Our condolences are extended to two employees, their families, co-workers, and the entire Jeffrey Energy Center family for the recent fatality of two employees. It is my understanding that on Sunday evening, two supervisors were engulfed in steam as the elevator opened on the steam drum level. The plant is shut-down until such time as they understand what occurred and the confidence it can be restarted safely.
The power industry's trusted source for generation technology, O&M, and legal & regulatory news for coal, gas, nuclear, hydro, wind & solar power plants; power jobs
Tue, 05 Jun 2018 15:16:42 +0000
More Groups Weigh-in on Trump Move to Save Coal, Nuclear—Including Supporters
Tue, 05 Jun 2018 10:58:46 +0000
Few entities have expressed approval of the Trump administration’s plan that includes a directive for system operators to buy or arrange purchase of energy or capacity from designated “fuel secure” power plants for two years until the Department of Energy (DOE) can address “grid security” challenges. The 41-page draft memo dated May 29—which was presumably authored […]
More Groups Weigh-in on Trump Move to Save Coal, Nuclear—Including Supporters appeared first on POWER Magazine. Few entities have expressed approval of the Trump administration’s plan that includes a directive for system operators to buy or arrange purchase of energy or capacity from designated “fuel secure” power plants for two years until the Department of Energy (DOE) can address “grid security” challenges.
The 41-page draft memo dated May 29—which was presumably authored by the DOE—defines “fuel-secure” capacity as a unit that has “many days or weeks of fuel available on site.” This includes coal, nuclear, hydropower, and certain kinds of liquid fuel or dual-fuel natural gas units.
But the balance has shifted away from “fuel secure” resources toward a growing dependence on pipeline-dependent units—units with “little or no onsite storage, which depend on ‘just-in-time’ supply chains”—and intermittent resources, such as wind and solar, the memo claims. While it acknowledges that “no single disruption effectively could compromise the whole generation fuel supply chain,” it claims that the loss of “fuel secure” electric generation resources is a tipping point.
On June 1, the day Bloomberg broke the news and published the memo—
and the White House confirmed a directive to the DOE to stem impending retirements of fuel-secure power facilities—reactions from an assortment of energy, legal, and regulatory groups were rife with anger and fear. Industry groups pointed to the government’s “short-sighted,” “unnecessary,” and “inappropriate” federal intervention into well-functioning power markets, lambasting its claims that an energy emergency exists, and strongly condemning the plan’s likely long-wearing effects, which include higher energy costs for consumers, and uncertainty for new market entrants.
Coal, Nuclear See Gains in a Tough Fight
Among the plan’s backers, predictably, were groups that represent coal and nuclear generators. The American Coalition for Clean Coal Electricity (ACCCE)—an organization that represents the nation’s coal generation fleet, not the coal industry, as is commonly assumed—said it was “pleased” that the administration is taking steps to help ensure that the nation’s grid is resilient and reliable.
ACCCE President and CEO Paul Bailey, who in March
acknowledged that a third of the coal fleet has retired or will be retired “for good reason,” said in a June 1 statement to POWER that the loss of fuel-secure generation, and especially coal plants, “pose an increasing threat to the power grid, as well as to national security.” The ACCCE will work with the administration and other policymakers on both “near-term and longer-term measures to ensure that the grid is not threatened by the loss of even more fuel-secure resources,” he said.
In a June 2 statement to
POWER, Maria Korsnick, president and CEO of the Nuclear Energy Institute (NEI), also commended the administration for considering options available to retain the operation of the U.S. nuclear fleet as national security assets.
The draft memo claims that nuclear plants have been as “hard-hit” as coal generation. Between 2002 and 2016, 531 coal generating units, representing 59 GW of generation capacity, retired from the U.S. generating fleet. Since 1990, the U.S. has lost 15 nuclear generation units, it says, including 4.7 GW of nuclear capacity—4.7% of the U.S. total that went offline between 2013 to 2016.
The draft memo, however, is sprinkled with critical factual blanks that the DOE presumably intends to fill to support its claims. These include empty footnote citations attached to claims such as: “Analysts have predicted that as much as half of the remaining nuclear fleet is ‘under water’.”
Nuclear Is Buoyed by State and Now Federal Support
While the NEI did not comment on the specific economics of the nuclear fleet its members own, Korsnick noted that the nuclear industry group has “repeatedly warned of the need to stem the tide of the early retirement of nuclear units whose function is irreplaceable in a resilient and reliable grid.”
Korsnick unveiled a four-prong strategy aimed at policymakers, seeking to provide a framework to help them understand the impact of their decisions to allow nuclear units to retire prematurely for economic reasons. The nuclear lobby has since made major gains.
On May 23, New Jersey’s Gov. Phil Murphy signed a bill that establishes a zero-emissions certificate (ZEC) program that will prop up PSEG’s Salem and Hope Creek nuclear plants. The state joins New York and Illinois, which passed laws subsidizing ailing nuclear facilities in 2016, and Connecticut, whose governor last year signed a bill allowing Dominion’s Millstone plant to participate in its clean energy procurement process. And last week, in a pivotal and underreported move, the U.S Department of Justice and the Federal Energy Regulatory Commission (FERC) backed Illinois’ nuclear subsidy program, arguing in an amicus brief that its ZECs—which would provide out-of-market payments for carbon-free nuclear power—does not preempt federal statute.
Still, for Korsnick, a key concern remains: “Once a nuclear power plant closes, it begins decommissioning and will not be reopened,” she said. “This finality is why it is critically important to preserve the fuel security offered by nuclear plants under threat of premature closure. This fuel security is an essential element of national security.” Korsnick noted that nuclear energy provides 20% of U.S. power. “Something must be done now to adequately value all that America’s nuclear power plants deliver,” she said.
Power Company Responses Trickle In
The Electric Power Supply Association—the group whose members include independent power producers (IPP), and
which has fiercely opposed state intervention in wholesale markets—issued a statement on June 1, noting “economic consequences” will be profound for power suppliers and consumers. The group pointed out, in stark contrast to the NEI’s statement, that “This proposed federal action is a bell that cannot be called back once it is rung. Forever more suppliers and consumers will be at the whim of the fuel preferences of whoever happens to be in office.”
Among power companies that expressed approval of the Trump administration’s move was Akron, Ohio–headquartered FirstEnergy Corp.—a company whose
bankrupt competitive arm FirstEnergy Solutions (FES) on March 29 filed an application with the DOE urging the agency to direct certain coal and nuclear generators in PJM Interconnection to buy or arrange for energy, capacity, and ancillary services to maintain grid reliability. FirstEnergy Corp. CEO Charles Jones told POWER in a June 5 statement that he continues to believe that baseload coal and nuclear help maintain system resiliency and national security while also playing an “irreplaceable role” in the regional economy. “The company has advocated for solutions that recognize the critical attributes coal and nuclear plants provide because preserving these vital facilities is the right thing to do for the industry, the electric grid and our customers. I am pleased that the federal government is also recognizing this issue,” he said.
FES, which has its own board of directors that is independent from FirstEnergy Corp.’s and makes the subsidiary’s decisions pertaining to plant closures, bankruptcy issues, and filing of the Section 202(c) request, told
POWER in a separate statement on June 5 that it welcomed Trump’s “support and his recognition of the critical role that our plants play in the security and resilience of the nation’s electrical system.”
Don Moul, president of FES Generation Companies and Chief Nuclear Officer, added: “We look forward to reviewing Secretary Perry’s order when it is issued. While this marks an important first step, until timing and details of the order are clear, additional support at the state level will be necessary to protect the jobs in Ohio and Pennsylvania.”
NRG Energy, which has sought to remain competitive in power markets increasingly characterized by disruptions
by accelerating its transition from a pure IPP model to a more simplified customer-driven integrated power model that favors its retail businesses, also reacted. On Monday, NRG spokesman David Gaier said: “NRG’s view remains unchanged—the organized, competitive power markets remain the best way to ensure reliability and resiliency of the grid while protecting the interests of ratepayers. There’s clearly no threat of crisis in the bulk power system and invoking the Defense Production Act for unprofitable generating plants will only harm consumers.”
‘Hypocrisy from the Left’
Over the weekend, a number of think-tanks and research groups also published their takes on the unprecedented measure in the name of national security.
In a blog post for non-profit public policy research organization
R Street, Electricity Policy Manager Devin Hartman lambasted the effort as “nothing to do with national security and everything to do with political optics.” A key point Hartman stressed is that the draft memo admits the grid is reliable, but that reliability in the “conventional sense is not sufficient” as the grid must be resilient and secure. “Grid resilience has certainly become the topic du jour, and a flood of work on the topic has surfaced in the past year. But the administration’s rationale directly contradicts this body of evidence and its intervention has made economists’ fears come true,” he wrote.
