Federal Measures Taken to Increase Pipeline Safety Post-San Bruno

by Christina Nagy-McKenna, Enerdynamics Instructor

Pipeline safety is a growing concern and top priority for all sectors of the natural gas industry (upstream, midstream, downstream, and additional stakeholders). As discussed Safetyin my last post, Pipeline Safety: Top Concern for All Segments of Natural Gas Industry, the tragic 2010 rupture of PG&E’s gas transmission Line 132 in San Bruno, Calif., instigated numerous changes in California in relation to pipeline safety. But what about on a federal level? Certainly pipeline safety is a national concern with  2.6 million miles of gas and liquid transportation pipelines in the U.S. (93 percent of which are used to transport natural gas).

Three years ago, federal regulators also took action in response to the San Bruno explosion. U.S. Transportation Secretary Ray Lahood together with the PHMSA issued a “Call to Action” to the regulatory agencies and natural gas pipeline operators to step up the repair and replacement of infrastructure that is considered highest-risk.

At the same time that the California Public Utilities Commission (CPUC) strengthened rules in California, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which was signed by the President in January 2012. Among its objectives, the Act:

  • reauthorized the Department of Transportation Pipeline and Hazardous Materials Safety Administration’s (PHMSA) federal pipeline safety programs through 2015
  • strengthened safety regulations
  • increased civil penalties for violations
  • provided for follow-up surveys and reports on safety concerns including the management and replacement of cast iron natural gas pipelines 

Despite the new regulations, tragic incidents continue to occur. In March of this year, a gas leak and subsequent explosion leveled two tenements in Harlem and took the lives of eight people. The investigation of this accident is ongoing, but residents reported smelling gas in the days prior to the explosion, and the gas main line to the tenement was an old cast iron pipe – again raising questions about aging infrastructure. 

During 2005-2013 approximately 2.5 percent of the gas distribution mains in the U.S. were made of cast iron, but 10.5 percent of incidents on gas distribution mains involved cast iron mains. And, in proportion to overall cast iron main mileage, the rate of incidents on cast iron main lines was more than four times that of mains made of other materials.

In February natural gas was the cause of an explosion in Chicago, which injured two women, as well as a fire in Kentucky that injured two people and destroyed two homes. Thus far in 2014, PHMSA, the agency that oversees pipeline safety in the United States,  has recorded 73 incidents on gas transmission systems, and 62 occurrences on gas distribution systems.  These events have resulted in 14 fatalities and 78 injuries. Data for recent years are equally grim: A five-year average from 2009 to 2013 for fatalities on the gas transmission system is two while on the gas distribution system it is 10. 

Thus, it is not surprising that the natural gas industry’s top concern is safety. While there have been fewer gas distribution incidents in the past two years, the number of injuries and fatalities is still high. Additionally, the number of gas transmission accidents has not diminished since 2009. While the investigation of the accident in Harlem is ongoing, it is clear that the industry needs to accelerate maintenance and replacement of infrastructure that is old and, in some cases, simply obsolete in technology and engineering.

For example, during 2005-2013 approximately 2.5 percent of the gas distribution mains in the U.S. were made of cast iron, but 10.5 percent of incidents on gas distribution mains involved cast iron mains. And, in proportion to overall cast iron main mileage, the rate of incidents on cast iron main lines was more than four times that of mains made of other materials.

Since San Bruno, many positive steps have been taken to increase pipeline safety. However, given the slow rate of reduction of actual number of annual incidents and steady aging of the U.S. natural gas pipeline system, it is clear the industry still has a great deal of work ahead.

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Pipeline Safety: Top Concern for All Segments of Natural Gas Industry

by Christina Nagy-McKenna, Enerdynamics Instructor

Safety is cited as the No. 1 concern among all sectors of the natural gas industry (upstream, midstream, downstream, and additional stakeholders), according to Black and Veatch’s most recent report on the U.S. natural gas industrypipeline construction

Distribution utilities, pipeline companies, and regulators are confronted with aging infrastructure that is slowly failing, often with catastrophic consequences. Wear and tear due to corrosion, damage, and stress can be difficult to diagnose given that pipelines are buried under ground and are not visible to inspectors. 

