third, a related type of externality involves ‘‘contamination effects.’’ Contamination effects arise when a catastrophic risk faced by one firm is determined in part by the behavior of others, and the behavior of these others affects the incentives of the first firm to reduce its exposure to the risk. Such interdependent security problems can arise, for example, in network settings. The problem in these settings is that the risk to any member of a network depends not only on its own security precautions but also on those taken by others. Poor security at one establishment can affect security at others. The result can often be weakened incentives for security precautions.5 For example, once a hacker or virus reaches one computer on a network, the remaining computers can more easily be contaminated. This possibility reduces the incentive for any individual computer operator to protect against outside hackers. Even stringent cyber-security may not be particularly helpful if a hacker has already entered the network through a ‘‘weak link.’’ • A fourth potential motivation for government intervention involves information—in particular, the cost and difficulty of accurately evaluating security measures. For example, one reason that governments promulgate building codes is that it would be too difficult for each individual entering a building to evaluate its structural soundness. Since it would also be difficult for the individual to evaluate how well the building’s air intake system could filter out potential bio-terrorist attacks, the same logic would suggest that the government should set minimum anti-terrorism standards for buildings.

It is also possible, at least in theory, for private firms to invest too much in anti-terrorism security. In particular, visible security measures (such as more uniformed guards) undertaken by one firm may merely displace terrorist attacks onto other firms, without significantly affecting the overall probability of an attack. In such a scenario, the total security precautions undertaken can escalate beyond the socially desirable levels—and government intervention could theoretically improve matters by placing limits on how much security firms would undertake.

Unobservable security precautions (which are difficult for potential terrorists to detect), on the other hand, do not displace vulnerabilities from one firm to another and can at least theoretically reduce the overall level of terrorism activity. For an interesting application of these ideas to the Lojack automobile security system, see Ian Ayres and Steven Levitt, ‘‘Measuring Positive Externalities from Unobservable Victim Precaution: An Empirical Analysis of Lojack,’’ Quarterly Journal of Economics, Vol. 108, no. 1 (February 1998). For further analysis of evaluating public policy in the presence of externalities, see Peter Orszag and Joseph Stiglitz, ‘‘Optimal Fire Departments: Evaluating Public Policy in the Face of Externalities,’’ Brookings Institution Working Paper, January 2002.

It would be possible, but inefficient, for each individual to conduct extensive biological anti-terrorism safety tests on the food that he or she was about to consume. The information costs associated with that type of system, however, make it much less attractive than a system of government regulation of food safety. • The fifth justification for government intervention is that corporate and individual financial exposures to the losses from a major terrorist attack are inherently limited by the bankruptcy laws. For example, assume that there are two types of possible terrorist attacks on a specific firm: A very severe attack and a somewhat more modest one. Under either type of attack, the losses imposed would exceed the firm’s net assets, and the firm would declare bankruptcy—and therefore the extent of the losses beyond that which would bankrupt the firm would be irrelevant to the firm’s owners. Since the outcome for the firm’s owners would not depend on the severity of the attack, the firm would have little or no incentive to reduce the likelihood of the more severe version of the attack even if the required preventive steps were relatively inexpensive. From society’s perspective, however, such security measures may be beneficial—and government intervention can therefore be justified to address catastrophic possibilities in the presence of the bankruptcy laws. • The sixth justification for government intervention is that the private sector may expect the government to bail it out should a terrorist attack occur. The financial assistance to the airline industry provided by the government following the September 11th attacks provides just one example of such bailouts. Such expectations create a ‘‘moral hazard’’ problem: private firms, expecting the government to bail them out should an attack occur, do not undertake as much security as they otherwise would. If the government cannot credibly convince the private sector that no bailouts will occur after an attack, it may have to intervene before an attack to offset the adverse incentives created by the expectation of a bailout. • The final justification for government intervention involves incomplete markets. The most relevant examples involve imperfections in capital and insurance markets. For example, if insurance firms are unable to obtain reinsurance coverage for terrorism risks (that is, if primary insurers are not able to transfer some of the risk from terrorism costs to other insurance firms in the reinsurance market), some government involvement may be warranted. In addition, certain types of activities may require large-scale coordination, which may be possible but difficult to achieve without governmental intervention.

Both the need for government intervention and the potential costs associated with it thus vary from sector to sector, as should the policy response. Government intervention will generally only be warranted in situations in which a terrorist attack could have catastrophic consequences. Nonetheless, the general conclusion is that we can’t just ‘‘leave it up to the market’’ in protecting ourselves against terrorist attacks.

SHEILA JACKSON-LEE, TEXAS: An illustration of the disjunct in our infra and super-structure is the television broadcast of the tens of thousands of New Yorkers who had to walk across the Brooklyn Bridge to end their workday. This is vulnerability. Thousands of riders of underground mass transit systems trapped in cars, frugal in their consumption of oxygen and hopeful that their rescue team was near equates to vulnerability. Because we cannot cast blame for this occurrence on a terrorist group means that we are vulnerable to ourselves first and foremost. The Administration must increase our awareness of the status of the areas that are most open to corruption.

 

Posted in Blackouts, Cascading Failure, Congressional Record U.S., CyberAttacks, Interdependencies | Tagged , , , , , | Comments Off on The electric grid, critical interdependencies, vulnerabilities: U.S. House hearing 2003

Barges are more energy efficient than rail and truck

marine highways

 

[After reading two congressional hearings, one in 2008, and another in 2013, about how the inland waterway system was falling apart, and had been for 30 years, I was curious to know why such an important asset would be allowed to fall apart. In the testimony, it was said that more money was collected in fees by the government than doled back out in capital and maintenance expenses (true from 1991 to 2006 (NAS 2015). It was said at the 2013 hearing that the U.S. Army Corps of Engineers (USACE) has a set budget, so if the money put into the Inland Waterway Trust Fund was actually given to port and river projects, other USACE projects would not be funded.

So the selection of waterways projects for authorization has a long history of being driven largely by political and local concerns (NAS 2015). Many states got a lot more money than they put in. The NAS report explains in gory detail what an irrational, byzantine mess the approval and funding process is.

National energy policy is not based on energy efficiency–there were no café standards for decades. Instead, massive, polluting gas guzzling vehicles have pummeled the hell out of our bridge and road infrastructure, wasting decades of oil that future generations will be angry about when the permanent oil crisis arrives.

Now that we’re at peak oil, a lot more attention and funding ought to go to the waterway system. 

Alice Friedemann   www.energyskeptic.com]

Energy Intensity of Barges and other transport

Barges are the second most energy efficient form of transport, next to large container and bulk ships.

Barges being towed down a river will get 953 net ton-miles, but being towed against the flow of the current will drop to 243 (Tolliver) with an overall average of 576 ton-miles, with rail 413, truck 155.

Barge versus rail

Davis reports that rail (294 Btu/ton-mile in 2012) is 40% more energy intensive than barge (210 Btu/ton-mile in 2012), nearly the same percentage difference as reported by Kruse (2013) who found 311 Btu/ton-mile for rail and 223 Btu/ton-mile for inland towing.

Dager (2013) reports even lower energy intensity for inland barge transport on the basis of independent data and fuel use modeling, corresponding to about 196 Btu/ton-mile, or about 60 percent better energy intensity than average rail.

Commodity-specific configurations can do even better. Dager reports  towboats on the Mississippi River between the mouth of the Missouri and Baton Rouge, Louisiana, averaged 867 ton-miles per gallon in 2011 versus the system average of 656. Baumel (2008) reported that unit grain trains moving from Iowa to New Orleans, Louisiana, had route-specific fuel efficiency of 640 ton-miles per gallon, 54% better than energy intensity for an average train.

“24th Annual State of Logistics Report: Is This the New Normal”, by Roz Wilson

Drought effect on barges

There were numerous times when sections of the particularly that Mississippi could travel only in one direction at a time because of the width of the channel would not support a bridge to, despite the fact that the Army Corps of Engineers was providing emergency dredging. Barges were often backed up for days at a time awaiting passage. I one point there were close to 100 vessels run aground and the lower Mississippi.

Shallower channels meant lighter loads, lower speeds and fewer barges, any of which would run up costs. Several harbors were closed at the height of the drought. It is estimated that every inch of drought loss represents thousands of potential products that cannot be moved. And 11 mile stretch of the Mississippi was closed intermittently and August causing queues up to 100 tows. Every single day a towboat is idle, it cost the owners $10,000. No surprise that shipping rates increase close to 25% during that period.

Just to show you how important the waterways really are, take a look at this model comparison chart and look at what you can move on one barge compared to what you can move on railroad, cars or trucks, or in one barge tow.

modal comparison barge rail truck

We should be using the water part of our system a lot more efficiency, I think, than we are. Just to bring it home, look at the time the miles traveled per gallon of fuel based on various modes. Looking at this really makes you want to understand or figure out ways that we can use our waterways more effectively.

most of the lock infrastructure has already exceeded its expected life. We need to fix the aging infrastructure. And then we need to build more landside infrastructure to support containers on barges and for translating the other modes.

Nicholas Kehoe. Oct 17, 2012. An Update on America’s Marine Highway Program

The infrastructure for seaports in our country was developed- much of it goes back to the 1930s, or some of it down in the South goes even later than that- but, the majority of the infrastructure in the country dates back to the 1950s, 60s and 70s. When it was built, it had an expected life cycle of about 50 years.

If you look at the freight network map that we have that has been used now for almost 5 years, not all of those highways connect to all of those ports. A prime section of ports that are missing are the Great Lakes. Look at the map and look at Duluth, which generates a significant amount of tonnage. Duluth supports one of the last US steelmaking plants and does not even have any highways connecting to it on that map. So, we need to work together to make sure that our freight highway system connects to the ports that the freight is flowing to, so that we can have that intermodal connectivity.

The purpose of the Marine Highway program, as legislated, is to mitigate landside congestion. And, we are to encourage the use of short sea or Marine Highway transportation through development and expansion of designated corridors, similar to the highway corridors, but for waterways. We use documented vessels and services, which means US flagged vessels. And, we have to encourage shipper utilization of the program. If the market is not establishing a program on its own, there is reason for that. There are policy disincentives to using marine highways, we are discovering. The system is not made right now to make water very easy. We are lacking purpose-built vessels to carry the freight on the water on the routes that we are identifying.

 

Baumel, C. P. 2008. The Mississippi River System Shallow Draft Barge Market—Perfectly Competitive or Oligopolistic? Journal of the Transportation Research Forum, Vol. 47, No. 4, pp. 5–18.

Dager, C. A. 2013. Fuel Tax Report, 2011. Center for Transportation Research, University of Tennessee, Knoxville.