Hartman argued—citing a May 2018
released by Rob Gramlich, Michael Goggin and Alison Silverstein ( paper who was the technical lead of the DOE’s 2017 controversial study on grid reliability)—that the recent surge of distributed generation, especially behind the meter, has been pivotal for resiliency. The paper highlighted that more than 90% of service outages occur from distribution-level problems. “The study also examined the of measures to improve grid resilience, finding that coal and nuclear subsidies have very low value, while over two dozen measures have far higher value. Read another way, if grid resilience is actually a matter of national security, the Trump administration is asleep at the wheel.” relative values
Conservative think tank
was even harsher: “The Department of Energy’s current scheme to subsidize coal and nuclear plants is yet another attempt to promote politically preferred energy technology under the guise of national security.” Rachel Zissimos, a policy analyst specializing in national security at the group, and Katie Tubb, a policy analyst for Heritage’s Roe Institute for Economic Policy Studies, added that the “national security card” gives politicians and special interests “a free pass from political debate and taxpayer oversight.” A more appropriate course of action “is to address the decades of bad federal policies that have put these plants in jeopardy,” they said. The Heritage Group in an op-ed in The Hill
Thomas J. Pyle, president of the Institute on Energy Research, expanded on that point, noting that “Government constantly intervenes and disrupts free markets in the energy sector. These interventions include renewable portfolio mandates, federal tax credits for wind and solar, state credit regimes for nuclear power plants, just to name a few.” He continued, “Before we think about more government interventions, I propose we reduce those government interventions that already distort and damage the market.”
Responding to the strong reaction from the renewables groups, Pyle noted it was “most entertaining” that “the outcry from the wind, solar and environmental special interest groups on this issue is a perfect example of the absolute hypocrisy from the left.
“They gladly accept government actions that favor wind, solar or other alternative sources, but complain when the government steps in to tip the scales towards reliable energy like coal and nuclear generation.”
—Sonal Patel is a POWER associate editor (@sonalcpatel, @POWERmagazine)
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Swift (and Angry) Reaction to Trump Move to Save Coal, Nuclear Plants
Fri, 01 Jun 2018 20:58:27 +0000
Reactions from U.S. energy and legal and regulatory groups began pouring in minutes after the White House confirmed on June 1 that President Trump has directed the Department of Energy (DOE) to act immediately to stop the loss of uneconomic coal and nuclear plants. White House Press Secretary Sarah Sanders said in a June 1 […]
Swift (and Angry) Reaction to Trump Move to Save Coal, Nuclear Plants appeared first on POWER Magazine. Reactions from U.S. energy and legal and regulatory groups began pouring in minutes after the White House confirmed on June 1 that President Trump has directed the Department of Energy (DOE) to act immediately to stop the loss of uneconomic coal and nuclear plants.
White House Press Secretary Sarah Sanders
said in a June 1 statement that President Trump believes in “total energy independence and dominance, and that keeping America’s energy grid and infrastructure strong and secure protects our national security, public safety and economy from intentional attacks and natural disasters.”
Because “impending retirements of fuel-secure power facilities are leading to a rapid depletion of a critical part of our nation’s energy mix, and impacting the resilience of our power grid,” the president has directed Energy Secretary Rick Perry to “prepare immediate steps to stop the loss of these resources, and looks forward to his recommendations,” she said.
White House confirmation comes hours after the leak of a Trump administration draft memo outlining a plan for federal action to prop up coal and nuclear plants that were unable to compete in wholesale power markets and faced retirement. Details of plan outlined in the memo are here: “ Trump Administration to Force Purchases of Coal, Nuclear Power.” Unprecedented Government Intervention
In a joint statement, a diverse group of energy industry associations including energy efficiency and storage, natural gas, oil, solar, and wind, condemned the action, saying the subsidized “failing coal and nuclear plants. The proposed action is “misguided” and “would hurt consumers,” the group said.
Most comments lambasted the government’s intervention in energy markets to provide assistance to coal and nuclear plants.
Todd Snitchler, American Petroleum Institute Market Development Group Director, said the plan “under the guise of national security would be unprecedented and misguided.” The natural gas and oil industry plays a leading role in reducing dependence on foreign energy, and the U.S. is on track to achieve energy dominance around the world, he noted. “However, unprecedented government intervention in the energy markets to support high cost generation will put achieving that vision in jeopardy and hurt customers by taking more money out of their pockets rather than letting people keep more of what they earn—a key priority of this administration.”
John E. Shelk, president and CEO of the Electric Power Supply Association—whose members are generators that bank on revenues in wholesale markets, including independent power producers, noted that the plan would “needlessly raise the costs for consumers, and “merely shifts the risk of premature retirement to newer, more efficient power plants that compete with coal and nuclear.” As a number of other entities noted, Shelk said no energy emergency existed, and the rash plan could have widespread and long-wearing effects. “There is none today that justifies such unprecedented Executive Branch intervention in the economic life of the country,” he said. “The economic consequences are profound for power suppliers and consumers. This proposed federal action is a bell that cannot be called back once it is rung. Forever more suppliers and consumers will be at the whim of the fuel preferences of whoever happens to be in office.”
Dena E. Wiggins, president and CEO of the Natural Gas Supply Association railed against the plan’s proposal to prop up uneconomic plants through the Defense Production Act, the Federal Power Act, “or other unnecessary federal intervention is a short-sighted action that drives up customer costs and undermines well-functioning power markets.” Wiggins pointed to “an inappropriate use of the federal government’s emergency powers that is even more egregious when even the regional power grid authorities at PJM say there is no emergency. We need to move away from a narrow focus on resuscitating individual projects and refocus the discussion on what lies at the heart of resiliency – the ability to reliably serve power customers in the most cost-efficient manner over both the short and the long-term.”
Undermining Market Stability for New Entrants
Kelly Speakes-Backman, CEO of the Energy Storage Association, said fair competition for all market participants was imperative, and incentives for specific generators could create uncertainty for new market entrants. She noted that participants rely on consistent and stable price formation signals. “Any action that undermines market stability to support new entrants like energy storage—resources that enhance grid resilience and reduce costs to consumers—will erode opportunities to create a more reliable and resilient, efficient, sustainable and affordable grid.”
Wind and solar industry trade organizations, and a handful of major environmental groups, suggested that the Trump administration hadn’t considered the evolving power landscape. “A policy to spend billions of dollars keeping uneconomic power plants afloat, while trying to put clean and affordable solar on the sidelines, is not a recipe for economic success,” said Christopher Mansour, Solar Energy Industries Association vice president for Federal Affairs. “Energy experts across a range of industries, within the federal government and in academia have agreed that this sort of effort will create a bloated power sector deploying outmoded technologies. We urge policymakers to again block this ill-advised effort to keep plants running that most electric utilities have already decided to abandon, and for good reason.”
Amy Farrell, senior vice president for Government and Public Affairs at the American Wind Energy Association, noted that independent energy regulators, grid operators and other experts have gone on the record “to declare that orderly power plant retirements do NOT constitute an emergency for our electric grid.” Farrell added that infrastructure and processes are already in place to ensure that remains the case. “The reported proposal would be a misapplication of emergency powers, there’s certainly no credible justification to force American taxpayers to bailout uneconomic power plants.”
The Environmental Defense Fund (EDF), an environmental advocacy group, pointed out the DOE’s draft plan is the newest development in a string of attempts to prop up coal and nuclear. “FirstEnergy has spent years trying every possible avenue to prop up its uneconomic, unnecessary power plants, often relying on political contributions and high-powered lobbyists. Two arcane laws the utility giant has pointed to include the Defense Production Act and Section 202(c) of the Federal Power Act, both of which will likely form the basis of President Trump’s new directive,” it said. “We don’t know yet how today’s move will affect FirstEnergy, but it’s clear Washington’s new swamp has created a monster: A multi-billion dollar attack on American families, markets and the law.” EDF said it will “forcefully” oppose the plan “every step of the way.”
The Legal Perspective
Industry observers from the legal realm appeared just as horrified. Jason Johns, a partner at Stoel Rives who advises independent power producers, utilities, and large users of power resources about matters concerning power markets and state and federal energy regulatory arenas, said that the Trump administration’s “transparent efforts to meddle with market realities under the pretext of national security, and the continued push to resolve the imaginary, and woefully undefined, issue of grid resilience—something that America’s wholesale energy market operators largely laughed at and rejected—simply fails the smell test.”
“In fact, it reeks and appears to be little more than a tantrum thrown in response to FERC’s surgical dismantling of the DOE’s similar demand last year.”
Johns pointed out that several states have moved to subsidize nuclear power already, which is likely why the Trump administration’s efforts “cannot be meant for much more than coal plants.” Jobs aren’t an issue: “The solar industry alone employs more Americans than the coal industry. If the President were concerned with this country’s future, then he would push for the greater advancement of renewable resources,” he noted.
Rabeha Kamaluddin, a partner in the international law firm Dorsey & Whitney’s Regulatory Affairs group, said: “Any plan to bail out coal and nuclear plants using the emergency powers under Section 202(c) Federal Power Act will likely face significant challenges at both the agency and judicial levels. Such powers have been invoked in very limited instances, and in those instances, ’emergencies’ have pertained to natural disasters, hurricanes, and major blackouts—events that hit at the core of grid reliability and power supply.”
Kamaluddin, who focuses her practice on energy regulation, compliance, and enforcement matters and represents clients before the Federal Energy Regulatory Commission, added that “Without connecting the emergency to such things, this unprecedented plan will likely face challenges passing judicial scrutiny. If the plant is successful in passing such scrutiny, it will allow for a broader interpretation of emergency under the Federal Power Act, and open the door for the DOE/FERC to invoke such powers in future cases where the underlying reason for the emergency is an economic one.”