While technology exists to assess the strength of most of the 2.6 million miles of gas and liquid transportation pipelines in the U.S. (93 percent of which are used to transport natural gas), some areas are unreachable due to the design and construction of the lines. Additionally, as recent gas pipeline safety cases have demonstrated, records that vastly predate computerized data storage and organization are sometimes inaccurate. This leaves a growing industry with a glaring Achilles heel.  

Four years ago the startling rupture of PG&E’s gas transmission Line 132 in San Bruno, Calif., took the lives of eight residents, injured 58 people, leveled 38 homes, and damaged 70 more. The tragic accident made national news and left many people wondering how such a large pipeline in the middle of a residential neighborhood could suddenly and inexplicable explode. Pictures of the 72-foot-long and 26-foot-wide crater looked more at home on a Hollywood movie set than in a quiet, suburban neighborhood.

The pipeline, put into service in 1948, became the blueprint for aging infrastructure that was not subject to pressure testing requirements of newer pipelines due to age exemptions, and whose as-built drawings did not match its actual construction. Specifically, Line 132 was inaccurately recorded as a seamless steel pipe when in fact it was a longitudinally seam-welded pipe. Accurate record keeping is considered an important part of establishing valid maximum allowable operating pressures (MAOP) for all pipelines. 

Since the San Bruno accident, the California Public Utilities Commission (CPUC), PG&E, and other California gas utilities have worked diligently to design and implement new, stringent standards set by the CPUC to prevent another devastating event. Specifically, on June 9, 2011, the CPUC issued a decision that ordered all California natural gas transmission operators to design a plan to test or replace all transmission lines that had not been pressure tested and to present this plan to the CPUC for approval. This order stemmed in part from PG&E’s difficulty locating pressure-testing records for 152 miles of its total 1,805 of transmission pipeline, approximately 8 percent of its system. 

The order further specified that all operators provide interim safety enhancement measures including:

  • increased pipeline patrols and leak surveys
  • pressure reductions
  • a prioritization of pressure testing for critical pipelines that had to run at or near their MAOP values at or above 30 percent of its specified minimum yield strength (SMYS)[1]

As of April 2014, PG&E has hydrostatically tested over 565 miles of its pipeline system, and it has replaced close to 90 miles of pipe.[2] The remaining California utilities are also implementing their pipeline safety plans. 

Next week I’ll continue this post by looking at federal measures for pipeline safety since the San Bruno tragedy.


[1] CPUC Decision 11-06-017, June 9, 2011, page 26.
[2] Status Report on NTSB Recommendations to the CPUC, August 2014.

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An In-depth Look at the EPA’s Clean Power Plan, Part III

by Matthew Rose, Enerdynamics Instructor

The last couple of weeks I’ve delved into the particulars of the Environmental Protection Agency’s (EPA) proposed Clean Power Plan including the plan’s purpose and objectives as well as how the EPA foresees its Red question mark puzzleimplementation. This week I conclude this discussion by looking at some areas of the plan that require further clarification and at some possible implications if the Clean Power Plan comes to fruition.

Issues needing clarification

A review of the plan’s draft rules points to a number of issues that seem ambiguous and need greater clarification. These issues are not exhaustive but reflect some of the immediate concerns arising from the rules.

  • Enforceable authority: There is some uncertainty regarding the enforceable authority under the “Clean Air Act” especially for renewables and energy efficiency strategies. If a state elects to use renewable energy or a state energy efficiency portfolio standard as part of its compliance plan, does the strategy become subject to EPA’s authority? There is some ambiguity that the rules may potentially extend to federal oversight in these instances.

  • Historical contributions: A key element of the approach is that EPA incorporated the relevant generation and energy efficiency accomplishments within each state in their goal-making process. As a result, any efficiency reduction prior to 2012 is not eligible to meet the savings targets. Only reductions from 2012 and forward can be applied against savings targets. Related questions: How do the rules address load growth or the need for new generation? Do emission targets change to accommodate new generation?