Davis, S. C., S. W. Diegel, and R. G. Boundy. 2014. Transportation Energy Data Book, 33rd ed. Oak Ridge National Laboratory, Oak Ridge, Tenn.

Kruse, C. J., D. Ellis, A. Protopapas, and N. Norboge. 2013. New Approaches for U.S. Lock and Dam Maintenance and Funding. Texas A&M Transportation Institute, Texas A&M University, College Station.

NAS. 2015. TRB special report 315: funding and managing the U.S. inland waterways system: what policy makers need to know.  Transportation research board, National Academy of Sciences.  157 pages.

Tolliver, D, et al. October 2013. Comparing rail fuel efficiency with truck and waterway. Transportation Research Part D: Transport and environment. volume 24 pp69-75.

 

 

Posted in Ships and Barges | 2 Comments

Trucking and Fracking

September 18, 2013. The Transportation Needs and Impacts of Fracking-Based Energy Extraction. U.S. Department of Transportation, Federal Highway Administration

fracking and trucks top image

 

 

 

 

 

 

 

May 16, 2012. Jack Olson. Impacts of Heavy of Oversize Truck Shipments on the U.S. Highway Network

In the early 1990s, these rigs weighed about 90,000 pounds. Today they weigh about 110,000 pounds. This is true for most of the equipment used in the oil industry; it is getting larger. There are many different kinds of equipment necessary to bring an oil well into production, and the number of truckloads that are involved with each of these oil productions is dependent on whether the well is drilled vertically or horizontally. It is also dependent on the depth of the well, the moving efficiencies of the companies that are moving the pieces of equipment, and a variety of other factors that influence the overall figures. A vertical well takes about 400 truckloads one-way, and a horizontal well takes about 1,150 truckloads one-way, or 2,300 truckloads total, inbound outbound.

fracking trucks on the road

Several of the loads that are used to drill a well are oversized or overweight, many of them exceeding the legal loads in North Dakota of 105,500 pounds on most of our highways. The largest of these is the mud pump, which weighs 164,000 pounds. There are two of those that move into each of the sites. Of the 100 or so loads used to move just the drilling rig portion of the operation when bringing a well into production, 40 to 50 feet are overweight, and 3 out of 4 loads are also oversized.

fracking truck overloads in pounds

 

 

 

 

 

 

 

 

 

Oil is initially transported to rail facilities or pipeline locations by collection pipelines or trucks – almost exclusively by trucks. About 70% of all oil is currently being trucked from wells to pipelines and transfer locations. On average, a typical Bakken well produces about three truckloads of oil/day during its first year production.

Bakken oil wells produce about one barrel of salt water for every three barrels of oil during the first year of production. Salt water is transported by pipelines in some cases, but most of it is trucked to saltwater disposal sites.

Individual wells are the destination of sand or proppants, which are used to maintain the cracks in the formation so the oil can seep to the well bore.Three years ago, Williston, North Dakota was the only location receiving sand for the fracking process. Today, fracking sand and proppants are shipped to several locations by rail and then by trucks for final delivery to the well sites. The same is true of pipe used in the oil drilling phase. Again, it is brought into the state by rail to several different locations and then transported by truck to the drilling site. In addition to the state’s pipeline infrastructure, which is capable of transporting about 535,000 barrels/day, there are 13 rail facilities capable of transporting about 720,000 barrels/day. Unfortunately, rail and pipeline transportation capacity is not always necessarily available relative to the location of oil production. The typical truck, similar to the one used to transport saltwater, can transport about 220 barrels of oil per load.

The EOG Resources Rail Transload Facility near Stanley, North Dakota currently ships 65,000 barrels/day. Every day, 125 truckloads deliver between 20,000 and 25,000 barrels of oil to the facility.Depending on their size, each of the state’s rail transload facilities have similar truck-generating impacts on the system.

Mark Murawski “Transportation Patterns and Impacts from Marcellus Development”

Each well pad typically uses 3 to 5 acres of land per well and 6-8 wells per pad and developed over 4 to 6 week period. We have 5000 tons of aggregate needed which generates 400 truck trips to do that. That there is actual drilling that occurs that requires more equipment, water and cement that generates another 150-200 truck trips over another 4 to 5 week period.

The third stage is the fracking we actually take the natural gas deposits that takes another 800 and 1000 truck trips transporting 3-6 million gallons of water and frack sand over another 1-2 week period. At the end of the day, per pad, you’re looking 2-3 months of development of today 1250-1600 cumulative truck trips over roads that maybe had 100 or 200 vehicles a day on them previously.

Some roads went from 150 to an additional 700 trucks per day and that has been quite a challenge.

So with the look at is two thirds of our road system and Lycoming County is locally owned by different municipalities and not the state of Pennsylvania. The other third is owned by the state. Another concern we have is the accelerated deterioration to our lifecycle payments on roads that are not bonded. So who’s going to pay that bill? In Pennsylvania basically the transportation funding is derived from the gas tax at the state level.   But we have no comprehensive database on the condition of local roads. We do on the state road system.

The railroad impacts have been significant as well. Right not about twenty percent of their rail traffic is gas related and it helps take trucks off the road, but it’s not a substitute but there still needs to be an interface point since the wells are in locations not served by rail, truck traffic still has to happen there. You see a lot of types of Marcellus gas commodities transported by rail such as frack sand and the pipe and other kind of equipment related to make the and they come from a large swath of the United States.

Our main transfer terminal point between rail and truck freight for Marcellus or for anything is the Newberry Rail Yard which is now operating at full capacity

Obviously the siting of the wells being in remote areas that are difficult to access and the trucks going to small communities that have an inadequate capacity to handle all of the sudden traffic at intersections-these have definitely raised public discontent.

 

Dr. Cesar Quiroga Fracking-based Energy Development and Transportation Impacts and Needs

when we looked at the numbers that we look at fifty to sixty percent of the selected segments which were expected to have less than five years of remaining life. So that’s quite significant. One of the things that we did then was to try to estimate the pavement life. We developed a couple of tools to be able to do this. For those of you familiar with the energy development industry you need to dispose of the saltwater using disposal facilities, typically injection wells.

Many of these injection wells are permitted by the number of the maximum barrels they can receive per day. If you look at any number, for example 20,000, you can translate that into the number of truckloads you receive per day or per year and if you are familiar with the design of the different types of facilities can be designed for different types of ESALs. If you assume a rural road and assuming that it is new, at this rate 20,000 barrels a day in the facility may not have more than four years of life assuming that it was new when the process started.

One other thing that we did as an example was the estimate of impact statewide. We produced a high level estimate for the state of about $1 billion per year on state roads. Taking into consideration that local and county roads account for a roughly the same amount of mileage, we came up with an estimate of about $2 billion a year which is quite significant.

There were some assumptions that we had to make regarding the buffer around which we had some impact within the facilities-we didn’t include U.S. highways– So if anything the impact would be higher than the number I just mentioned. Another important part to keep in mind is that you may have overweight loads.

Just to give you an idea how important the overweight factor is if you look at 80,000 pounds is the reference and if you look to increase the overload to 100,000 pounds, an increase in weight is only twenty percent, but the increase in the impact is 240% which is quite significant, and that is something we should not forget.

It has been documented for example here-I live in San Antonio very close to the Eagle Ford and when the increasing of truck traffic became evident, there were also increases in documented crashes and fatalities. You can document this using other commercial data, for example, commercial vehicle violations, but the impact that I mentioned regarding overweight. Well, it turns out that a significant number of violations pertained to exceeding the maximum tandem axle weight as in this case is that of 34,000 pounds and note that energy-related traffic is ranked higher than non-energy-related traffic.

Let me try to summarize some of these issues in terms of things that are happening right now. I think nationwide there is an increasing amount of awareness When you talk to stakeholders and the county officials, it kind of depends. Most of the focus is related to environmental and water issues. One of the needs that I see is to continue to increase awareness about the impact on transportation and infrastructure with the numbers I mentioned earlier.

 

 

 

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Biofuel distribution wastes valuable diesel fuel

Biofuels can’t use the existing refined petroleum distribution pipeline system, by far the cheapest way to move fuel — 17.5 times cheaper than truck, 5 times less than rail, 2.25 times less than barge, on average (Curley), so delivery of biofuels consumes finite, far more energy-dense diesel fuel on rail, truck, and barge to be mixed in gas/diesel storage tanks, most of which aren’t served by rail:

gasoline distribution and consumption

ethanol distribution system

Source: National Commission on Energy Policy’s Task Force on Biofuels Infrastructure. 2008. Bipartisan Policy Center, Washington D.C., U.S., www.energycommission.org 

Notes from May 2011 APEC Biofuel Transportation and Distribution Options

Use of Existing Fuel Products Pipelines for Biofuels

Shipments Ethanol cannot easily be shipped via fuel products pipeline because it is a good solvent and would remove sulfur and other impurities from the pipeline system, resulting in contamination of the shipped ethanol.

Biodiesel is also a good solvent and could remove sulfur and other impurities from the pipeline system, resulting in contamination of the shipped biodiesel. In addition, there is concern regarding traces of biodiesel left over in the pipeline system. There is a possibility that trace methyl ester (biodiesel) could disarm the coalescers in aircraft fuel and potentially compromise the safety of the aircraft.  There is thus a proposal to limit the methyl ester content in the pipeline system in the USA to 5 PPM as a result of this concern.

A national ethanol pipeline?

Obstacles to Ethanol Pipeline Shipments There are 2 types of challenges involved in moving ethanol through a pipeline:
1. Challenges due to the corrosive nature of ethanol.
2. Challenges due to incompatibility with other products and substances within the pipeline.

The obvious challenge is that ethanol behaves so much differently than the refined petroleum products that are typically moved through pipelines.  More work is needed to find ways to overcome ethanol’s effects on the pipe, the valves and the pipeline systems themselves.

A key consideration is whether a new dedicated pipeline should be built, and if built, where it should be located. The other key question is whether long-term prices and demand would be able to support the building of a vast trans-national pipeline. In the United States , even the Renewable Fuels Association (RFA)  has stated that it is not certain that a dedicated ethanol pipeline would provide the same transport security as the more traditional barges, rail cars, and trucks.

Ethanol Solvency Issues: Ethanol’s solvent properties pose additional challenges. Over years of use, small quantities of residual sulfur and dirt from petroleum products can build up in existing pipeline systems.  Although these are not soluble in petroleum products, they can be in ethanol, which can lead to discoloration and product contamination.  Ethanol (and biodiesel) can strip lacque rs and deposits from internal pipeline surfaces and carry them as impurities. A dedicated ethanol pipeline would not encounter these issues, because these contaminants/deposits only arise from prior transport of petroleum products.