—POWER’s editors (@POWERmagazine)
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[UPDATED] Trump Administration to Force Purchases of Coal, Nuclear Power
Fri, 01 Jun 2018 13:34:52 +0000
A draft memo circulated by the Trump administration before the National Security Council urges federal action to force grid operators to buy power from uneconomic coal and nuclear plants. Bloomberg on May 31 first pointed to the existence of the 41-page memo, which is dated May 29 and distributed Thursday. The memo outlines plans for a […]
[UPDATED] Trump Administration to Force Purchases of Coal, Nuclear Power appeared first on POWER Magazine. A draft memo circulated by the Trump administration before the National Security Council urges federal action to force grid operators to buy power from uneconomic coal and nuclear plants.
Bloomberg on May 31 first pointed to the existence of the 41-page memo, which is dated May 29 and distributed Thursday. The memo outlines plans for a directive by the Department of Energy (DOE) under Section 202(c) of the Federal Power Act (FPA) to “direct the operators to purchase electricity or electric generation capacity from at-risk facilities.”
The draft memo, which is tagged “Privileged & Confidential, Attorney-Client Privilege,” says that regulatory and economic factors have prompted the premature retirement of “fuel-secure” plants—which include nuclear and coal, but also oil-fired and dual-fuel units with adequate storage. “Although the lost megawatts of power often are replaced by new generation from natural gas and renewable energy sources, this transition comes at the expense of fuel security and resilience,” it says.
The memo reasons that because premature retirements of fuel-secure baseload plants reduce resilience to fuel supply disruptions, and because this “crisis” is caused by regulatory and economic actions, federal and state regulatory bodies as well as the private sector must act promptly “to achieve a lasting solution that meets the needs of both national security and the efficient operation of energy markets.”
The DOE adds that it has begun a 24-month-long analysis, working with five national laboratories to identify critical defense facilities” served by “Defense Critical Electric Infrastructure.” In the meantime, the DOE will issue an order (or directive) with authority under the Defense Production Act and FPA as a “temporary stop-gap measure to prevent the further permanent loss of the fuel-secure electric generation capacity for the grid upon which our national security depends, much like the interstate highway system.”
The directive—which will be effective for two years—will direct system operators “to purchase or arrange the purchase of electric energy or electric generation capacity from a designated list of subject generation facilities (SGFs) sufficient to forestall any further actions toward retirement, decommissioning, or deactivation of such facilities during the pendancy of DOE’s order.” SGFs, outside of wholesale market territories should meanwhile continue generation and delivery of power according to their existing contractual arrangements with load-serving entities.
As outlined in the memo, the order will also establish a strategic electric generation reserve (SEGR) to promote the national defense and maximize domestic energy supplies. “This prudent stop-gap measure will allow the Department further to address the Nation’s grid security challenges while the Order remains in force.”
In response to
POWER’s questions on Friday, the DOE shared a statement confirming federal action from White House Press Secretary Sarah Sanders.
Sanders said in the June 1 statement that President Trump believes in “total energy independence and dominance, and that keeping America’s energy grid and infrastructure strong and secure protects our national security, public safety and economy from intentional attacks and natural disasters.” Because “impending retirements of fuel-secure power facilities are leading to a rapid depletion of a critical part of our nation’s energy mix, and impacting the resilience of our power grid,” the president has directed Energy Secretary Rick Perry to “prepare immediate steps to stop the loss of these resources, and looks forward to his recommendations,” she said.
PJM: No Need for ‘Drastic Action’
PJM, the nation’s largest RTO, on Friday said in a statement that it has not received any official documents or directives from the DOE. “Our analysis of the recently announced planned deactivations of certain nuclear plants has determined that there is no immediate threat to system reliability. Markets have helped to establish a reliable grid with historically low prices,” the grid operator said. “Any federal intervention in the market to order customers to buy electricity from specific power plants would be damaging to the markets and therefore costly to consumers.”
The grid operator emphasized that there is no need for “any such drastic action.”
PJM results for its 2021/2022 capacity auction, released just last week, saw an increased amount of coal resources clear the market, along with other resources it noted. Wholesale prices were also tumbling. “From 2008 to 2017, wholesale prices in PJM fell by more than 40 percent. Competition has required generators to operate more efficiently while also attracting new, more efficient technology, resulting in more than $1.4 billion in annual savings.”
PJM also said it acknowledged concerns raised by the Trump administration and regulators about the long-term resilience of the grid. “We are embarking on a fuel security initiative that we announced just a few weeks ago. Our goal with that initiative is to ensure that the already reliable electric grid will continue to remain both reliable and resilient for years into the future without the need for government intervention in the marketplace,” it said.
An Extraordinary Emergency
Section 202(c) of the FPA gives the energy secretary extraordinary authority to order temporary connections of facilities and generation, delivery, interchange, or transmission of power to mitigate a power emergency, such as a shortage.
But the DOE has only issued emergency orders under the FPA at least seven times before—mostly during active energy crises, such as in California in 2000; in Long Island in 2002; during the well-known Northeast blackout of August 2003; and during Hurricanes Rita and Ike in 2005 and 2008. Last April, however, the DOE issued a first-of-its-kind emergency order to keep open a plant slated for shutdown under the Mercury and Air Toxics Standards and secure reliability in Oklahoma.
On March 29, FirstEnergy Corp.’s bankrupt competitive arm FirstEnergy Solutions (FES) filed an application with the DOE urging the agency to “find that an emergency condition exists” in PJM Interconnection’s footprint that requires immediate intervention by the energy secretary in the form of a Section 202 (c) order. The order should direct “certain existing nuclear and coal-fired generators in PJM … to enter into contracts and all necessary arrangements with PJM, on a plant-by-plant basis, to generate, deliver, interchange, and transmit electric energy, capacity, and ancillary services as needed to maintain the stability of the electric grid,” it said.
While the DOE hasn’t publicly rejected the application, it continues to seek ways to keep uneconomic baseload generation from retiring. In September 2017, the agency proposed its “
Grid Resiliency Pricing Rule,” directing the Federal Energy Regulatory Commission (FERC)—an independent regulatory government agency that is officially organized as part of the DOE—to exercise its authority under sections 205 and 206 of the FPA and require that independent system operators (ISOs) and regional transmission organizations (RTOs) “establish just and reasonable rates for wholesale electricity sales” for power plants that show “reliability and resiliency attributes.” FERC rejected the DOE’s rule on January 8, however, initiating instead a new proceeding that will examine the resilience of the bulk power system. A More Recent Tactic: The Defense Production Act
This past April, meanwhile,
coal and nuclear generators who were supportive of the DOE’s controversial proposal called on the Trump administration to use a Cold War-era law—the Defense Production Act—to subsidize uneconomic baseload plants to secure grid security. The 68-year-law passed by Congress during the Korean War has historically been reserved for use during military operations and major national emergencies, such as the California gas crisis. Energy Secretary Rick Perry told the House Committee on Science, Space and Technology on May 9 that the DOE is “looking very closely at” the law as a way to secure the nation’s energy grid.
“That’s approaching this from an economic standpoint and I think … it’s about the national security of our country, of keeping our plants, all of them, online, being able to deliver energy” in an emergency, he told the committee.
But that measure, too, was heavily criticized. On May 10, a bilateral and bipartisan coalition of American industry associations
submitted a legal analysis to the DOE stressing that the Defense Production Act does not contain authority to provide above-market pricing to power plants. The trade groups—which include the Advanced Energy Economy, the American Petroleum Institute, the American Wind Energy Association, the Electric Power Supply Association, the Interstate Natural Gas Association of America, and the Natural Gas Supply Association—also urged the DOE to reject FES’s petition under Section 202(c) and noted that Section 215A of the FPA authorizes only temporary measures in response to grid security emergencies.
David Spence, an energy law professor at the University of Texas at Austin,
told the : “One can’t really use this wartime authority to subsidize coal and nuclear with a straight face. And I say that as someone who believes that keeping nuclear power plants open is good policy.” Washington Post in early May
A Federal Fog
Where FERC stands on the issue of propping up uneconomic baseload power plants for reliability is also murky. The regulatory body has traditionally opposed intervention in wholesale markets.
In January, as it rejected the DOE’s grid pricing rule, it said it has taken steps with regard to reliability and other matters that have helped to address the resilience of the bulk power system. However, it added: “The Commission recognizes that it must remain vigilant with respect to resilience challenges, because affordable and reliable electricity is vital to the country’s economic and national security.”
On Tuesday, in a move that surprised industry observers,
FERC told the U.S. 7th Circuit Court of Appeals that Illinois’ nuclear subsidy program does not preempt federal statute, siding with the state and Exelon Corp. in a contentious legal fight that has divided the power sector.
According to Bloomberg, the memo makes a case for action, arguing that a lapse in reliability would affect national security, and federal intervention is necessary. Under the plan, the DOE would reportedly direct grid operators to buy power from designated facilities for two years “to forestall any future actions toward retirement, decommissioning or deactivation,” the news outlet reported. The planned action will serve as a “prudent stop-gap measure” while the DOE addresses the nation’s “grid security challenges” in a two-year-long study.