  • Generator incentives and cost recovery: What are the incentives to utilities (generators) to participate in a statewide strategy? This issue becomes more complex in states that have restructured and include merchant (IPP) generation, and it extends to the idea that some strategies may result in increased costs requiring regulatory approval and cost recovery. The process for this set of activities is not detailed.
  • Roles and responsibilities of ISO/RTOs: The rules have limited discussion of how things would work in an organized transmission organization (ISO/RTO) where the generators have limited control over their dispatch. The conflicting obligations of the ISO/RTO may not be aligned with intended state-level compliance requirements. Will states have the authority to control generation dispatch to address emission goals?

  • State regulatory authority: The rules are unclear in defining what state organization will be responsible for organizing and submitting compliance plans. Compliance with the rules will require an in-state authority capable of executing the plan development and compliance.


The proposed rules involve significant implications. Although there are disagreements on the rules’ impacts on prices and jobs, there is consensus that the rules serve to decrease the role and contributions of the country’s aging coal-fired generation. Many of the older plants will never find an economic path of compliance and will be forced to retire (although there may be some opportunities to convert existing coal plants to natural gas).

Many experts point to impacts ranging from higher electricity prices, fewer jobs, grid reliability concerns, and greater reliance on natural gas as a fuel choice for future generations. Other analysts suggest that impacts will be minimal. And some even suggest that consumers will benefit through significantly increased use of low-cost energy efficiency and demand side management solutions. Of course, the real impacts will be discernible only when the final rules are revised and approved and markets have a chance to respond.  

As of early August 2014, a number of states have filed suits against the EPA to block the proposed rule in the U.S. Court of Appeals in the District of Columbia. These include Alabama, Indiana, Kansas, Kentucky, Louisiana, Nebraska, Ohio, Oklahoma, South Dakota, South Carolina, West Virginia, and Wyoming. It seems the process may entail legal and political battles resulting in an evolving landscape that takes time to settle and means implementation may be delayed beyond the EPA-proposed dates.

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An In-depth Look at the EPA’s Clean Power Plan, Part II

by Matthew Rose, Enerdynamics Instructor

Last week I gave a brief overview of what the EPA’s proposed Clean Power Plan is and the objectives guiding it. Now for a little more detail on the EPA’s approach toward 452180751implementation…

The plan’s proposed rules reflect a focused modeling exercise conducted by the EPA to:

  • characterize the status and environmental efficiency of fossil-fuel generation assets in 2012
  • apply predetermined supply-and-demand efficiency improvements to establish state-level targets

These estimates were allocated across all states with fossil-fuel generation and result in a target goal for emissions reductions. The key analytical steps include:

  1. Calculating each state’s “emissions rate”: The EPA sets a baseline estimate of the carbon intensity of each state’s electricity sector. The carbon intensity is a product of dividing the total carbon dioxide emissions from a state’s power plants by the total amount of electricity generated (with a few adjustments for renewables and nuclear). Different states start out with different emissions rates. Washington, for instance, has a relatively low emissions rate — just 763 pounds of carbon dioxide per MWh of electricity produced. That’s a result of having only one coal plant. Indiana, by contrast, relies far more heavily on coal, so it has a much higher emissions rate of around 1,923 pounds of carbon-dioxide per MWh.
  2. EPA examines what emissions reductions are reasonable for each state to achieve:  The EPA sets goals for reducing those emissions rates based on what the agency deems reasonable for each state to cut by 2030. The EPA assumes that each state will be able to take a series of steps using existing technology or policies to lower emissions.
  3. Extend reduction options to a series of four building blocks: The proposed rule sets out a series of four building blocks (or pathways) that states can employ to reach reduction targets. These are illustrated in the following table:

The end result is a specific carbon reduction target for each state that in aggregate provides a total reduction of 30% for the country by 2030. As a result, each state has a specific target that varies greatly by state depending on various characteristics and opportunities. The application of the reductions plays out differently in each state.

For example, Michigan has a lot of coal plants and spare gas capacity so the opportunity of coal-to-gas switching is assumed as a key option in determining Michigan’s goal. By contrast, the EPA assumed that growth in wind and solar could play a relatively bigger role in helping New Hampshire and Maine cut emissions based on renewable policies that are already in place.