Materials Compatibility: Compatibility and corrosion issues can arise because of the way ethanol reacts with some materials in the pipeline and associated equipment. Ethanol and biodiesel can also degrade materials used in gaskets, o-rings, and seals used in fuels transportatio n and storage systems. Elastomers can experience swelling, shrinking and cracking when exposed to ethanol or biodiesel . Polymers used for coatings may be degraded by certain b iofuels as well.Corrosion of certain non-ferrous metals used in gauges, meters, valves, and pumps may occur . Any part of the supply system that will be converted to biofuels service needs to be assessed for materials compatibility and refitted with more resistant materials where required.

Stress Corrosion Cracking: Another challenge experienced in ethanol transportation by pipeline is Stress Corrosion Cracking (SCC) associated with ethanol movement and storage in pipelines and storage tanks. Stress corrosion cracking (SCC) can be defined as the slow growth of cracks along the inside of the pipeline, which are caused by mechanical stress and exposure to a corrosive environment. Research, largely funded by pipeline companies, has made great strides in addressing this problem. Industry/government research by Pipeline Research Council In ternational, Inc. (PRCI) 8 has found that ethanol-gasoline blends containing up to 15 percent ethanol by volume (E-15 and below) can be transported in existing pipelines without any design or operational modifications. PRCI also found that higher ethanol-containing blends (E-20 and above) and fuel-grade ethanol can be transported without SCC when certain commercial inhibitors are added. The efficacy of commercial inhibitors to mitigate SCC must be assessed prior to their use.

Water and Biofuels Fuel Quality: Small amounts of water enter pipeline systems from petroleum fuels, terminals and tank roofs. This is generally not a problem during pipeline transportation of refined petroleum products, because the water can separate in a tank and can be drained off. Unlike petroleum products, ethanol has an affinity for water as it flows through the pipeline network. The water-ethanol mixture has the potential to separate from petroleum products with which it may be mixed, resulting in degraded fuel quality. This can be managed by taking steps to cover tanks and remove excess water at certain points in the supply and distribution system.

Typical Biofuel Transport Modes

Biodiesel and biodiesel blends are transported primarily by dedicated (or washed) tanker trucks and rail cars. I f the truck or railcar was used for diesel shipment in the previous load, no washing is needed, but if another type of petroleum fuel was shipped, the tank must be washed.

Ethanol and ethanol blends are also transported mainly by dedicated (or washed) tanker trucks and rail cars. If the truck or railcar was used for gasoline shipment in a prior load, no washing is needed, but if another type of petroleum fuel was shipped, the tank has to be washed.

Ethanol and ethanol blends are generally not transported via pipeline due to some concerns regarding corrosion and contamination.

Primary terminals (also called “product terminals”) are generally located near major markets and transportation modes. Some terminals are located at refineries, while others are separate tank farms that receive fuel products by pipeline, tanker truck, rail car or marine tanker. Primary termin als are equipped with product delivery and loading racks that vary from one terminal to another. For example, some terminals linked via pipeline will not necessarily have racks that are adapted for other modes of transportation (train or truck). In region s with ample waterways, petroleum products may be transported to primary terminals by marine tankers.  In regions that are essentially land-locked, products are often transported from refineries to terminals by pipeline. For marine shipments of biofuels, there may be additional storage infrastructure required at the marine terminal.  From the marine terminal, the biofuel would be delivered by truck or rail, unless a dedicated biofuels pipeline could be justified. Since primary terminals are designed to provide downstream distribution of finished products, they all have tanker trucks and high-performance fuel injection equipment at the loading rack to prepare fuel blends (i.e., in-line blending).

Pipelines are a key part of the petroleum fuel transportation infrastructure. The petroleum fuels are transported via pipeline to primary or secondary terminals, which then serve as distribution points to nearby retail sites that are supplied by tanker trucks.  It is typically at these terminals that biofuels are blended with petroleum fuel for distribution.  At present, biofuels are usually transported to the blending terminals by truck, since there are no dedicated biofuel pipelines and the terminals are not generally linked to the railway network.

Rail Cars: Biodiesel (B100) or ethanol (E100) could move by rail from the biofuel production plant to destination terminals (mainly primary terminals or, in some cases, secondary terminals equipped with rail spurs). Rail shipment is generally the most cost-effective delivery method for medium-range and longer-range destinations (i.e., 500 to 5,000 km) that are incapable of receiving product by barge, tanker or pipeline. Rail line coverage and access va ry from region to region. Some te rminals lack rail receipt capability, requiring biodiesel (B100) and ethanol (E100) to be transported by truck.  Rail delivery might also prove infeasible in colder climates, unless the rail cars are heated and a heating system is in place at the destination terminal.

Because of the number of railcar units, the smaller volume of biofuel shipped per unit , and the laborious process of cargo unloading and inspection, rail shipments require more effort compared with ocean tankers, for example. The transportation of biodiesel and ethanol via train also requires more complex logistics (availability of heated or dedicated rail cars, delays due to cleaning rail cars in the case of non-dedicated rail cars or heating rail cars at the terminal, etc.). In some cases, installing heating systems or rail spurs adds to the terminal adaptation costs.

Tanker Trucks: In many cases, a tanker truck delivers B100 or E100 directly from the production plant to nearby terminals. In distant markets, tanker trucks may also pick up biofuel blends at primary terminals (that have received biodiesel or ethanol by tanker or rail), for delivery to secondary terminals that either cannot take product other than by truck or that have insufficient tankage for larger quantity deliveries. The redistribution of bi ofuel blends to retail outlets and end-users is also made by trucks.

Typical Blending and Distribution Practices

Ethanol is usually “splash blended into tanker trucks or rail cars that already contain gasoline.  The ethanol blended with the gasoline mixes readily and does not stratify.

Biodiesel is also generally splash blended or blended in tanks near the point of use. In the European Union (EU), blending is primarily done “in line” at refineries. The “splash blending” of biodiesel may result in some shock crystallization,depending on the temperature during blending or the means by which the splash blend is administered.  In-line blending provides contact between the diesel and the biodiesel and mitigates this risk. At primary terminals for ethanol blending, E100 is injection or splash blended into trucks (or rail cars) before being taken to secondary terminals or to retail.  Similarly, at primary terminals for biodiesel blending, the B100 is blended with the diesel by injection (or in some 14 cases splash blending) before being distributed in its blended form B5-B20) to secondary terminals or retail outlets (service stations, card locks, users with their own storage facilities). At this stage, the modes of shipment used no longer have to be insulated and heated.

Existing petroleum distribution terminals usually do not have rail access, creating a distribution infrastructure challenge for biofuels. Petroleum distribution facil ities were generally designed for pipeline distribution of petroleum fuel products. In r emote or smaller petroleum distribution terminals, product receipts were designed around truck receipt and delivery. In most cases, therefore, distribution of E100 or B 100 or blended biofuel product by rail is usually impractical.

From secondary terminals (or depots), blended biofuel product is moved mainly by tanker truck to retail outlets fueling stations–petrol and gasoline stations with direct delivery to end-users. Delivery distance, costs and carbon footprint of distribution may be greater for biofuel blends than for purely petroleum-based fuels due tho the concentration of biofuel feedstocks and refineries in agricultural regions which are remote from m any key urban population centers.

 

The cost of shipping feedstock s greater than 100 miles is generally prohibitive.  In the case of adv anced biofuel feedstocks such as biomass for cellulosic ethanol, even with densification technologies, the transportation costs become prohibitive beyond 100 miles.  Thus, the location of future cellulosic ethanol plants is likely to be dictated by proximity to feedstock as opposed to proximity to market, similar to the current situation with first generation biofuels. This also implies that most feedstocks will be delivered by truck, and that most biofuel production facilit ies will be located in rural areas close to feedstock, rather than close to urban fuel markets. Transportation factors to consider as biofuel production continues to expand include:

  • The capacity of the transportation system to move biofuel, feedstock, and co-products produced from biofuel, especially over long distances to fuel markets.
  • The availability of feedstock close to biofuel plants within 100 miles
  • The proximity of feedstocks and biorefineries to co-product markets.
  • Uncertainty about the size and location of biofuel demand from terminal s which consolidate, trans load, and distribute biofuels for blending.

Government policies towards biofuels may decrease this uncertainty. The lack of excess transportation capacity reduces flexibility in case of sudden changes in transportation demand and distribution patterns. Changes in these patterns brought on by rapidly increasing biofuel production could impact the logistics of rail networks, highway congestion, and marine logistics.

Co-Product Transportation Issues

Ethanol plants that use corn and other grains as feedstock produce a co-product called distillers grains (DDGS dried distillers grains with solubles, WDG-wet distillers grains, and MDG-modified distillers grains).  For every 56-pound bushel of corn, 17.5 p ounds of DDGS and 2.76 gallons of ethanol are produced, on average.  Slightly different yields of DDGS are produced from other grains. Dairy cattle operations and cattle feedlots are the primary domestic users of distilled grains as a protein supplement for the ruminant animals. Research is ongoing for increasing the DDGS use by poultry and hog operations, which currently is limited due to nutritional challenges DDGS present to non-ruminant animals. DDGS are initially marketed locally, and delivered by truc k. However, as production grows, access to wider markets may rely on rail or marine transport. Facilities using grain may also choose to adopt fractionation technologies to extract fibre, protein, starch or sweeteners as co-products. These food-grade co-products would also require transportation infrastructure to deliver these products to market.

Biofuel Infrastructure. Managing in an Uncertain Future. Research and Innovation, Position Paper 03 – 2010

At present, biofuel is first sent to blending terminals through tanker trucks, rail cars, and barges, where they are blended with gasoline or diesel and then sent to consumer filling stations via trucks. In the U.S. 67 percent of the ethanol is transported to blending terminals via trucks, 31 percent by rail cars, and 2 percent by barges. Biofuel is also exported through ships to receiving terminals which then blend them with gasoline and then transport them to filling stations using trucks.

The U.S. passed the Energy Independence and Security Act of 2007 (EISA), which required the creation of a Renewable Fuel Standard (RFS) program. The U.S. environmental Protection Agency issued revised RFS effective on July 1st 2010 (called RFS2) that for the first contained specific fuel volume requirements (Figure 3)

References

Curley, M. 2008. Can ethanol be transported in a multi-product pipeline? Pipeline & Gas Journal 235:34

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Peak oil in the Congressional record 2013

Peak oil in the Congressional record 2013

Also see: Peak Oil in the Congressional record: Overview

Scorecard from 7 documents: 6 denials, 2 affirmations of peak oil

Denials

  1. United States Secretary of Energy Moniz
  2. House of Representatives David Schweikert, Texas
  3. House Representative Pete Olson, Texas (2 times)
  4. Jeffrey B. Hume, vice chairman, Strategic growth initiatives, Continental Resources, Inc., Oklahoma city, OK
  5. Adam Sieminski, Administrator, Energy Information Administration (EIA), U.S. Department of Energy
  6. House representative Dana Rohrbacher, California.