—Sonal Patel is a POWER associate editor (@sonalcpatel, @POWERmagazine)
Updated—June 1: Adds comments from the White House press secretary; adds comments from PJM; adds details from the leaked memo
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How General Atomics Developed Its Revolutionary Nuclear Fuel Solution
Fri, 01 Jun 2018 04:00:47 +0000
The U.S. is pouring funding into developing new fuel technology for advanced nuclear reactors in a bid to help the flagging industry. On April 27, it awarded General Atomics (GA) $3.2 million for two projects that the San Diego, California-based company is developing, including an accident tolerant fuel (ATF) solution that the company says is […]
How General Atomics Developed Its Revolutionary Nuclear Fuel Solution appeared first on POWER Magazine. The U.S. is pouring funding into developing new fuel technology for advanced nuclear reactors in a bid to help the flagging industry. On April 27, it awarded General Atomics (GA) $3.2 million for two projects that the San Diego, California-based company is developing, including an accident tolerant fuel (ATF) solution that the company says is “truly revolutionary.”
The funding, for which GA will provide a cost share, is aimed to advance development and licensing of new reactor fuel that features silicon carbide (SiC) composite fuel cladding containing uranium carbide (UC) fuel pellets. One project, being conducted in collaboration with the Oak Ridge National Laboratory and the University of Tennessee with total funding of $2,763,744, will combine advanced computer modeling and simulation with new microcapsule irradiation to establish techniques that “substantially reduce the time and expense required to qualify new fuels,” the company said. The second project, funded at a total of $475,819, would back the pre-application license review of SiC-UC fuel by the Nuclear Regulatory Commission, allowing the company to develop an efficient roadmap for formal regulatory qualification.
Nuclear Prospects for a 100-Year-Old Compound
General Atomics told
in April that it has been working with SiC—which it recently furnished with the trade name, “SiGA”—since the 1960s. SiC ceramic, it noted, has been used for a variety of industrial purposes for more than 100 years, and owing to its high hardness and ability to withstand extremely high temperatures, the composite has long been considered ideal for cutting tools, refractory components, and high-power electrical systems. POWER
“However, its brittleness in pure form has limited its use as a structural material,” GA explained. In the 1990s, researchers discovered that monolithic SiC can be significantly toughened by reinforcing it with flexible SiC fibers, forming a combined material known as a ceramic matrix composite (CMC). “In a CMC, these fibers provide reinforcement similar to how steel rebar reinforces concrete. CMCs have been explored for a variety of high-temperature applications (mainly in aerospace), but manufacturing challenges and problems with joining composite components have slowed deployment,” it said (Figure 5).
General Atomics says its silicon carbide ceramic technology greatly enhances nuclear fuel rod coping time under loss of core cooling and improves performance across normal operations. The company’s cladding design combines a tough composite layer with an impermeable monolithic layer. 5. Ceramic clad. Courtesy: General Atomics
GA’s experience with SiC began with SiC-coated TRISO fuel particles for the Fort St. Vrain reactor. The facility in Colorado operated as a nuclear plant between 1979 and 1989. After it was decommissioned, Fort St. Vrain was converted to a natural gas plant that is today owned by Xcel Energy. In the late 2000s, GA stepped up its research on SiC CMCs for nuclear fuel cladding while developing its advanced high-temperature gas-cooled reactor (HTGR) design, the Energy Multiplier Module (EM
). EM 2 is a small modular helium-cooled fast reactor that could offer dramatic improvements in cost, safety, and non-proliferation while reducing waste production and enabling the use of multiple fuel types, including spent reactor fuel, GA said. “Because EM 2 2 is designed to operate at temperatures up to 850C, it requires fuel rods that can safely withstand such conditions. SiC CMC was identified as the best solution,” it added.
The technology has gained a renewed relevance owing to the nuclear industry’s commitment to developing ATFs in a timely way. (For more, see “
Accident-Tolerant Fuels Could Be a Boon for Nuclear Industry” in April 2018 issue.) As GA noted, interest in fuel rods that can tolerate extreme temperatures surged after the Fukushima accident in 2011. POWER’s
“One of the elements that made this disaster so severe is related to the zirconium-alloy fuel rod cladding used in current reactor cores. At Fukushima, after the water boiled away and the core overheated, the cladding reacted violently with high-temperature steam in the reactor vessel. This highly exothermic reaction between zirconium and the oxygen in the steam added to the thermal energy already present from decay heat and also generated explosive hydrogen. This was one of the main factors that caused the cores to melt down and led to the hydrogen explosions that breached the reactor’s containment,” it said.
ATF Advancement: Evolutionary v. Revolutionary
Today, under the Department of Energy’s ATF program, which Congress launched in 2012, several nuclear fuel makers are developing several concepts for ATF fuel pellet and cladding materials, and testing is underway or scheduled at four nuclear units in the U.S. GA leveraged its work on EM
2 to successfully partner with Westinghouse in proposing a SiC-based ATF solution. But its solution stands out from other efforts, the company said.
While other ATF initiatives are exploring evolutionary advances, such as coated metals or new alloys, SiC is said to offer “a truly revolutionary ATF technology.” GA claims SiC CMCs can withstand far harsher conditions than metal fuel rods. Tests have shown that SiC-SiC cladding can retain its strength at temperatures greater than 3,000F (1,700C), more than twice the tolerance of zirconium alloys. The material has also survived immersion in water from temperatures as high as 1,200C. Additionally, SiC is much more chemically stable, virtually eliminating the risk of hydrogen explosions during loss-of-cooling accidents, according to the company.
In tandem, GA is developing a robust and durable end joint seal to keep fission products safely contained during normal operation. Using dissimilar materials to bond SiC joints typically results in cracking under irradiation, the company noted, so it created a high-purity stoichiometric SiC bonding method, known as GA-HSiC, to seal the fuel rod end joints. “Recent tests at Oak Ridge National Laboratory demonstrated that both the SiC CMC and the HSiC joints retained their integrity under irradiation and showed no signs of cracking that would release fission products,” it said.
Asked how ATF fuels—and specifically GA’s SiC composite SiGA—would improve cost efficiency, the company explained that SiGA cladding improves the neutron efficiency of the core, “meaning more neutrons are available to sustain the fission reaction.” Combined with advanced uranium silicide and uranium carbide fuels, SiGA cladding also allows for higher fuel density, resulting in higher burn-up and longer refueling cycles. That translates to reduced fuel costs.
“The combination of SiGA cladding and advanced fuels will also add margin to normal operation, anticipated operational occurrences, design-basis, and beyond-design-basis accidents. This added margin means greater operational flexibility and the opportunity for plant uprates,” the company added. “While it is difficult to put exact numbers on this without testing under operational conditions, the bottom line is that a shift to ATF will mean increased plant revenue, perhaps significantly so.”
For now, owing to the notable benefits in safety, efficiency, and operating costs offered by GA’s SiC-SiC ATF over current metal fuel rod designs, the company anticipates the technology will be widely sought commercially. To meet future commercial demand, GA is developing a proprietary mass-production process for high-purity SiC CMCs. “Once completed, this process could open up substantial possibilities in nuclear, defense and aerospace applications in addition to ATF,” it said.
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THE BIG PICTURE: CEO-to-Employee Pay Ratio
Fri, 01 Jun 2018 04:00:30 +0000
As required for the first time by a new Securities and Exchange Commission (SEC) rule mandated by the 2010 Dodd-Frank Act and Item 402(u) of Regulation S-K, public companies in early 2018 began disclosing ratios that compare total compensation paid to principal executive officers (PEOs), such as a CEO, to the median of the annual […]
THE BIG PICTURE: CEO-to-Employee Pay Ratio appeared first on POWER Magazine. As required for the first time by a new Securities and Exchange Commission (SEC) rule mandated by the 2010 Dodd-Frank Act and Item 402(u) of Regulation S-K, public companies in early 2018 began disclosing ratios that compare total compensation paid to principal executive officers (PEOs), such as a CEO, to the median of the annual total compensation of all employees. For companies in the U.S. power sector, that pay ratio varies widely. It should be noted that while the SEC in September 2017 provided guidance for companies outlining how to implement and comply with the pay ratio rule, CEO compensation may appear inflated owing to one-time bonuses. Other factors, such as part-time employment, may push median worker pay lower. Note: Companies are ranked by total revenues for 2017.
Sources: Company-filed proxy statements pursuant to Section 14(a) of the Securities Exchange Act of 1934; vectors from Freepik
—Copy and artwork by Sonal Patel, a POWER associate editor
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India’s Power Industry Struggles to Solve Pollution Problems
Fri, 01 Jun 2018 04:00:30 +0000
In a bid to tamp down pollution, India’s government in December 2015 notified the country’s coal generators they would need to meet—for the first time—new emissions limits for nitrogen oxides (NOx), sulfur dioxide (SO2), and mercury, as well as tightened limits for particulate matter (PM) and water consumption. The gazetted notification gave new plants until […]
India’s Power Industry Struggles to Solve Pollution Problems appeared first on POWER Magazine. In a bid to tamp down pollution, India’s government in December 2015 notified the country’s coal generators they would need to meet—for the first time—new emissions limits for nitrogen oxides (NO x), sulfur dioxide (SO 2), and mercury, as well as tightened limits for particulate matter (PM) and water consumption. The gazetted notification gave new plants until January 2017 and existing plants just two years—until December 2017—to curb those pollutants.