The EPA draft plan and associated modelling expects 2012-20 reductions to comprise 39% from combined-cycle gas turbines (CCGT) re-dispatch, 10% from heat rate improvements at coal plants, 23% from renewables, 3% from nuclear build, and 25% from energy efficiency. This will vary by state depending on a state’s fuel mix and program history.

It’s important to note that states don’t have to follow any of the above pathways and may seek approval from EPA for a unique path to achieving the designated savings goal— this is just how the EPA calculates what it deems a reasonable goal for each state. (In the proposed rules, the technical term for this is “best system of emissions reductions”. For a complete graphic depiction of the assigned targets for each state, click here.

State compliance plans

Once the EPA sets its final targets, states will have to submit compliance plans to meet the targets. EPA’s rules reflect a purposeful attempt to provide states with extensive flexibility in meeting emission reduction targets. Compliance plans could include an array of different strategies. For example, states could:

  • ramp up renewable energy
  • shut down their coal plants and/or build new natural gas plants
  • build nuclear plants or get credit for prolonging the life of their nuclear plants
  • advance more stringent energy efficiency codes and standards as part of a statewide energy efficiency portfolio
  • propose implementation of a carbon tax or join “cap and trade systems”[2]

The one condition is the need for EPA review and approval. The agency will have to decide whether a given state’s implementation plan will actually help the state meet its emissions goal. States that refuse to submit compliance plans would be subject to the EPA crafting its own plan for regulating a state’s emissions. It’s likely that any federal plan would be less flexible and possibly more costly.

Next week I’ll wrap up this series by looking at some possible holes in the plan that many feel require further clarification, and I’ll look at the implications if and when the plan comes to fruition.

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An In-depth Look at the EPA’s Clean Power Plan, Part I

by Matthew Rose, Enerdynamics Instructor

This week and in the weeks ahead, Energy Currents is taking a close look at the Environmental Protection Agency‘s (EPA) Clean Power Plan proposal that was released on June 2, 2014. This week’s post looks at the plan’s main objectives and the process it faces in the months (or years) ahead. In future posts, we’ll look at the specific approach the EPA is proposing to meet such objectives; some vague areas within the current plan that need further clarification; and the implications  if and when the plan comes to fruition.

If implemented, the Clean Power Plan will, for the first time ever, federally regulate carbon dioxide (CO2) emissions from existing power plants. The plan is designed to cut carbon pollution from power plants nationwide by 30 percent from 2005 levels.

More specifically, the proposed plan is designed to address the following:

  1. Create state-by-state carbon emissions goals: These goals are defined in terms of pounds of emissions per MWh of output and are based on each state’s historic generation mix. Thus goals for states with higher historic levels of carbon-based generation are set at less stringent levels than those for other states.
  2. Define a “pathway” for each state to develop plans to achieve the goals: Rather than defining power plant-specific regulations or mandating how states must achieve their goals, the EPA-proposed process is designed to be flexible to allow each state to develop its own program. States may develop their own individual plans or may work together to develop regional multi-state plans.

A 120-day public comment period began once the plan’s rules were published, and EPA began holding public hearings in Atlanta, Ga., Denver, Colo., Pittsburgh, Pa., and Washington, D.C. Affected parties are expected to submit comments to the plan during this period in order to preserve arguments for potential litigation.

The plan is expected to be finalized by June 1, 2015. This date assumes there are no challenges associated with its rules. Note that any legal challenges can only be advanced after the ruling is finalized, suggesting there may be a protracted process before any plan is finalized and implemented.

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Customizing E-learning to Meet Energy Companies’ Training Goals and Budgets

By John Ferrare, Enerdynamics CEO

There is no doubt that e-learning (online training) has found a permanent home in the corporate training arena. We’ve seen a phenomenal jump in sales of our online courses in the past year. And, not surprisingly, that jump has correlated with a drop in the number of live seminars Enerdynamics has been contracted to teach. E-learning is displacing the traditional classroom experience for certain types of training.

It makes sense for many reasons: E-learning is cheaper, employees learn at their own pace, and it eliminates the logistical issues of getting people together in the same place at the same time for joint training.