Affirmations of Peak Oil

  1. Randy Udall (Read into the record by Senator Tom Udall of New Mexico)
  2. Jefferson Keel, President, National Congress of American Indians

2013/6/18 House Hearing – Department of Energy Science & Technology priorities

Denial by United States Secretary of Energy Moniz & House of Representatives David Schweikert, Texas

House of Representatives David Schweikert, 4 denials in 2014: If I were to hop in the literature right now and go back a dozen years ago, whether it be you or many of the smart people who you hang around with, what would you have written about peak oil?  Small problem is we got it wrong. And we built tax codes here, we built environmental codes, we built regulatory codes, actually even foreign policy based on a premise that was absolutely wrong ().

United States Secretary of Energy Moniz:  Sir, that is exactly along the lines of what I was trying to emphasize, that I think we don’t know the future. We always think of the future as a linear extrapolation of the present, and it is not. And it is those innovations that do so much to change the future. I will just say one thing, however, in terms of peak oil. I have witnesses; I was never a peak oil believer.

Schweikert:  I Googled you and I did not see you pop up. I did see the guys just down the hallway from you at MIT writing huge articles about how, right now, we should be about $200 barrel in oil as of this month.

Moniz: We didn’t even get close. But on peak oil, I mean, our view was always that it is not molecules you run out of; it is at what cost can you get the molecules?  And also just to reinforce your point, in natural gas, of course, it was very recently when major heads of major corporations not only got it wrong but put their money in the wrong place.

Schweikert:  But you have to agree it is a brilliant example of technology is faster-moving and smarter than we are because someone out there is coming up with it. It is—you know, when I hold up the book of—you know, the Population Bomb from 1968, the only thing they got right was the author’s name. Everything in the book got wrong because the arrogance of not knowing what the next breakthrough is.

2013/9/13 REMEMBERING RANDY UDALL

Affirmation of Peak Oil. Excerpts of Obit in the Aspen Times: James “Randy” Udall, a native son of the American West, died June 20, 2013, on the eve of the Summer Solstice, doing what he loved most, hiking in the remote Wind River Mountains. He was 61 years old. In 2005, Randy co-founded the Association for the Study of Peak Oil-USA to track the shifting balance between world oil supply and depletion. Randy Udall told hard truths: “We have been living like gods,” he often said. “Our task now is to learn how to live like humans. Our descent will not be easy”. Randy did not hesitate to go toe-to-toe with oil executives, calling for accountability, when discussing the realities of peak oil (Read into the record by Senator Tom Udall of New Mexico)

2013/7/31 THE ALASKA NATIVE TRIBAL HEALTH CONSORTIUM LAND TRANSFER ACT

Affirmation of Peak Oil. As tribal communities grow, it is essential to look at economic and environmental realities in order to make critical decisions about our future. That means tribal planning must address issues such as climate change, peak oil and food insecurity. Food and energy consume huge portions of tribal economies and must be considered in relation to tribal self-determination. The new millennium is a time when we are facing the joint challenges of an industrial food system and a centralized energy system, both based on fossil fuels, and both of which are dam- aging the health of our peoples and the Earth at an alarming rate. Tribal communities have long supplied the raw materials for nuclear and coal plants, huge dam projects, and oil and gas development. These resources have been exploited to power far-off cities and towns, while many tribes remain deficient in sources of heat or electricity (Jefferson Keel, President, National Congress of American Indians)
.

2013/7/23 OVERVIEW OF THE RENEWABLE FUEL STANDARD (RFS)

Denial. The RFS was designed for a U.S. energy future that no longer exists, that of a peak oil and increasing demand. The RFS mandate will be met this year using most of the older excess credits in the system. In future years, if unchanged, this will be much more difficult. Compliance costs are spiking, especially for small refiners who don’t blend fuels and generate their own credits. The RFS has helped increase corn prices, and that has hit consumers back home, at Kroger’s, at Safeway, Wendy’s …With all due respect to some of the panelists who said that there is not an impact on food prices, RFS does have that impact. Wendy’s came into my office a month ago, wanted to talk about Federal issues. You think they want to talk about Obamacare, increasing taxes, all sorts of things? No. They wanted to talk about RFS corn-based ethanol and how it has increased their cost of doing business (House Representative Pete Olson, Texas)

Jack Gerard,  CEO of the American Petroleum Institute: The cost of pure ethanol has always been higher than a gallon of gasoline. Consumers are figuring this out. That is why even with flex-fuel vehicles, they are not buying E85, even though it is available. In Minnesota they have increased the number of E85 filling stations, but the demand for E85 is going down.

2013/7/16. Gas Prices

Denial. These are truly are exciting times in the energy business. Each day at Continental, we witness the assumptions underlying “peak oil” theories crumble under the power of creative minds and pioneering technology. (Jeffrey B. Hume, vice chairman, Strategic growth initiatives, Continental Resources, Inc., Oklahoma city, OK

2013/6/26 HOUSE Hearing OVERVIEW OF THE RENEWABLE FUEL STANDARD: GOVERNMENT PERSPECTIVES   

Denial. We owe the American people a thorough review of the RFS for one simple reason: The American energy outlook that drove the creation of ethanol tax subsidies in RFS is in the dustbin of history. Tax preferences for corn-based ethanol were created last century and mutated into RFS this century. Why the spur of government activity? Because we thought we hit peak gas. Meaning that to feed our ever-growing demand for gasoline we had to buy more and more oil from foreign sources that weren’t reliable. Our production was going down every single day. But the American innovator, with new technology, has pushed peak oil back to the next century. And while I think the best solution to this problem is to repeal RFS, my mind is not closed. But it is not empty either (House Representative Pete Olson, Texas)

2013/2/13  HOUSE Hearing – American Energy Outlook: Technology, Market & Policy Drivers

2 Denials from Adam Sieminski, Administrator, Energy Information Administration (EIA), U.S. Department of Energy and House representative Dana Rohrbacher, California.

ROHRABACHER.  I would like to ask, a few years ago we were gloom and doom about peak oil and how we are going to be energy-wise, things are going to get worse and worse. What about peak oil and gas? Is that just a false alarm?

SIEMINSKI.  The problem that I saw as an energy economist, the problem that I always had with the peak oil hypothesis was that it was entirely geology-based. The view assumes that the resource base is completely known, and once you produce half of it that you inevitably are on a downturn. I think that this Committee particularly understands that there is a role for both prices and technology to dramatically change our understanding of the resource base. And that is what we have seen.

ROHRABACHER. When you talk about price, which is one thing, we heard it earlier about the importance of efficiency. Well, assuming that mandates and regulations are what causes efficiency as compared to price, and when you allow the price to go up, there is going to be a great deal more efficiency. People will turn off their lights. Actually, we found that out in California. If indeed the price of electricity goes up, again, we go back to market-based solutions. Rather than having the government step in to try to mandate what direction we go, quite often, the market-based solutions actually get the job done better.

Also See:

Peak oil in the Congressional record 2015

Peak oil in the Congressional record 2014: 7 denials, 1 affirmation

Posted in Congressional Record U.S. | 1 Comment

Secretary of Energy Ernest Moniz in the Congressional Record

As I was researching “peak oil” in the congressional record, I ran across this testimony from current Secretary of Energy Moniz, as well as some of his other points of view on different energy matters, of which I’ve extracted just a few.  Moniz defends climate change quite well in this congressional testimony, despite the challenges from stone age congressmen who disagree.  But his views on Peak Oil are disappointing.

2013/6/26. Overview of the Renewable Fuel Standard (RFS)

House of Representatives David Schweikert: If I were to hop in the literature right now and go back a dozen years ago, whether it be you or many of the smart people who you hang around with, what would you have written about peak oil?  Small problem is we got it wrong. And we built tax codes here, we built environmental codes, we built regulatory codes, actually even foreign policy based on a premise that was absolutely wrong ().

United States Secretary of Energy Moniz:  Sir, that is exactly along the lines of what I was trying to emphasize, that I think we don’t know the future. We always think of the future as a linear extrapolation of the present, and it is not. And it is those innovations that do so much to change the future. I will just say one thing, however, in terms of peak oil. I have witnesses; I was never a peak oil believer.

Schweikert:  I Googled you and I did not see you pop up. I did see the guys just down the hallway from you at MIT writing huge articles about how, right now, we should be about $200 barrel in oil as of this month.

Moniz: We didn’t even get close. But on peak oil, I mean, our view was always that it is not molecules you run out of; it is at what cost can you get the molecules?  And also just to reinforce your point, in natural gas, of course, it was very recently when major heads of major corporations not only got it wrong but put their money in the wrong place.

Schweikert:  But you have to agree it is a brilliant example of technology is faster-moving and smarter than we are because someone out there is coming up with it. It is—you know, when I hold up the book of—you know, the Population Bomb from 1968, the only thing they got right was the author’s name. Everything in the book got wrong because the arrogance of not knowing what the next breakthrough is.

Efficiency

The targets are across-the-board efficiency, where we still have many opportunities that are lifecycle-cost beneficial, whether that is vehicles, buildings of course are an enormous opportunity, industrial processes. Then, we need to go to low-carbon, carbon-free alternatives in the power sector, which is probably the leading sector for getting carbon out of the sector. We have three options: We have nuclear, we have renewables, and we have carbon capture and sequestration. And I believe we need a multipronged approach on all of these, and that is what, in fact, the President’s budget proposes. That is what we are doing

Wind

Mr. BUCSHON. why would private sector venture capital be leaving renewables?

Secretary MONIZ. Certainly, one of the reasons has been the large uncertainties in the wind case around the tax.

Mr. BUCSHON . You may or may not agree that it is because that at this point in our history, they are not economically viable and—without massive Federal Government infusion of cash into those industries, is that true or not true? The question is is are we getting ahead of our- selves by—at this point without R&D showing that these are economically viable, getting ahead of ourselves essentially? When venture capital is leaving those areas of our economy, should the Fed- eral Government, other than R&D in those areas, continue to put this kind of money into those when it is clear that the private sec- tor and venture capital are leaving them because they are not economically viable? That is the bottom line.