But on November 17, 2017, in an affidavit filed with the Supreme Court of India, the Ministry of Environment, Forest, and Climate Change (MoEFCC) recognized the timeframe wasn’t feasible. India produces 80% of its power with coal, and electricity is an “essential commodity and [an] uninterrupted power supply in the country needs to be ensured at all times, therefore, many units cannot be taken out for retrofitting at the same time and it has to be done in phases, so as to avoid [a] problem in the power supply,” it said, asking the high court for an “appropriate order” to extend compliance deadlines until at least 2022.
In the affidavit, the MoEFCC also urged the court to relax a ban it issued in October of pet coke and furnace oil use by power generators and the cement sector in three states (Uttar Pradesh, Rajasthan, and Haryana) that flank the National Capital Region, which is battling an unprecedented smog crisis (Figure 1). The MoEFCC noted that while state-owned natural gas processing and distribution company GAIL was looking into what it will take to make power generation through gas competitive with coal plants, it was clear that India does not have enough domestic natural gas to fuel its power sector. “Present availability of domestic natural gas is only 23 [million metric standard cubic meters per day],” it said. That’s enough to fuel 5 GW of power capacity, against a demand of 120 GW to 160 GW for the whole country.
1. A pollution predicament. New Delhi and neighboring areas in the National Capital Region of India are battling a debilitating air pollution crisis. In November 2017, fine particles suspended in the air shot up to maximum levels recorded, soaring beyond hazardous levels. New Delhi officials took drastic measures, curbing construction and demolition work, banning diesel generators, and temporarily shutting down a coal-fired power plant, while the Supreme Court ordered the Environmental Pollution Control Authority to come up with an immediate, “comprehensive” plan to tackle the issue. This image was taken at the New Delhi railway station on December 31, 2017. Courtesy: Sumita Roy Dutta/Creative Commons ‘Compliance with New Norms Is Limited’
As the court contemplates these matters, coal generators across the country are exploring the most economic and technically feasible options to comply with the MoEFCC’s new environmental rules. Dr. Rahul Tongia, a fellow with New Delhi–based Brookings India, explained to
POWER that generators have asked the government to temper emissions limits stipulated in the original edict, as well as to phase them in, focusing first on PM and NO x last. Currently, “compliance with the new norms is limited, especially for plants that need retrofitting, and it’s not clear when these would get implemented in full,” he noted. “If the past is any guide, then much of the benefits of a five-year delay could be lost—instead of testing, learning, and implementing in phases, there might be limited action at the beginning, and a scramble near the end.”
In a paper he authored for Brookings India in February 2017, Tongia noted that India’s environmental focus rests on PM, specifically, fine particulates (PM 2.5)—even though SO
2 and NO x, which, emitted as gases, convert to PM after atmospheric reactions. “India used to claim that its coal was low-sulfur, and hence [flue gas desulfurization (FGD)] wasn’t required,” he noted. Meanwhile, the data for how many plants have actually installed SO 2 controls to comply with the new limits is scarce.
According to the International Energy Agency’s (IEA’s) Clean Coal Centre, many coal generators have individual deadlines for installation of pollution controls, but delays are expected owing to a number of issues as India attempts to introduce mass retrofits or new technologies. The country will need to tackle technical difficulties; financial issues associated with introducing multiple technologies at the same time; a lack of local suppliers; and a subsequent need to import technologies as well as all materials and reagents. Then it must grapple with a lack of local skills and expertise. “The utilities have no experience in continuous emissions monitoring,” it noted in a February 2018 report. NOx Compliance: A Pipe Dream?
The IEA Clean Coal Centre’s report specifically highlights India’s coming troubles associated with its stringent new NO
x limits. The new rules require coal plants built before 2004 to emit less than 600 milligrams (mg) of NO x per cubic meter (m 3). Plants installed after 2003 and before 2017 must emit no more than 300 mg/m 3, and plants installed after January 1, 2017, must limit NO x emissions to 100 mg/m 3.
Significantly, however, as Sanjeev Kumar Kassi, who serves as director for thermal engineering and technology development at India’s Central Electricity Authority, noted: “Globally available [selective catalytic reduction (SCR)] system[s] for reducing NO
x emissions are not proven for Indian coal having high ash contents. No proven and established control technology suited to our high-ash Indian coals exists and pilot studies [are] needed before deploying any technology.”
The IEA points out that many boilers in India already have overfire air and deploy fuel biasing, but only a few have low-NO
x burners. (That point has been contested by an expert on the Indian power market, who notes that because Indian plants did not have pollution standards before the 2015 announcement, no overfire air was ever used.) To meet the new limits, more than 300 units may require SCR, it said. Though SCR achieves the highest NO x removal rates of all NO x controls (at 80% to 90%), it is also the most expensive option. Installing SCR systems in existing units may also be technically difficult, owing to plant layout. “For example, an extensive change in duct work, an [induced draft] fan, and other equipment will be required, for which there will have been no provision made in the existing design. There will be a need for reagent storage, an injection grid, and the associated installations.”
An SCR for a 500-MW unit could also consume 2,500 tons per year of ammonia, but the use of ammonia as a reagent will cause new environmental and safety concerns. An SCR system would also require extra outages for inspection and replacement of the SCR catalyst, which is subject to high rates of erosion due to the ash content of the coal, and it may not reach the three-year average lifetime achieved with international steam coals. Then, “installation of the new system will lead to changes in [operations and maintenance] and greater auxiliary power consumption due to the increased pressure drop in the system,” it said.
The Challenge of Control System Supply
Beyond those challenges, India will likely need to import NO
x control systems “as they are not manufactured in India” and ensure they are suited to Indian conditions. Citing Kassi, IEA noted that India is already facing a limited supply of desulfurization systems. Consequently, the installation of NO x control technology at a rate of 20,000 MW/yr for a total 256,000 MW capacity (made up of 175,200 MW of existing units plus 80,800 MW under construction) would take more than 10 years.
Cost increases are also inevitable, with implications for the country’s power reliability, and grid operators will be forced to take into account plant outages needed for modifications and retrofits. The IEA suggests that a high demand for pollution control systems within the short timescale could raise the energy tariff by an estimated 1¢/kWh. For plants older than 15 years, any increase in tariffs could hamper recovery of the investment within their remaining lifetime. For plants whose construction began before the new limits were introduced, delays and cost increases related to redesign are inevitable.
However, Ravi Krishnan, founder of global consulting firm Krishnan & Associates, also cited in the report, told
POWER that competition among pollution control manufacturers is fierce in India. “I personally don’t believe that there’s a shortage of suppliers because there are at least 30 to 35 emission control companies around the world who are all centered into India, because the market for worldwide coal-fired emissions control technologies are dwindling. Coal-fired power plants are no longer being built in many parts of the world and some are being shut down because of revenue pressures from gas.” Krishnan said demand for emission control technologies is dependent on new markets like India. “In fact, at a recent bid at NTPC, I think there were close to 25 to 30 suppliers. There are a lot of Chinese, European, American, Korean, and Japanese suppliers with [joint ventures] in India,” he said.
For now, despite several hurdles on the horizon, a few major players are evaluating NO
x control technologies. The country’s largest power generator NTPC currently is carrying out eight pilot projects for installation of SCR and selective non-catalyst reduction (SNCR). Results for these projects are expected in 2019, and the IEA noted that “utilities are not expected to make decisions before the outcome of these tests is clear.” Indian power equipment maker BHEL is also testing its own SCR catalyst on a pilot scale. Recognizing the market’s potential, global equipment manufacturers have also jumped into the game. Doosan Babcock and Doosan Heavy Industries recently developed low-NO x burners specifically for such applications.
However, SCR isn’t the only option, noted the IEA. Generators may also consider multipollutant control technologies like ReACT (Regenerative Activated Coke Technology), which was conceived in Germany in the 1950s and has been used successfully in Japan and in the U.S. (Figure 2); Haldor Topsoe’s SNOX, an FGD system that can remove NO
x and particulates from flue gas; Tri-Mer’s UltraCat, a ceramic filter technology; and Linde’s LoTOx, a process that uses low-temperature ozone injection to oxidize NO x for capture in an FGD system. “Although, there are no multi-pollutant systems developed specifically for high ash coals, it appears that the existing ones can be applied successfully,” the IEA noted. The potential of the ReACT system in particular for Indian high ash coals has reportedly been recognized by the Indian government and utilities. However, both cost and water availability should be important considerations in the technology selection process in India, it added.
2. A multi-pollution solution. Wisconsin Public Service began commercial operation of the first-of-its-kind U.S. ReACT (Regenerative Activated Coke Technology) facility at the Weston Power Plant 321-MW Unit 3 in November 2016, after a three-year construction period. According to the utility, with the $345 million ReACT facility in service, Weston 3’s emissions, including mercury, NO , particulate matter, and SO x 2, are all well below legal and regulatory requirements. This image shows construction of the facility by Miron, which conducted superstructure work. Courtesy: Miron
Still, “It may be years before the exact effect is known of Indian coals on these systems. Hence contracts with potential suppliers should have some flexibility and there should be provisions for future possible technical changes,” the IEA said.