Of course, there are tradeoffs. For example, live seminars are more conducive to customization. We can (and almost always do) customize content, learning style, etc., to match a live seminar’s audience. This is trickier with “off-the-shelf” e-learning. Or is it?

Enerdynamics has recently and successfully been experimenting with combining e-learning modules into custom courses. Those familiar with our online training know that we have quite a few “full-length” courses. Each comprises modules that are combined in a logical manner to bring learners up to speed on a general area of the business.

For instance, our Electric Industry Overview is a four-hour course designed to present a big-picture introduction to the electric business. The course comprises seven modules, each of which can be taken on its own or as part of the full-length course. This gives Enerdynamics’ clients the opportunity to literally build their own courses that include the individual modules they want or need.

We recently worked with a municipal utility that wanted six modules from various courses combined into a custom course for a small work group. The Enerdynamics team combined these six modules and added a company-specific landing page explaining the course to the client’s employees. Each module includes a quiz that must be passed with 70% accuracy, and when the employee passes each quiz, he or she passes the course.

Additionally, we can supplement the e-learning with reading assignments from our book, Understanding Today’s Electricity Business, and even custom webinars that might focus on company-specific information. Such flexibility allows us to create a custom course for a group of less than a dozen at a small muni or a group of 200+ at a large utility.

With a variety of learning components already produced and the option to add custom content for each client, the possibilities are endless. And very exciting. Contact me at jferrare@enerdynamics.com or 866-765-5432 ext. 700 about how Enerdynamics can help you put together custom e-learning courses for your employees.

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Initial Research Shows Fracking Well Contamination Is Due To Poor Completion Techniques

by Bob Shively, Enerdynamics President and Lead Instructor 

A major concern of the United States’ current fracking boom is if and how fracking is negatively impacting the environment[1].  One key concern is that fracking may tap watercontaminate drinking water since elevated levels of methane in drinking water has been noted in locations near fracking sites. But the science of figuring out exactly what’s going on takes time, and meanwhile energy companies continue their fracking operations in and around communities across the nation.

Data from studies on fracking sites and water contamination is just now coming in. Several scientists who initially started work at Duke and are now at various universities have been studying natural gas contamination of wells in Pennsylvania and Texas and recently published their findings in the Proceedings of the Natural Academy of Sciences[2].

The group’s conclusion? Well contamination is occurring through poor well completion techniques, not from the migration of natural gas from deep underground induced by hydraulic fracturing techniques. This is good news for the industry and for the environment, since this type of well contamination should be controllable through use of proper well completion processes.

What was studied?

The scientists looked at two questions:

  • Are elevated levels of hydrocarbon gas in drinking-water aquifers near gas wells derived from natural or man-made sources?
  • If gas contamination exists due to man-made activities, what is causing the contamination?

To answer these questions, the scientists used a technique called noble gas and hydrocarbon tracers, which allows them to track the source of hydrocarbon gas.

Were elevated levels due to human activities?

The scientists use the term “fugitive gas” to describe gas that migrated into drinking water sources from other locations due to human activities. They documented fugitive gases in eight clusters of domestic water wells in Pennsylvania and Texas. The Texas wells showed declining water quality over time indicating recent activities have caused the contamination.

What caused the contamination?

The scientists theorized that man-made contamination could occur due to multiple causes. For the eight cases of contamination they were able to identify the cause:

  • Four cases were due to leaks through the annulus cement
  • Three cases were due to leaks through the production casings
  • One case was due to underground well failure

well diagram

In no case was the mechanism of contamination gas migration induced by hydraulic fracturing deep underground.

What does this mean?

Certainly study is needed for more than just eight cases of contamination. But the data received to date suggests that energy companies and their regulators should focus on procedures and rules to ensure the integrity of the wells themselves rather than stopping fracking over concerns of migration of gas from deep underground. The scientists suggested that further work should evaluate whether large volumes of highly pressurized fluids used during fracking may affect the integrity of wells. If so, more steps may be required than simply improving well completion procedures.



[1] For a discussion of fracking see: http://marketing.enerdynamics.com/Energy-Insider/2011/Q3NaturalGas.htm

[2] Available at: http://www.pnas.org/content/early/2014/09/12/1322107111.full.pdf+html

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