Secretary MONIZ [replies several times that wind is competitive]

Fusion

I think fusion and plasma science are an important area for continued DOE support. Plasma science really is another kind of phase of matter and then fusion has a long-term—and it is still long-term possibility as an attractive energy source. So I support the general idea of continuing fusion research.

Mr. KENNEDY. Just because it is a long-term horizon doesn’t mean that we don’t make the in- vestment. Would you agree?

Secretary MONIZ . No, we have to. If you don’t make it today, we won’t have it in the future.

How will DOE spend money this year?

Mr Kennedy: The Fiscal Year 2014 administration budget includes 2.78 billion for the Office of Energy Efficiency and Renewable Energy, which proposes a number of increases to its programs across the board. You also mentioned in your testimony, sir, the ‘‘Race to the Top’’ initiative as part of your larger focus on national energy policy. You touched upon this a little bit earlier, sir, but if there are parts of our across-the-board energy portfolio that are not yet cost- competitive because of barriers to technological advancement, how would you propose going forward to lower those barriers to make the technological advances to make it cost-effective?

Secretary M ONIZ . Well, I think we need a portfolio of instruments. At the foundation is the basic R&D, which gives us, you know, the new possibilities. But then, of course, we have something like ARPA–E, which takes promising but still high-risk technologies and moves them hopefully to the place where they become market-attractive for investors. And I think we are seeing a lot of success now developing there and that the program is still new. I mean it is about 3–1/2 years old, well, going on 4, I guess. So that is very, very encouraging. We also have them in programs and the applied energy programs in selected areas for large-scale demonstrations. The gentleman from North Dakota, for example, mentioned carbon capture and sequestration. That is a place where demonstrating the viability of large-scale storage is just not credible without DOE, without government investment. And then when it comes to deploying or helping the deployment, then we have things like the loan programs

LNG

Mr. WEBER. We have a unique opportunity in the history of the world for America to take the lead, as you heard earlier from one of my colleagues. Are you committed to doing everything you can to get those—that permit process moving forward, especially LNG, natural gas, and making it expeditious so that we can maintain our competitive edge so that we can have that public interest in mind that you yourself talked about?

Secretary MONIZ. Well, again, to clarify, I mean we are not engaged in permitting in terms of production or exploration but in terms of LNG exports certainly.

URANIUM

Mrs. LUMMIS. I want to visit with you about what has been happening with regard to the domestic uranium industry. Sometime ago a 10% cap was negotiated so that DOE would only transfer, sell, or barter their uranium stockpile at a rate below 10% of current domestic uranium demand. And that agreement was abrogated and the price of uranium fell through the floor. And my State, which produces a great deal of uranium—albeit domestic supply only supplies 10% of our uranium for our nuclear power needs—was hurt badly, badly by the DOE’s decision to abrogate the 10% cap. You know, the DOE has the authority, the power to make or break uranium production in this country because of prices and their ability to dump excess product on the market and destroy prices here, thereby making our country actually more reliant on foreign providers of uranium. My next question is about USEC. Over the last 18 months, Dr. Moniz, the taxpayers have been asked to directly subsidize the U.S. Enrichment Corporation to the tune of over $1 billion in cash for uranium and other incentives. I want to understand how big this hook is that the taxpayers are hanging on. Specifically, is it DOE or is it USEC who is financially obligated to safely decommission the enrichment facility in Paducah, Kentucky, and hand it over to DOE? And how much do you anticipate that costing?

Secretary MONIZ . I cannot give you an exact cost estimate right now… There is a sensitivity that currently we have no American origin uranium enrichment technology, and consequently, if and when we need en- riched uranium for military purposes, we will not have the option.

 

 

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Peak oil in the Congressional record 2015

[ I’ve meant to post more but haven’t gotten around to it, but there are quite a few other summaries of house and senate hearings on energy in category Experts/GOVERNMENT/Congressional Record U.S.

Also see: Peak Oil in the Congressional record: Overview

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

E42. January 9, 2015. Fracking is jeopardizing the environment and the U.S. Economy.  Congressional Record.

House Representative Jim McDermott: I rise today to express my growing concern about the economic issues of fracking. The once booming oil fracking market could be headed for a bust. If a bust in the oil fracking sector does happen, it could create massive losses on Wall Street and for investors on Main Street in 2 ways.

  1. Fracking oil drillers issued massive amounts of debt to construct the necessary wells. With the price of gas falling, many oil fracking drillers now face cash shortfalls. As a result, it is becoming more and more difficult for frackers to meet their debt servicing obligations. If the debt servicing obligations are not met, investors on Main Street and Wall Street could be left holding billions of dollars of worthless bonds.
  2. Many companies took out derivatives contracts against market fluctuation, insuring stable cash flow. Losses are mounting on these contracts as oil prices fall. Wall Street banks that own many of these contracts will have to absorb massive losses. The unexpected shock of falling oil prices may destabilize the balance sheet of these big banks, creating the conditions for another financial crisis.

Below is an article from Truth-out.org that further explains this issue by Ben Ptashnik, Russia blamed, U.S. taxpayers on the hook as fracking boom collapses:

“…When gas fracking first popped onto the scene, grandiose claims were made that the United States had 100 years of gas supply in shale, or 2,560 trillion cubic feet. And Wall Street rode that initial estimate. But in fact, no statistical evidence con- firmed the hyped claims of a 100-year shale gas supply…

By 2013, the U.S. Geological Survey refined that down to 481 trillion cubic feet—less than a 19-year supply based on 2013 rates of production.

Meanwhile oil fracking, which is separate from gas fracking, also needed huge injections of capital, and oil prices to stay at $85 a barrel or higher on average to break even. Many of the shale oil wells that have sucked up a huge amount of investment have also turned out to have short lives and their operators required continued infusions of capital to drill new wells to keep afloat, even as prices tumbled due to the glut they them-selves created.

Falling oil prices will place a huge stress on the world’s junk bond market as energy companies now account for 15% of the outstanding issuance in the non-investment grade bond market. The plunge in the prices of crude could trigger a ‘‘volatility shock large enough to trigger the next wave of defaults,’’ according to Deutsche Bank.

This explains why the Obama administration—with complicity of both congressional Democrats and Republicans—managed in the wee hours of the morning to slip a loophole into the supposedly ‘‘must-pass’’ cliff-hanger omnibus budget bill. This toxic Trojan horse, passed in December 2014, now includes a minor footnote provision that might cause taxpayers to pick up the tab on more than a trillion dollars (yes, trillion) if the energy market bubble implodes, which it must if oil stays at half the price it fetched just six months ago.

After last minute, heavy lobbying on the budget bill by Jamie Dimon of JPMorgan Chase and an army of 3,000 Wall Street lobbyists, it appears that once again sufficient insecurity and fear had been spread among the political class regarding destabilization of the financial markets (or withdrawal of campaign financing). They allowed a last minute amendment that killed Dodd-Frank protections, and allowed U.S. taxpayers to be shaken down to cover Wall Street’s shale gambling debacle.

The heavy-handed move by the financial industry has outraged progressives and libertarians alike. It seems that these Wall Street criminal could not resist the easy cash from Ponzi scheme market bubbles, and so they have stuck it to the U.S. public once again: Preposterously huge bonuses, Porsches, pricey call girls, and million-dollar Manhattan condos were at stake. [And why not?] After all, not a single one of those con artists went to jail last time.

Wall Street is now flooded with fracking industry derivatives contracts that protect the profits of oil producers from dramatic swings in the marketplace. Derivatives are essentially insurance policies taken out by the oil industry to guard against fluctuations in the cost of fossil fuel supplies. Dramatic swings rarely happen, but when they do they can be absolutely crippling. Derivatives taken out to ensure prices don’t go down are now creating billions in losses for those who sold such bets on the market; someone is going to have to absorb massive losses created by the sudden drop in oil on the other end of those insurance con- tracts. In many cases, it is the big Wall Street banks, and if the price of oil does not rebound substantially they could be facing colossal losses.

The big Wall Street banks did not expect plunging home prices to implode the mort- gage-backed securities market in 2008, and their current models also don’t have $60 oil prices included in projections. The huge losses may send a shock wave into the entire financial industry. It has been estimated that the 6 largest ‘‘too-big-to-fail’’ banks control $3.9 trillion in commodity derivatives contracts, those same gambling instruments that brought us the 2008 housing collapse. And a very large chunk of that amount is made up of oil derivatives. Combined with the huge flood of shale junk bonds on the market, the derivatives could initiate a bubble burst that could turn into a financial market implosion.

2015/6/3 National defense authorization act for fiscal year 2016

Denial. Same as 2014/5/6 A few years ago people were talking about peak oil, as if all of the oil that could be discovered had been discovered in the world; we were running out. Well, obviously, that has proven not to be true (Senator Cornyn, Texas).

Also See:

Peak oil in the Congressional record 2014: 7 denials, 1 affirmation

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Peak oil in the Congressional record 2014: 7 denials, 1 affirmation

Peak oil in the Congressional record 2014 from the U.S. Government Publishing Office by Alice Friedemann, www.energyskeptic.com

  • 7 government documents
  • 7 Denials, 4 from House of representatives David Schweikert of Arizona
  • 1 affirmation of conventional oil peak from James Hansen

Also see: Peak Oil in the Congressional record: Overview

2014/3/13 Keystone XL and the national interest determination.

  • Denial of peak oil – fracked oil will lead to US independence, can be sent to Europe to reduce Putin’s influence, but can’t be done without building the Keystone pipeline (Gen. James L. Jones, USMC (Ret.).
  • Conventional peak near but using tar sands will “screw our children and grandchildren and all the young people in future generations…. This is game over” (James Hansen)

2014/5/6 Energy savings & industrial competitiveness act of 2014. Denial. a few years ago people were talking about peak oil, as if all of the oil that could be discovered had been discovered in the world; we were running out. Well, obviously, that has proven not to be true (Senator Cornyn, Texas)

House of Representatives David Schweikert AZ (4 denials):

  1. 2014/2/11 Ensuring Open Science at EPA. Denial: It was only 10, 12 years ago if you and I sat in this room, we would have been hearing speakers, Members talking about Peak OilWe got it wrong but yet our tax policy, our environmental policy, our military policy was based on that data
  2. 2014/3/12 Science of capture & storage: understanding EPA’s carbon rules. Denial, same as above.
  3. 2014/6/25 Congressional Record H5761. Denial, same as above.
  4. 2014/7/16 Unfunded liabilities, the greatest threat to our future—house. Denial, same as above.