— Sonal Patel is a POWER associate editor
Updated (June 4): Adds note perspective about IEA’s claim that many boilers in India already have overfire air.
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Renewable Growth Soars, Buoyed by Distributed Generation
Fri, 01 Jun 2018 04:00:12 +0000
Nameplate renewable capacity surged to more than 2,000 GW worldwide at the end of 2016, constituting more than 28% of total generating capacity (Figure 6). Most (56%) was hydropower, followed by wind (23%), and then solar, mostly from photovoltaic (PV) at about 15%. According to the International Renewable Energy Agency (IRENA) the expansion was fueled […]
Renewable Growth Soars, Buoyed by Distributed Generation appeared first on POWER Magazine. Nameplate renewable capacity surged to more than 2,000 GW worldwide at the end of 2016, constituting more than 28% of total generating capacity (Figure 6). Most (56%) was hydropower, followed by wind (23%), and then solar, mostly from photovoltaic (PV) at about 15%. According to the International Renewable Energy Agency (IRENA) the expansion was fueled by dedicated policies and technological advancements that have, in turn, driven costs downward. While the agency projects soaring growth of all renewables for power, one sub-sector making notable headway is distributed generation (DG), which allow the production of energy near the point of use.
6. Trends in installed renewables by technology (2005 to 2016). Courtesy: IRENA
In a report released this April titled
, IRENA suggests that the modular nature of DG systems allows for rapid deployment, and typically, it is the most “cost-effective energy option for rural off-grid locations.” Because DG enables local self-consumption, it can deliver savings both to the end consumer and the system as a whole. Renewable Energy Policies in a Time of Transition
But growth of the new sub-sector is still pegged to regulatory and pricing policies, including administratively set feed-in tariffs (FITs) or feed-in policies (FIPs), as well as net metering and net billing schemes, which allow DG system owners to reduce or eliminate the variable charge portion of their electricity bills, the agency noted. As with larger scale renewable installations, DG FIPs/FITs are typically designed to encourage distributed PV. Net metering provides compensation to DG owners in energetic terms (credit in kWh), and the credit can be applied to offset consumption of electricity within current or future billing cycles. In net billing, compensation is monetary, and an owner can consume power from the DG system in real-time and send excess generation to a utility’s grid (though unlike net metering, banking kWh in a billing cycle to offset future consumption is not allowed). The world has increasingly adopted both policies. The number of countries adopting net metering and net billing grew from 9 in 2005 to 55 to 2017.
According to the report, distributed PV has achieved the most significant growth. Investments soared to $67.4 billion in 2015, up 12% from 2014. Developing countries largely led this surge, armed with effective financing, innovative business models, and as distributed PV costs generally declined. IRENA also noted, however, that the subsector has opponents that are pushing for reformulation of net metering schemes. Some utilities, for example, argue that net metering fees paid to prosumers for excess power unfairly transfer costs to the utilities.
“Well-designed net metering schemes that encourage self-consumption can drive prosumers to a more system-friendly behaviour. Regulation should consider appropriate design elements, such as the length and timing of the netting period and the actual value of net excess generation,” the report says.
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Rethinking the Service Delivery Model for Guaranteed Outcomes
Fri, 01 Jun 2018 04:00:09 +0000
Service delivery models are today undergoing unprecedented change to accommodate the needs of customers trying to navigate business and market uncertainties. Around the world, industrial manufacturers are facing new and familiar challenges ranging from economic and competitive pressures and the tightening availability of resources, to aging workforces, rising technology and operating costs, and heightened focus […]
Rethinking the Service Delivery Model for Guaranteed Outcomes appeared first on POWER Magazine. Service delivery models are today undergoing unprecedented change to accommodate the needs of customers trying to navigate business and market uncertainties. Around the world, industrial manufacturers are facing new and familiar challenges ranging from economic and competitive pressures and the tightening availability of resources, to aging workforces, rising technology and operating costs, and heightened focus from top management on optimizing total cost of ownership (TCO).
These pressures are prompting a re-think of how traditional value-added services are delivered. The consensus is that service providers must dispense with longstanding models that are transactional in their approach and move toward forming true partnerships with customers in which they take ownership of the customer’s expected outcome. In other words, service providers are getting skin in the game.
This new model allows service providers to better address customer needs, which today increasingly include:
A desire for continuous innovation, in which incremental improvements are made to ensure system performance
Improved system stability, reliability, and quality
Better operating expenditure (OPEX) and capital expenditure (CAPEX) cost predictability
Protecting intellectual property—such as engineering and training investments—along with previous capital investments
It also allows service providers to help customers tackle acute market and business challenges, such as:
Core competency focus. With costs tightening and a smaller number of personnel responsible for more areas of plants, there’s an increasing appetite among manufacturers to outsource the running of their automation systems in order to focus on core competencies. They might, for example, channel resources to sharpen their value proposition or potentially reinvent their business.
Aging workforce. People aged over 65 are the fastest growing demographic in the workplace through 2024, according to the U.S. Bureau of Labor Statistics. Despite older people working longer, 50% of plant personnel are still due to retire in the next five years, with the younger generation increasingly hesitant to take their places. Not surprisingly, 80% of U.S. manufacturers are reporting a shortage of qualified workers, according to the National Association of Manufacturers.
Remote locations. Many global companies—particularly those in energy—maintain critical operations in remote areas. However, finding skilled, competent resources to run these facilities is difficult, making support a challenge.
Economic shifts. Hundreds of thousands of energy-industry jobs have been cut in recent years due to low prices. Although the industry today is in better health, a report published by the Deloitte Center for Energy Solutions says, “When thinking about potential constraints on the recovery of the industry, we should view people as equally, if not more, critical to capital.” Volatility has long been an energy industry reality, and it remains so today.
Technology obsolescence. The U.S. has a huge installed base of aging assets that require ever-higher levels of maintenance, according to ARC Advisory Group, and the complexity and interoperability of these systems is preventing end-users from having a complete, accurate view of their operations. Technology obsolescence is a growing threat, but the sheer cost of replacing and maintaining systems is a deterrent for many. ARC feels the solution lies in new, intelligent services, which preserve plant assets, eliminate unplanned downtime, and improve productivity and throughput.
With so many challenges to be faced, it’s little wonder servicing models are being re-examined. So, what should the new shape of services look like?
Next-Generation Service Delivery—Today
In the past, customers sought ad-hoc service support or purchased service contracts for their automation systems but still bore the stress and pressure of maintaining them. Today they have more-pressing concerns and are increasingly open to partnerships (Figure 1) with service providers willing to take over the complete running of their systems.
1. Working together. The benefits of outcome-based services are numerous, but the most-significant benefit is arguably the opportunity for energy companies to focus on their core business. Courtesy: Honeywell Process Solutions
Indeed, the evolutionary shift taking place can be described as moving from insurance to assurance. Service providers and customers are looking at the total lifecycle management of a plant’s automation system, and not just the sum of its parts. The notion of support, meanwhile, is morphing from a one-time transaction into an ongoing relationship.
Key performance indicator (KPI) goals are being set based on the enterprise’s, or plant’s, business priorities, with service level agreements put in place to meet those KPIs. In other words, service providers are providing guaranteed outcomes for automation system performance, including advanced control and process optimization, with financial consequences if the agreed upon KPIs aren’t met. The goal for both parties is the sustained performance of IT system, with a strategy of continuous innovation to ensure longevity.
In addition, new capabilities might be added to a customer’s service package based on the needs of the business, such as strengthened cybersecurity capabilities, preventive/predictive analytics solutions, alarm management tools, competency management programs, and continuous evolution programs. Solutions for remote locations, including remote management or human capital support, are available too.
For plant executives, the prospect of another party assuming responsibility for their technology assets is a welcome development (see sidebar “Sasol Chooses Outcome-Based Services from Honeywell”). These decision-makers have long had to cope with the mounting safety, health, and operational risks of their aging control systems while pressured to achieve higher levels of responsiveness, flexibility, and productivity—all with a diminishing level of resources. It’s an impossible task. Outsourcing this responsibility to a partner with the very latest product, application, and vertical knowledge, who will help modernize their systems and tackle their interoperability issues, allows them to mitigate risk, and crucially, focus on the bigger picture.
Sasol Chooses Outcome-Based Services from Honeywell
Sasol, an international chemical and energy company based in South Africa, for years operated a project-based maintenance program that was largely reactive to incidents. Servicing tasks were micromanaged, with strict timings allocated to the completion of jobs, leading to friction between maintenance and the plant staff. The approach wasn’t sustainable, nor did it serve the evolving needs of the business.
What Sasol decision-makers desired was a holistic, proactive approach to maintenance and problem-solving; a focus on outcomes while reducing incidents and lowering costs.
While evaluating Assurance 360 from Honeywell, Sasol discovered a partner with the same motivations. Once deployed, the solution provided agreed upon service levels rather than prescribed quantities of materials and labor. Deliverables included a commitment to continuous improvements aligned with Sasol’s goals; minimized TCO; and expert services that augmented Sasol’s maintenance teams.
The outcome? Plant incidents have been reduced by half, requiring an average of one resource versus the previous three-and-a-half to address them; the initially skeptical engineering team has been won over and is now a willing partner for the service team; and there’s a new, company-wide initiative to drive innovation and improve business performance.
Outcome-based services are now part of Sasol’s culture. Senior Engineer Cobus van Dyk, who manages Sasol’s Critical Control Information Infrastructure team, said: “Assurance 360 has changed the organization for the better, making it more collaborative. The plant has gained trust in us through the results we’ve achieved. Our experience is, if you go into a partnership with a commitment to get a successful outcome, you can attain it with the right partner.”
Adapting to Change
Outcome-based services represent a revolution compared with previous business practices, and they will unquestionably require a period of adjustment on the part of customers and service providers.
One challenge that service providers come up against is that some customer stakeholders—particularly those in maintenance and engineering roles—perceive outcome-based services as a threat to their internal order. For years, these professionals’ day jobs have revolved around their company’s automation systems. Will relinquishing control mean the loss of their jobs? On the contrary, it could strengthen their positions. How so? They will be immediately freed from reactive, time-consuming service workloads and able to redirect their expertise into higher-level activities such as proactive maintenance, control optimization, and resolving underlying problems. In other words, they can better showcase their value to the business.
Service providers, meanwhile, need to be brave and bold, and turn years of traditional practice on its head. Mindsets must change. They need to invest in new technologies and reorganize their skilled talent to support outcome-based models. If they don’t, they risk being left behind as underlying industry trends drive lasting changes in customer needs.
The benefits of outcome-based services, such as
Assurance 360 from Honeywell, are numerous, from continuously improved operations and more predicable OPEX and CAPEX costs, to better system stability, reliability and quality, and optimized TCO. However, the most significant benefit is arguably the opportunity for industrial manufacturers to focus on their core business. With automation and/or process control strategy no longer placing demands on their resources, organizations can channel their expertise into areas of the business that really need it—for example, sharpening differentiators or achieving transformation. Quite simply, strategic opportunities abound.
— Steve Linton is global director, programs and contracts, with Honeywell Process Solutions.
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Maintaining Nuclear Plant Ice Condensers: A ‘Cool’ Responsibility
Fri, 01 Jun 2018 04:00:03 +0000
Although nuclear plant ice condensers are rare—only seven sites throughout the world have them—the theory behind these passive heat sinks is quite novel. In fact, some next-generation plant designers have built upon the concept and incorporated passive accident intervention schemes into their plans. A nuclear plant ice condenser is a passive, static heat sink that […]
Maintaining Nuclear Plant Ice Condensers: A ‘Cool’ Responsibility appeared first on POWER Magazine. Although nuclear plant ice condensers are rare—only seven sites throughout the world have them—the theory behind these passive heat sinks is quite novel. In fact, some next-generation plant designers have built upon the concept and incorporated passive accident intervention schemes into their plans.
A nuclear plant ice condenser is a passive, static heat sink that relies on large quantities of ice to mitigate severe accidents. Its origin dates back to patent #3,423,286 filed in February 1966. It was called a “pressure suppressing arrangement for use with a nuclear reactor,” and it allowed smaller containment structures and reduced material requirements. Of all the operating nuclear plants in the world, only Watts Bar 1 and 2, Sequoyah 1 and 2, Catawba 1 and 2, McGuire 1 and 2, D.C. Cook 1 and 2, Loviisa (Finland), and Ohi (Japan) rely on ice condenser systems.
This passive engineered safety feature (ESF) provides a static heat sink to rapidly absorb steam, reduce containment pressure and temperature, and remove fission products following a loss-of-coolant accident (LOCA) or main steam line break. The
Nuclear Regulatory Commission defines a LOCA as “those postulated accidents that result in a loss of reactor coolant at a rate in excess of the capability of the reactor makeup system from breaks in the reactor coolant pressure boundary, up to and including a break equivalent in size to the double-ended rupture of the largest pipe of the reactor coolant system.” Licensed nuclear plants must be capable of mitigating a LOCA and preventing offsite consequences.
POWER interviewed James Klein, maintenance FIN (fix-it-now) superintendent and ice condenser system subject matter expert at the Tennessee Valley Authority’s (TVA’s) Watts Bar nuclear plant located in southeastern Tennessee. The site has two Westinghouse four-loop, 1,150-MWe pressurized water reactors. Units 1 and 2 are licensed to operate until 2035 and 2055, respectively. (For more on the plant, see “ ” in the June 2015 issue of Watts Bar Unit 2: A ‘Deferred Nuclear Plant’ Gets Back into the Game POWER.) Klein discussed the major components of the ice condenser system, which are designed to manufacture ice and maintain a thermally controlled environment to keep the ice from melting. Three Compartments and LOCA Mitigation
The containment building is divided into three major compartments: a lower compartment consisting of the interior steel containment housing the reactor vessel and steam generators; the ice condenser compartment with one-way, hinged inlet (bottom) and outlet doors (top) that open upon slight pressure from the lower compartment and hinged vertically opening intermediate deck doors; and an upper compartment for displaced air from the other two compartments following a postulated LOCA. Return air fans maintain a forced circulation from the upper to lower compartments, equalizing containment pressure, and continuing to circulate heated air and steam through the ice condenser (Figure 1).
This cross-sectional view with parts removed to show different levels of the pressure suppressing arrangement (marked FIG. 2) and a vertical sectional view of one embodiment of the ice condenser concept (marked FIG. 1). The enlarged fragmentary view (marked FIG. 3) shows the lower right-hand portion of FIG. 1. These drawings show the ice (98) is sub-divided into discrete packets by means of annular trays (102). Vertical flow passages (118) are maintained on either side of the trays.
1. The ice condenser system. Source: U.S. Patent 3,423,286, January 21, 1969
The ice condenser annular compartment is an enclosed low-temperature, static heat sink formed by the containment wall and a crane wall. Circumferentially, it covers a 300-degree perimeter of the upper containment structure. A refueling canal and equipment hatch are located in the remaining 60-degree arc. An operating deck separates the reactor vessel and upper compartment, with a portion of the ice condenser compartment extending into the lower compartment so the steam and heated air following a LOCA is directed through the lower inlet doors below the ice condensers.
For example, the lower inlet doors (92.5 inches high, 42 inches wide, and 7.5 inches thick) are located in crane wall ports. They are closed during normal operation, and equipped with torque-tension spring mechanisms, shock absorbers, and instrumented to verify their position. Following a pressure increase from a LOCA in the lower compartment, the doors open and vent the released energy into 24 ice condenser bays containing an array of 48-foot-long, vertical cylindrical columns of 1,944 twelve-inch-diameter perforated/lattice-mesh baskets that form flow channels.
The baskets contain flake ice impregnated with sodium tetraborate to mitigate the neutron fission/chain reaction and remove radioiodine. To assure that the iodine remains in solution, the alkaline pH (9.0–9.5) of the combined condensate and ice melt promotes iodine hydrolysis to non-volatile forms. Complete steam condensation occurs as it contacts the ice because of the ice mass and ice column geometrical arrangements. The resulting pressure rise, due principally to the air mass in the ice condensers, open the top outlet doors allowing airflow to vent into the upper compartment.
Accident analysis indicates that ice meltout occurs after approximately one hour. Drains at the bottom of 20 of the 24 ice condenser compartments allow melt/condensate water to flow out. Being a passive system, there are no actuation circuits or equipment required for the ice condensers to operate following a LOCA, and it is a part of several ESFs, such as the containment spray systems for reducing pressure, air return fans—which promote air flow and prevent the buildup of hazardous gas concentrations including hydrogen—and residual heat removal systems that cool recirculated water.
The ice is produced as a continuous ribbon, approximately one-eighth inch thick from machines located in the Additional Equipment Building. The ice is then deposited in storage bins via gravity chutes, pushed by a mechanized rake to an ice chopper sizing the ice flakes to approximately 2 in. x 2 in. x 1/8 in. (Figure 2).
The flake ice is prepared and stored inside this massive bin. When initiated, the flake ice is blown into either the Unit 1 or Unit 2 condenser where it is weighed and loaded into baskets.
2. Ice prepared for ice baskets. Courtesy: TVA/Watts Bar Nuclear Plant
Change in ice basket weight determines how much ice has been lost, usually through sublimation, since the last outage. Although ice replacement is not a critical path item, approximately 2% to 4% of the ice is replenished every scheduled 18-month outage (Figures 3 and 4), thereby maintaining a technical specification (TS) requirement of 2,404,500 pounds of total ice weight per containment. Additional chillers were used to support the Watts Bar 2 startup.
Flake ice is being blown into one of the 1,944 baskets during preparations for Unit 2 operation.
3. Blowing ice into an ice basket. Courtesy: TVA/Watts Bar Nuclear Plant
An inside look at the Watts Bar Unit 1 ice condenser basket area reveals the design and conditions to which skilled technicians must safely perform work. There are 24 bays, which include 81 twelve-inch baskets.