2014/11/18. A roadmap for prosperity—house H8067. Denial. 8 years ago, when President Bush was in, they were talking about something called peak oil theory, where they said we had already discovered all of the recoverable oil and it was going to get lower and lower, and it was going to be harder and harder to recover and that we were at our finite limits. That shows you how wrong science can be, because in the last 5 years we have had the largest oil boom in history right here in the United States (House Rep. Tom Rice, SC)

 

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Oil Infrastructure – pipelines, refineries, terminals

Sider, A. and Friedman, N. November 2, 2016. More than half of U.S. Pipelines are at least 46 years old. Building new systems has become harder amid opposition from landowners and environmental groups. Wall Street Journal.

More than 60% of U.S. fuel pipelines were built before 1970, according to federal figures. Recent disruptions on Colonial Pipeline Co.’s fuel artery running up the East Coast show why some energy observers worry that this is a problem.  Carl Weimer, executive director of the advocacy group Pipeline Safety Trust, said fuel pipeline systems can operate safely for decades if they are well maintained. But after 40 or 50 years, problems like corrosion increase.

U.S. OIL Pipelines 2013 (US DOT/RITA reports 49,974 miles of crude and 87,452 miles of refined product pipelines in Table 1-10: U.S. Oil and Gas Pipeline)

  • Transmission liquids pipelines delivered 8,305,840,173 billion barrels of crude oil
  • Transmission liquids pipelines delivered 6,642,068,030 billion barrels of refined products (gasoline, diesel, jet fuel, etc and natural gas liquids (propane, ethane, butane, etc) to terminals
  • In total,  transmission pipelines delivered 14.948 billion barrels of crude oil and petroleum products
  • Pipeline operators reported 192,396 miles of liquids pipeline in operation in the United States, with 60,911 miles devoted to crude oil, 63,532 miles transporting refined petroleum products (gasoline, diesel, jet fuel, etc), and 62,742 miles delivering natural gas liquids (propane, ethane, butane,etc)
Figure 11-30. Total Petroleum Product Movement

Figure 11-30. Total Petroleum Product Movement

Figure 11-26. Major U.S. Product Terminals with gas, diesel, jet fuel, etc for delivery to 160,000 service stations

Figure 11-26. Major U.S. Product Terminals with gas, diesel, jet fuel, etc for delivery to 160,000 service stations

Source: http://www.api.org/~/media/files/oil-and-natural-gas/pipeline/us-pipeline-map-api-website3.pdf

Source: http://www.api.org/~/media/files/oil-and-natural-gas/pipeline/us-pipeline-map-api-website3.pdf

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The difference between depletion and decline rate in oil fields

Notes from 26 page: Höök, M., Davidsson, S., Johansson, S., Tang, X. 2014. Decline and depletion rates of oil production: a comprehensive investigation. Philosophical Transactions. Series A: Mathematical, physical, and engineering science, 372

Depletion rate is the rate that the oil reserves are reducing

Decline rate is the rate that production is declining 

A database of 880 post-peak fields is analyzed to determine typical depletion levels, depletion rates, and decline rates. We found the size of oil fields has a significant influence on decline and depletion rates, with generally high values for small fields and relatively low values for larger fields.

Introduction

Non-renewable fossil fuels provide around 81% of the global primary energy supply and oil remains the single largest primary fuel, satisfying 33% of the world’s energy needs in 2009 (IEA, 2011). Given the high reliance on oil, particularly within the transportation sector, it is evident that policymakers and the public need reliable forecasts of future oil supply.

Two of the most fundamental concepts in the current debate about future oil supply are oil field decline rates and depletion rates. These concepts are related, but not identical. However, analysts and laymen alike tend to get these concepts mixed up, leading to misunderstandings and flawed conclusions.

In addition, the definition of depletion rates can vary.

The term decline rate refers to the annual reduction in the rate of production from an individual field or a group of fields, after a peak in production. Detailed empirical analyses of decline rates have been produced for well over 50 years and most studies tend to agree on the typical decline rates for different categories of field, despite some differences in details (Höök et al., 2009a, b). Possible causes of observed decline rates are debated. Some propose that the observed decline rates are mainly caused by underinvestment while others argue that the reason is simply physical limits to production rates.

Depletion rates refer to the rate at which oil is produced in a field or region expressed as a fraction of either the ultimate recoverable resources (URR) or the remaining reserves.

Depletion rates have been studied since the late 1970s (Flower, 1978) and the concept has become prominent in the peak oil debate due largely to the work of Campbell (1992; 1996; 2006; Campbell & Heapes, 2008) – although he is far from alone in using depletion rates. However, the definition of depletion rate and the methodology for estimating them has varied over time and has never been as standardized as is the case for decline rates. Perplexing terminology, inconsistent theory, lack of clear methodology, and different definitions have contributed to a confusion surrounding depletion rates.

Fundamentals of oil production

Conventional oil accumulates through long geological processes in underground formations known as reservoirs. Typical reservoirs consist of porous rocks, such as sandstone or carbonates, where petroleum resides in the tiny void spaces between the rock grains. An oil field may consist of one or several reservoirs reachable from the surface by drilling. Current global oil production is predominantly derived from conventional oil fields with minor contributions coming from natural gas liquids (NGL – ethane, propane, butane and pentane), unconventional oil, and other liquids. For historical reasons, oil is commonly measured in barrels corresponding to a volume of 42 US gallons or approximately 159 liters. An oil field may contain anything from less than a million barrels (Mb) to many billion barrels (Gb).

Robelius (2007) estimated the number of identified oil fields in the world to be around 47,500.

IEA (2008) estimated there are around 70,000 fields, but also notes that the exact number depends on how specific fields are delineated and highlights data discrepancies. However, the importance of individual fields to global oil supply varies widely, with around 25 fields accounting for one quarter of global oil production and a few hundred ‘giant’ fields (> 500 million barrels) accounting for approximately one half of global production (Höök et al., 2009b). All fields share similar overall behavior, although the magnitude of production can differ significantly. An oil field typically exhibits the production profile seen in Figure 1. However, significant deviations can be caused by development history, changes in technology or oil price, accidents, political decisions, sabotage, and similar factors. Some fields have short plateau periods, more resembling a single peak, while others (especially large fields) may keep production relatively constant for many decades. But at some point, all fields will reach the onset of decline and begin to experience decreasing production.

Figure 1. Idealized production behaviour of an oil field. Source: Höök et al (2009a).

Figure 1. Idealized production behaviour of an oil field. Source: Höök et al (2009a).

 

 

 

 

 

 

 

 

The extraction of oil from a reservoir is commonly divided into 3 production methods: primary, secondary and tertiary recovery. Several factors control the production flows in most oil fields. A basic understanding of these is necessary for better understanding of decline and depletion behavior. Physically, oil recovery is about fluid flows through the porous material that make up the oil field. Fluid movements in a reservoir depend on the following factors that are explained more comprehensively by Satter et al. (2008):

  • Depletion (leading to a decrease in reservoir pressure)
  • Compressibility of the rock/fluid system
  • Dissolution of the gas phase into the liquid
  • Formation dip
  • Capillary rise through microscopic pores
  • Additional energy provided from the underlying aquifer or the overlying gas cap
  • External fluid injection
  • Thermal, or other, manipulation of fluid properties

Fluid flow fundamentals

The extraction of oil is to a large extent decided by physical properties related to the geological formation of the reservoir in question and the fluid characteristics of the petroleum it contains. Variations in these characteristics cause production rates to vary from field to field. An oil reservoir carries its fluid in small microscopic pores within the rock, and the term porosity refers to the fraction of the pore volume compared to the total bulk volume. The larger the porosity, the better the rock is at storing fluids. The pores serve both as storage and as a transmission network for fluid flows. The French physicist Henry Darcy (1856) studied fluid flow through a bed of packed sand and derived an elegant expression to describe the behavior of the fluid, known as Darcy’s law (Equation 1). The expression involves important physical properties such as the ability of the porous medium (rock in case of oil reservoirs) to permit fluid flow, its permeability, and the degree of internal resistance to flow of the fluid, its viscosity. Viscous forces tend to influence reservoir flows of both produced and injected fluids in reservoirs under normal oil field conditions to a greater extent than gravity/capillary forces. This implies that fluids flow through porous media in parallel layers with few disruptions (i.e. laminar flow conditions) and the flow rate is proportional to the existing pressure gradient in the reservoir (Satter et al., 2008).

Generally horizontal flow is greater than vertical flow due to directional differences in permeability (Selley, 1998), but this must be seen as a simplification of the real conditions in an oil field. Nevertheless it is relevant because it expresses the physical limits to the possible production rate, or defines a “best case-scenario” of production from a homogenous reservoir where the pressure gradient is the sole drive mechanism.

Darcy’s Law states that a fluid with high viscosity will have a low flow rate; that if the rock permeability is high there will be a high flow rate; and that there must be a pressure gradient in order to have any fluid flow.

Primary recovery uses naturally occurring energy, such as buoyancy (Archimedes principle) and reservoir pressure, to drive oil flows to the surface. Oil is simply allowed to flow under its own pressure, unless fluids are injected into the reservoir. However, the pressure gradient drops as oil is extracted and this will limit the rate of production according to Darcy´s law (Abrams and Wiener, 2010). This results in a depletion-driven decline in the rate of production as depletion of the reservoir reduces pressure and hence fluid flows. Reservoir and fluid properties can greatly influence the outcome and lead to significant differences in the percentage of ‘oil in place’ that is recovered (i.e. recovery factor). Typically, about 10–30% of the oil in place can be extracted during primary recovery (Kjärstad and Johnsson, 2009).

Secondary recovery focuses on artificial pressure maintenance (APM), where injection of fluids maintains reservoir pressure. In most oil fields, especially those of significant size, secondary recovery accounts for the largest proportion of total recovery (Amit, 1986; Hyne, 2001). The most common method for maintaining pressure during secondary recovery is water flooding, where water is injected to maintain reservoir pressure. When this works well the water forms a water bank that moves through the pores and presses the oil towards the producing wells. The injection of water is generally intended to give a fairly constant pressure at the entry to a well pipe (i.e. downhole pressure), but eventually injected fluids will break through and mix with the oil. Conservation of mass (i.e. material balance) in oil reservoirs requires that the extracted volume of fluid is relatively constant throughout the lifetime (Satter et al., 2008), but the water share (or ‘water cut’) will increase with time. As oil is extracted from the reservoir, an increased water cut will cause a decline of the oil production flow despite high reservoir pressure.

Water-flooding presents numerous engineering challenges that vary with the rock and fluid properties, reservoir heterogeneities and the physical differences between the oil in place and the injected water (Satter et al., 2008). One example is when the oil is much more viscous than the injected water causing so called “fingering”, where water moves in thin irregular ‘fingers’ instead of as a unified front. This bypasses significant volumes of recoverable oil and can cause premature breakthrough of water into production wells.