4. Ice baskets. Courtesy: TVA/Watts Bar Nuclear Plant Refrigeration System
A three-stage refrigeration system—refrigerant loop, glycol loop, and air-cooling loop—cools the ice condensers and has defrost capability when needed. During normal operation, 30 air-handling units keep the ice beds at 15F to 20F. These conditions are maintained using a redundant, corrosion-inhibiting 50% glycol/water cooling system. Watts Bar has an average July temperature of 88F. Therefore, pipe coils are embedded in the ice condenser floors to minimize heat influx. Also, materials that could decompose and block water flow, such as solid insulation, is protected to prevent damage from LOCA blowdown effects.
insulation is sufficient to prevent ice melting for a minimum of seven days following a refrigeration system loss, allowing time for safe shutdown. Air-handling units located above the ice baskets provide cold forced-air through the ice systems. There are a number of sensors that monitor and provide feedback to the control room including indication for air temperature, ice condenser door position, glycol levels, glycol pump status, and glycol temperature (Figures 5 and 6).
Watts Bar Assistant Unit Operator Adam Kimble monitors and operates one of the many integral chiller components during Unit 2 flake ice production.
5. Assistant Unit Operator with chiller equipment. Courtesy: TVA/Watts Bar Nuclear Plant
Watts Bar’s Justin Mauer monitors the glycol chiller control panels during ice production inside the Additional Equipment Building.
6. Maintenance personnel at chiller controls. Courtesy: TVA/Watts Bar Nuclear Plant Routine Maintenance and Monitoring
An ice condenser systems engineer is responsible for the system. An operating engineering staff performs monitoring duties and a maintenance staff services the system. During full power operation, the upper compartment and ice condenser upper plenum areas are entered for ice bed and ice condenser inspection and maintenance, as required by the technical specification.
Routine ice condenser compartment checks verify that equipment performs within the prescribed limits. Items checked include:
Ice condenser doors are not impaired by ice, frost, or debris, and have no evidence of damage.
Air handling units, glycol circulation, and refrigeration equipment are functioning properly.
Air temperature surrounding the ice condenser baskets is within specification.
Quantity and quality of borated ice is correct.
Gated floor drains and drain lines are free of debris.
Gross inlet-outlet door bypass leakage paths between the upper and lower containments are not present.
Instrumentation failures or anomalies are monitored in the control room, where redundant ice condenser temperature monitors, door position monitors, coolant liquid level, and valve position indicators are displayed and alarmed. Ample time is available to investigate and eliminate off-normal conditions maintaining ice inventory and integrity.
Employee Safety and Training
Klein said that because of the cold environment in the ice bays and their location inside the containment,
pre-job safety and radiation worker permit briefings are conducted prior to entry. Workers use a “buddy system,” and they are required to wear additional gear, such as coveralls, jackets, and gloves, for personal protection and comfort. Chemical protection and safety data sheets for glycol are reviewed when working on the chiller system.
Although the location is considered a radiologically low-dose and clean (that is, contamination-free) area, which eliminates the need for respirators, the health physics department requires wearing dosimeters to monitor for employee radiation exposure and contamination surveys are routinely conducted.
Respecting radiological dose implications, these containment access entries are limited to Tuesdays for Unit 1 and Thursdays for Unit 2. Refrigeration technicians conduct walkdowns, and if deficiencies are discovered, they are allowed to begin corrective maintenance processes. Klein added that maintenance has been proactive in monitoring for adverse trends in air-handling units and chiller performance, and conducts repairs, as needed.
Klein said training mainly focuses on refrigeration fundamentals. However, the individuals that perform maintenance must also have proper access and radiation safety qualifications to work onsite. Refrigeration training topics prescribed by the American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE) cover the following:
Refrigeration and thermodynamics
Refrigeration system components
Types of refrigerants and their characteristics
Refrigeration system codes and standards
Ice condenser plants are unique among pressurized water reactors. This was the result of extensive development work during the early stages of the commercial nuclear industry as a part of a continuing effort to simplify nuclear plant designs, and reduce containment size and material usage, while improving safety using a passive system. This balance of proven technology and new concepts for accident intervention has been carried forward satisfying fundamental requirements demanded by the next generation of reactors.
— James M. Hylko ( JHylko1@msn.com) specializes in safety, quality, and emergency management issues and is a frequent contributor to POWER.
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Why the EPA’s Proposed Coal Ash Rule Is Concerning
Fri, 01 Jun 2018 00:00:00 +0000
Over the past decade, together with my students and colleagues at Duke University and other academic institutions, I have conducted scientific research and published 13 scientific articles on different aspects
Why the EPA’s Proposed Coal Ash Rule Is Concerning appeared first on POWER Magazine. Over the past decade, together with my students and colleagues at Duke University and other academic institutions, I have conducted scientific research and published 13 scientific articles on different aspects of coal ash’s environmental effects. While some of these studies have supported claims made by environmentalists that show evidence for coal ash pollution, others have vindicated power companies that own coal ash sites.
Overwhelmingly, however, these studies point to the need for more monitoring, strict standards, and more transparency of coal ash disposal issues. Based on my knowledge and experience as a scientist, the amendments to the 2015 final Coal Combustion Residuals (CCR) rule proposed in March 2018 by the Environmental Protection Agency (EPA) would considerably weaken the existing federal regulations. And perhaps worse, reducing environmental protection and safeguards that were established as part of the federal 2015 Coal Ash Rule would severely exacerbate the already identified environmental effects associated with coal ash storage and disposal. Below I outline the major issues that could result from the proposed EPA amendments.
Groundwater Contamination by Coal Ash Is Real
One important component of the 2015 Coal Ash Rule is that it requires comprehensive water quality monitoring of groundwater located in the vicinity of coal ash impoundments. However, the EPA has proposed modifying the required monitoring program, even though evidence points to the presence of contaminants in aquifers.
Our 2016 evaluation of seeps and surface water from seven sites and shallow groundwater from 15 sites in five states (Tennessee, Kentucky, Georgia, Virginia, and North Carolina) found that they were contaminated above background levels. Contamination levels above drinking water and ecological standards were observed in 10 out of 24 samples of impacted surface water. Out of 165 monitoring wells, 65 were contaminated. Distinct isotope fingerprints, combined with elevated levels of contaminants known to be enriched in coal ash, provide strong evidence for the leaking of all investigated coal ash ponds to adjacent surface water and shallow groundwater.
The results of this study are consistent with recent data published on the EPA website. A large water quality dataset of groundwater from sites near coal ash facilities that was released this March by owners and operators of CCR units, as required by the EPA’s 2015 final CCR Rule, also revealed large-scale water contamination of groundwater in the vicinity of coal ash impoundments and other storage and disposal facilities at numerous sites throughout the country. In particular, elevated levels of toxic and carcinogenic arsenic, chromium, molybdenum, lead, selenium, thallium, radium (radium-226 and radium-228), boron, fluoride, and sulfate were discovered in numerous groundwater wells near coal ash disposal sites. If finalized, the EPA’s proposed modifications could increase the risks for the further spread of contaminated groundwater and impact thousands of drinking water wells located downstream from these disposal sites.
Groundwater Quality Standards Should Not Be Modified
The 2015 Coal Ash Rule requires owners and operators of CCR units to conduct groundwater quality monitoring and other post-closure care activities—such as maintenance of the cover and leachate collection systems—for a period of 30 years after coal ash sites are closed. But the proposed amendments call for a much shorter period of post-closure care activities and groundwater quality monitoring. Yet, as the evidence makes clear, long-term monitoring and protection measures are critical for public protection.
Groundwater flow in aquifers is a long-term process, and the migration of contaminated groundwater from the CCR storage sites to pumping areas in aquifers could take decades. Because we have clear evidence that coal ash contaminants have already arrived in shallow groundwater underlying and downstream from coal ash storage facilities, shortening the monitoring period could paralyze detection of how far contaminated groundwater has migrated toward drinking water wells near coal ash impoundments and landfills.
Also concerning is a proposed amendment that suggests modifying the 2015 Coal Ash Rule to allow states to set different standards for some contaminants identified by coal ash site owners in their March groundwater monitoring datasets—including high levels of toxic elements such as lithium, cobalt, lead, and molybdenum. Another proposed amendment seeks to eliminate a 2015 Coal Ash Rule requirement that coal ash site owners post groundwater quality and air quality data on publicly available websites. Given that these contaminants are known to have direct human health effects, any reductions in the protection threshold or compromised data transparency could have negative effects on human health. People need to know what’s in nearby groundwater.
Compared to the 2015 Coal Ash Rule, which mandates that unlined coal ash ponds in areas where underlying groundwater was contaminated should install liners or be closed at a certain date, the EPA’s proposed amendments would allow state agencies or utilities themselves to make those decisions. However, avoiding actual closure or liner installation could further exacerbate the water quality situation in shallow groundwater underlying and downstream from CCR storage sites.
Another proposed amendment would meanwhile make contaminated groundwater cleanup discretionary. However, given the economic cost of such cleanup operations, many utility owners may be reluctant to conduct large-scale cleanup operations, which could result in continued contamination of the impacted aquifers, or allow contaminated groundwater to migrate farther toward drinking water wells. ■
— Avner Vengosh, PhD (firstname.lastname@example.org) is a professor of Geochemistry and Water Quality, Division of Earth and Ocean Sciences, at Duke University’s Nicholas School of the Environment.
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