The properties of the oil compared to water are so important for oil extraction that the American Petroleum Institute has constructed a measure of the density of the oil compared to water, defined as API gravity = (141.5/specific gravity at 60 degrees Fahrenheit) – 131.5.

API > 10° the oil is lighter and floats on fresh water, while if API < 10° it is denser and sinks. Water flooding is possible when the oil API > 25° and the viscosity is rather low (< 30 centipoise), and works best in homogenous reservoirs. Consequently, secondary recovery is not always effective, even though a majority of the world’s oil producing fields attempt secondary recovery.

Primary and secondary recovery combined can usually extract 30–50% of the oil in place and nearly all reservoirs that can benefit from APM are using it (Kjärstad and Johnsson, 2009).

Figure 2. Production of oil and water for the giant Jay field in Florida, USA. The water cut reached over 90% of total produced fluids in the mid-1980s and is now at 97%. In 2010, the field produced 2,500 barrels of oil and 94,000 barrels of water per day. Data source: Florida Department of Environmental Protection (2012)

Figure 2. Production of oil and water for the giant Jay field in Florida, USA. The water cut reached over 90% of total produced fluids in the mid-1980s and is now at 97%. In 2010, the field produced 2,500 barrels of oil and 94,000 barrels of water per day. Data source: Florida Department of Environmental Protection (2012)

Tertiary recovery or enhanced oil recovery (EOR), involves more complex ways of influencing rock and fluid properties. The feasibility of EOR, together with the appropriate approach to EOR, will vary with the fluid properties and geological characteristics of the reservoir. According to Darcy’s Law, the ability of oil to move in a reservoir can be increased by decreasing its viscosity. This leads to four main approaches to EOR, namely thermal, chemical, miscible and microbial methods.

  1. Thermal methods are the most commonly used approach and make up nearly half of all worldwide EOR projects. Thermal EOR involves changing oil viscosity by thermal means, such as steam flooding, hot-water flooding or in-situ combustion, where the bottom of the reservoir is ignited and heat is generated by burning a part of the oil in place.
  2. Miscible methods account for about 41% of worldwide EOR projects and focus on injection of a gas or solvent that is miscible with the oil, resulting in improved recovery. Miscibility increases the mobility of the oil, but also greatly adds to the complexity of the process. Carbon dioxide injection is widely applicable to many reservoirs at lower miscibility pressures than other methods. Part of the carbon dioxide is soluble in oils and swells the net volume and reduces viscosity. As miscibility develops, both CO2 and oil can flow together because of the low interfacial tension. If available, light hydrocarbons (primarily natural gas) can also be injected to generate miscibility, decrease the viscosity of the oil and increase oil volume via swelling. Nitrogen, or even flue gas, is an alternative in high permeability reservoirs containing light oil (Bath, 1989). These gases are usually rather inexpensive, but inferior to CO2 or hydrocarbons from an oil recovery perspective (Satter et al., 2008). Nitrogen has poor solubility in oil and requires much higher pressures to develop miscibility.
  3. Chemical flooding uses the injection of polymer, surfactants, and caustic alkaline or other chemicals. At present, it makes up about 11% of global EOR projects. This technique requires conditions favorable for water-flooding as it is a modification of water-flooding. Polymers can be used to augment water-flooding by changing water viscosity and mobility. More oil will be produced in the early life of the water flood and this is the primary economic advantage, as ultimate recovery is generally the same for as for conventional water-flooding. Surfactants recover additional oil by enhancing mobility and solubility of oil and emulsification of oil and water. Caustic alkaline injection involves the injection of sodium compounds that can react with organic petroleum acids in certain oils to create surfactants in situ. Injected chemicals can also react with reservoir rocks to change wettability and thereby improve recovery. Sheng (2011) reviewed these methods.
  4. The final form of EOR uses microbes to improve oil recovery. It is a rarely used approach and only makes up 0.6% of worldwide EOR projects . Injected microbes can generate gas within the reservoir, thus increasing reservoir pressure and reducing oil viscosity. Alternatively microbes can generate bio-surfactants that can reduce interfacial tension and improve recovery by favourably changing wettability (Adasani and Bai, 2011).

Under favorable conditions, the combination of primary and secondary recovery can extract between one third and one half of the original oil in place. The average recovery from petroleum reservoirs around the world is estimated to be approximately 35%. If a large part of the oil remains after both primary and secondary recovery, operators may implement a suitable EOR technique. However, only a small percentage of all oil fields are using EOR due to high costs and technology requirements.

Since 1959, only 652 EOR projects have been pursued and enhanced production corresponded to ~1.8 Mb/d in 2010, or 1.5% of total global production.

Defining decline and depletion rates

The concept of depletion is intuitive as it is something of which we all have every-day experience. For example, if we have a fixed amount of beer in a bottle, and drink some of it, the beer in the bottle is unavoidably depleted. Any resource that is extracted faster than it is produced is subject to depletion – which means that depletion is not restricted to nonrenewable resources. For example, wood can be considered renewable, but if deforestation is faster than reproduction the resource is depleted within the time-span considered. A resource can only be considered as renewable if the rate of extraction is less than or equal to the rate of increment of the resource.

Fossil fuels are only reproduced on geological timescales, making depletion of these resources irreversible. While the concept of depletion is the same for all resources, there may also be limits on the rate of depletion of a resource. This is an important consideration for oil resources, where the rate of depletion is constrained by geological conditions and the physical laws of fluid flow in porous media, together with economic and technological factors.

Fundamental definitions for oil depletion

A fundamental parameter concerning oil production is the size of recoverable resources remaining for exploitation. Multiple classification schemes for resources and reserves make it difficult to compare and combine data from different sources.

Revisions to URR estimates may occur at any time as a consequence of changing market conditions, increased geological knowledge, and improved technology and so on. This makes URR a time varying quantity, although it is not as fluctuating as other reserve estimates. URR may also be expressed as the remaining recoverable resource plus cumulative production at an arbitrary point in time. Depletion levels can vary from 0 to 1 (i.e. 0–100%) and indicate what proportion of the estimated URR remains. Returning to the beer bottle analogy, we note that a half-full bottle would have a depletion level of 50%.

Depletion rates

Conceptually, the depletion rate is the ratio of annual production to some estimate of recoverable resources, where the latter can be defined as 1P or 2P reserves, remaining recoverable resources or the URR.

A lack of standardized use has resulted in several studies using depletion rates based on very different definitions of recoverable resources and this has added to the confusion surrounding the concept.

In practice, a depletion rate can refer to two possible things.

  1. It can relate to the rate of change of the depletion level at time t.
  2. Or it could also refer to the rate at which remaining recoverable resources are being produced.

Decline rates

The rate of decline, Y, is equal to the difference in the rate of production from one period to the next (change in production rate/production rate) and is commonly expressed on an annual or monthly basis. Changes can be both positive and negative, but are generally negative after a field has passed its peak of production.

A disadvantage of decline rate studies is that they do not necessarily relate to the physical factors driving oil depletion (decreasing reservoir pressure, increasing water cut, etc.). Observed decline may also arise from non-physical factors such as underinvestment, politics, production quotas, damage or sabotage. In essence, decline rates easily provide ambiguous signals for unwary analysts. Usually, decline of production is the result of complex interactions between reservoir physics, technology, economics and decision-making. Many factors influence production rates and one must be careful in extrapolating decline into the future. Decline and disruption caused by socioeconomic events are often termed ‘aboveground’ constraints, and may be resolved if proper measures are taken. On the other hand, depletion-driven decline is the result of intrinsic, below- ground physical constraints and is difficult to alleviate.

Empirical study

This study relies on the Uppsala giant oil field database. The database was initiated by Robelius (2007) and later updated by Höök et al. (2009a, b). It contains ~350 giant oil fields worldwide accounting for an URR of over 1100 Gb. For the purpose of this study, complementary data on hundreds of smaller oil fields all over the world have been combined with the giant oil field data. From this combined database, some 880 individual oilfields were selected. They were chosen to reflect the wide array of field sizes, production strategies, and socioeconomic conditions seen over the globe. The size distribution is given in Table 2, and in general an equal number of fields in each size category have been chosen. However, due to the limited number of post-peak fields larger than 1 billion barrels (Gb), this size category contains fewer fields (N=130) than the other categories (N=150). However, this difference is assumed to be negligible when identifying the general patterns of behavior.

Table 2. Descriptive statistics of the sample of fields studied. The distribution is highly skewed with most resources concentrated in relatively few giant fields.

Table 2. Descriptive statistics of the sample of fields studied. The distribution is highly
skewed with most resources concentrated in relatively few giant fields.

 

 

 

 

Table 3. Observed annual decline rates in percent sorted by field size.

Table 3. Observed annual decline rates in percent sorted by field size.

Table 5. Estimated depletion levels at peak production sorted by field size.

Table 5. Estimated depletion levels at peak production sorted by field size.

Table 6. Estimated depletion rates of ultimately recoverable resources at onset of decline, sorted by field size.

Table 6. Estimated depletion rates of ultimately recoverable resources at onset of decline, sorted by field size.

Table 7. Estimated depletion rates of remaining recoverable resources sorted by field size.

Table 7. Estimated depletion rates of remaining recoverable resources sorted by field size.

Data considerations

To assess depletion and decline rate behavior, data for individual fields is essential. Some data on production and recoverable resources is available in the public domain or can be obtained from companies (IHS, Rystad Energy, etc.), agencies or governments. Some regions, such as the North Sea, provide excellent openly accessible data while others, such as OPEC, are characterized by generally poor data access.

Figure 5. The relation between field size and maximum production level.

Figure 5. The relation between field size and maximum production level.

Annual or monthly production data is comparatively easy to acquire and can commonly be obtained from operators, agencies or third-party sources such as business magazines, trade journals, etc. Recoverable resources, reserve estimates, and related data are more problematic to acquire and are generally less reliable. The multiple classification schemes for resources and reserves make it difficult to compare and combine data from different sources (UKERC, 2009a).

Naturally, there are shortcomings in the available data. For example, different definitions among reporting agencies, changing classifications over time, terrorist strikes, major accidents (Piper Alpha, Deepwater Horizon, etc.), and political decisions can all influence both production trends and data quality. Fields with severely disturbed behavior or otherwise dubious properties were, as far as possible, omitted from this analysis. Some fields exhibit a clear peak, commonly quite early in the field’s life, followed a decline phase. Other fields can have long plateau phases, possibly ranging for decades, which are followed by the onset of decline.

This study focuses on fields that have “peaked” and left the plateau stage. Consequently, fields that are in the build-up phase or haven’t reached the onset of decline are excluded from the study. For fields with a plateau, “peaking” was defined as the point where production is judged to clearly leave a 4% fluctuation band around the plateau level, as earlier used by Höök et al. (2009b). The data show a strong correlation (R2 = 0.98) between estimated URR and peak/plateau production levels (a power fit indicates a strong correlation valid over several magnitudes as seen in figure 5). This is hardly surprising, since high daily production levels are generally only possible in fields with significant URR.

For some fields, official estimates of URR or equivalent were available. For others, the URR was estimated by adding cumulative production to recent (no older than 2005) industry estimates of 2P (proven+probable) reserves. Bentley et al. (2007) discuss industry 2P data in more detail and suggest that they provide a median estimate of remaining recoverable resources (i.e. there is a 50% probability that recoverable resources are higher or lower). Thus it is equally likely that cumulative production over the remaining life-time of the field will be greater or lower than the 2P figure. However, reserve estimates tend to increase over time, a phenomenon known as reserve growth (Sorrell et al., 2012). Factors such as increased investment, technology and knowledge are also acknowledged and known to increase reserves over time, making it probable that URR estimates based upon current 2P reserves will underestimate the actual field size, and the fact of reserves growth must also be acknowledged even in 2P data. For the remainder where no 2P data or official URR estimates were available, more traditional curve-fitting methods were used to estimate the URR.

In our aggregated dataset, the URR of some fields are surely overestimated, while others may be underestimated. We assume here that these effects cancel each other out when combined. For the sake of simplicity we assume here that a field’s URR remains fixed over time. Changed URR values will not affect decline rates of any of the fields used in this study, and neither will it affect the peak production points. However, increases in the estimated URR reduce the estimated depletion level and depletion rate.

Decline rates seen in real fields can vary significantly. In this dataset, annual decline rates ranged from less than 1% to more than 70%, although the range decreases with increasing field size (Figure 6). The average decline rates for the entire data set can be derived, although such a figure can be misleading due to the underlying size dependence. Closer analysis shows major differences among decline rates and implies that decline rates of small fields may differ significantly from those of large fields (Table 3).

Giant fields of over 1 Gb have by far the lowest decline rates and there is a clear trend towards more rapid decline with decreasing field size (Table 3). Production-weighted (PW) average values also show that fields with high production levels tend to decline somewhat faster than the arithmetic average for small fields (<0.1 Gb), while the opposite was true for semi-giant and giant oil fields. Partly this can be explained by a large share of OPEC control among the larger fields and the fact that OPEC producers tend to aim for long and stable production profiles rather than rapid return on investment. Secondly, these patterns can arise from the economically rational behavior of a price- taking producer who maximizes profit subject to technical and physical constraints (Jakobsson et al., 2012).

Table 3. Observed annual decline rates in percent sorted by field size.

Earlier studies have also shown that technological development such as EOR can result in more rapid declines. Gowdy and Julia (2007) initially highlighted this problem for two North Sea giant fields. Later, Höök et al. (2009a, b) elaborated on this and found a general tendency towards higher decline rates for giant fields as new technology and modern production strategies allowed the extension of plateau production at the expense of higher subsequent decline rates.

Table 4 compares the results of three studies that provide estimates of average decline rates from a globally representative sample of post-peak giant fields. Despite differences in data sets, definitions and weighting methods, the results are in broad agreement that the decline in the existing production is between 4–8% annually (Höök et al., 2009b). Expressed in production 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 (Fantazzini et al., 2011). This implies that nearly 5 new Saudi-Arabias would be needed by 2030 just to offset the decline in existing production (Aleklett et al., 2010).

Höök et al. (2009b) provides additional data on the time evolution of giant oil field decline rates and finds the average decline rate has increased by around 0.15% per year since mid-1960s – a trend that is expected to continue. From Table 3, it can be also seen that decline rates are higher for smaller fields and as future production becomes more reliant on non-giant fields it is reasonable that average decline in existing production will increase. The Increasing decline rate is seldom discussed – even though it can lead to additional capacity requirements of as much as 7 Mb/d by 2030 (Aleklett et al., 2010).

Figure 6. Scatter plot of observed decline rates seen the data set. Significant differences occur, but generally decrease with increasing field size.

Table 4. Average decline rates for post-peak giant fields found by recent studies. Source: Höök et al. (2009b) Parameter Höök et al. IEA CERA Average decline

Depletion level behavior

Earlier studies have shown that it is common for giant oil fields to reach the onset of decline when less than half of the URR has been produced (Höök et al., 2009a). In this study, this analysis is expanded to include smaller fields. Figure 7 provides a scatter plot of the estimated depletion level at the onset of decline, while Figure 8 provides a corresponding frequency histogram.

A significant spread can be seen among the fields studied with some reaching an estimated depletion level of over 80% before the onset of decline, while others peak at depletion levels as low as 10%. However, there is a clear trend towards higher depletion levels at peak with increasing field size (Table 5). Some of the fields with the highest depletion levels at peak, especially in the >100 Mb size category, are old American fields that were extensively redeveloped around the 1980s when new technology/investments allowed larger fractions of the oil- in-place to be recovered. Production-weighted figures indicate that fields with high annual production rates are usually developed in such a way that the depletion level is relatively high at the onset of decline.

Interestingly, there is virtually no correlation (linear correlation coefficient = -0.07) between the estimated depletion levels at peak and the subsequent decline rates in oil fields. This indicates that depletion levels have restricted relevance for analyzing production flows.

It should also be noted that any future reserve growth in the studied fields will reduce the estimated depletion levels. If a significant portion of the URR figures used in this study are underestimates, the depletion levels derived here will be overestimates. If so, this would reinforce the conclusion that most fields begin to decline well before half of their URR is produced.

Figure 7. Scatter plot of estimated depletion levels at peak production (onset of decline).

The theory described above predicts that maximum depletion rates should occur when the onset of decline is reached. This may also be referred to as the depletion rate at peak and effectively marks the point where depletion-driven decline begins to dominate over other variables and leads to the onset of production decline. Estimated annual depletion rates of URR at the onset of decline are plotted in Figure 9. A few small fields reach depletion rates of 30% or more before peaking, but most have significantly lower depletion rates at peak production. The histogram (Figure 10) shows a skewed distribution with the largest number of fields having values of 10% or less, leading to an overall mean of 10.3% and a production-weighted mean of 4.9%. The figure also demonstrates a clear trend towards lower depletion rates at peak with increasing field size (Table 6).

The general behavior is similar for depletion rates of remaining recoverable resources (RRR) as seen in Figure 11. The distribution histogram (Figure 12) shows a skewed structure with only a small number of fields capable of depleting more than 20% of the remaining recoverable resources per year at peak production. Depletion rate differences diminish with increasing field size, indicating a narrowing interval of possible depletion rates. Höök et al. (2009a) expanded on this correlation by comparing onshore, offshore, OPEC, and non-OPEC giant oil fields.

High depletion rates are only common in small oil fields, and are increasingly exceptional with increasing field size. As noted earlier, an oil-producing region consists of a sum of individual oil fields, with their individual peak points distributed in time. From the theory described in Section 3.4, it follows that the regional depletion rate must be somewhere between the minimum and maximum depletion rates of its components. Maximum depletion rates can only be reached if all fields peak simultaneously, which is extremely unlikely. According to our analysis of field data, regional depletion rates are likely to be constrained to less than 20% if they are assumed to follow patterns seen in history. Given the dominance of larger fields in total regional production, the regional depletion rates are even lower in reality. Aleklett et al. (2010) estimates that the typical regional depletion rates of remaining recoverable resources are of the order of 2–5%, and argue that projections of future global oil production by the IEA (2008) are based upon unrealistic assumptions about depletion rates that are not explicitly discussed. Miller (2011) agrees with the findings of Aleklett et al. (2010) and notes the persistent optimism of the IEA projections.

Depletion rates can be directly calculated from production data and URR estimates during both the build-up and plateau stages in an oil field’s life, even before the field has peaked.

In contrast, decline rates can only be estimated after the onset of decline.

However, the strong correlation between the concepts makes it possible to use depletion rates to estimate future average decline rates reasonably well. This has already been used to forecast future production profiles for fields that have yet to reach the onset of decline (Höök et al., 2010b). When combined with reliable URR estimates, depletion rate analysis offers a simple tool for making educated estimates of future production decline rates.

Decline and depletion rates are important to understand and give significant depth to the peak oil debate. However, it is essential to understand that these two concepts are fundamentally different. Decline rates can be measured directly from production data, while depletion rates depend upon estimates of recoverable resources. Changes in recoverability will affect depletion levels and depletion rates, while decline rates are unaffected. Different data sources and resource estimates done at different times are likely to give diverging results.

Oil field size is a key variable, with generally high values for most parameters in small fields and comparatively low values for larger fields. The data shows clearly that most fields tend to peak with much less than half of their ultimately recoverable resources produced, typically around 30% (Table 5).

Peak production generally appears well before the glass is half empty.

Depletion levels of giant oilfields are a noteworthy detail, since giant fields tend to reach the onset of decline with higher depletion levels than small fields. This could be explained by the way most giant fields are developed, as they usually start production at far lower depletion rates than smaller fields due to requirements related to production equipment, pipelines, etc. As a result, giant fields can maintain production plateau by continually drilling into new parts of the reservoir to supplement declining production from older sections and this can probably lead to comparatively higher depletion levels at peak. However, this could also be an effect of underestimated URR and might possibly change if significant future reserve growth occurs.

The theoretical framework summarized here is well supported by the empirical evidence. The existence of maximum depletion rates prior to the onset of production decline is of particular importance. Furthermore, the strong correlation between depletion rates at peak and subsequent decline rates can be used in supply forecasting and for estimating future decline rates before the plateau phase ends. Depletion rate analysis has been around for some time, but the underlying methodology has never been clearly presented.

Much confusion surrounds the concept of depletion rates, even though it is relatively simple idea once properly understood. Maugeri (2012) is a recent example of how terminology is mixed up and how exceptionally low decline rates are used without any solid justification.

Another example is how the EIA used a depletion rate model in a flawed way to reach misleading conclusions (Jakobsson et al., 2009). Similarly, the IEA’s influential projections of global oil supply are based upon highly unrealistic assumptions about the depletion rates of various categories of resources (UKERC, 2009a; Aleklett et al., 2010; Miller, 2011). Once more realistic assumptions are made; the future supply outlook looks much bleaker.

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