Statement of Scott H.
Segal
Bracewell & Patterson,
L.L.P.
Before the Subcommittee on
Superfund, Toxics, Risk and Waste Management
Committee on Environment
and Public Works
United States Senate
Hearing on the Status of
the Enforcement Program of the U.S. EPA
March 12, 2002
Senator Boxer and Members of the
Subcommittee, thank you for this opportunity to testify regarding the current
state of EPA enforcement programs. My
name is Scott Segal, and I am a partner at the law firm of Bracewell &
Patterson. In that capacity, I have
represented clients here in Washington on environmental policy matters for
thirteen years. I have worked with a
wide variety of federal agencies, and have become familiar with a number of
industrial sectors. I have represented
private corporations, trade associations, and non-profit organizations. In addition, I serve on the adjunct faculty
of the University of Maryland (University College) in the area of Science and
Technology Management.
I represent many groups that have taken an
active interest in environmental enforcement matters. With respect to the current need to clarify the New Source Review
program, I specifically represent the Electric Reliability Coordinating Council,
a group of six electric utilities.
Further, I serve as outside counsel to the Council of Industrial Boiler
Owners, a trade association whose members represent some twenty industrial
sectors. While I have learned much from
these clients, the views I express today are my own.
1. Environmental Indicators Show Marked
Improvement: the Example of Clean Air.
In the United States today, we have much to
be proud of when we contemplate the success of environmental programs. It has often been observed that at the
outset of the current federal environmental programs in the early 1970's, our
problems were substantial and obvious.
It stands to reason that at that time, and for a period following, our
environmental enforcement priorities were also fairly obvious. In many ways, as milestones of environmental
achievement have been reached, our adversarial enforcement model has not caught
up.
It is clear that substantial environmental
progress has been made since the adoption of major control statutes. Using clean air progress as an example, we
can see measurable success. An analysis
of federal government data earlier this year demonstrates astounding
reductions. The analysis tracks air
quality gains and energy consumption during the 30‑year period from 1970‑1999.
It is derived solely from data produced by the U.S. Environmental Protection
Agency (EPA) and the Energy Information Administration (EIA) of the U.S.
Department of Energy.
The nationwide data show that since 1970:
_ Carbon monoxide (CO) levels have dropped 28
percent;
_ Sulfur dioxide (SO2) levels have decreased 39
percent;
_ Volatile organic compound (VOC) levels have
declined 42 percent;
_ Particulate matter (PM‑10) levels have
fallen 75 percent;
_ Airborne lead levels have declined 98
percent; and
_ Overall energy consumption has increased 41
percent ‑ by sectors, commercial energy consumption grew by 80 percent,
residential energy by 34 percent, and industrial energy consumption by 21
percent.[1]
Senator Boxer, these gains are evident even
in challenging air emission situations, such as your own State of California.
As Peter Venturi, a California State Air Resources Board official stated at a
recent EPA hearing in Sacramento, "The system is working," noting
that smog-forming emissions from businesses in the state have declined by 50%
in the past 20 years despite a 40% increase in population and commensurate
industry growth.[2]
The acid rain reductions, contained in Title
IV of the l990 CAAA, are of special importance because they in part serve as a
model for the Administration's recent Clear Skies Initiative and for
legislation pending before this Committee. Title IV has, by all accounts, been
highly successful. Gregg Easterbrook, a senior editor at the New Republic,
wrote last summer that the results have been "spectacular. Acid rain
levels fell sharply during the 90's, even as coal combustion (its main cause)
increased."[3]
Notwithstanding these successes, there remain
some difficult problems. Ozone levels, while improving, are still in violation
of the NAAQS in substantial sections of the country. I think it's important to
say here that while acid rain is primarily, though not exclusively, a power
plant problem, ozone is primarily a mobile source problem today. Cars, trucks
and buses account for twice the NOx produced by power plants, which in turn
have no role in VOCs, the other smog precursor. That mobile sources account for the greater portion of pollutants
of concern to human health is clear.
EPA itself has observed that, "in numerous cities across the
country, the personal automobile is the single greatest polluter, as emissions
from millions of vehicles on the road add up. Driving a private car is probably
a typical citizen's most 'polluting' daily activity."[4]
Much has
been written recently about the effects of small diameter particulate matter,
or PM. Thanks to a combination of the TSP and PMl0
NAAQS, the ozone standard and the acid rain program, the United States has engineered
a massive reduction of PMl0, which is now largely in attainment (achieving a
15% reduction from 1990 to 1999 and a 80% reduction from 1970). EPA has pending
a NAAQS to control PM2.5 which could, if implemented, call for further
reductions of power plant emissions, along with other pollutants. In the
meantime, existing EPA control programs are producing continuing reductions of
what EPA describes as the "gaseous precursors of fine particles (e.g.,
SO2, NOx and VOC), which are all components of the complex mixture of air
pollution that has most generally been associated with mortality and morbidity
effects" (PM2.5 emissions declined 17% from 1990-1999). In addition, it is far from clear that PM
levels should be viewed as a traditional enforcement issue; the President's own
proposal for a Clear Skies Initiative is another, undoubtedly more efficient
mechanism to incentivize and engineer further reductions in PM. And recent data has demonstrated that among
the most dangerous forms of PM are those arising from automobile exhaust B a source
controlled by the federal reformulated gasoline program, a program enforced
with a minimum of traditional adversarial enforcement actions.
2. Changing
Environmental Enforcement to Reflect New Realities.
In some respects, we are a victim of our own
success. As environmental indicators
are trending in a positive fashion, the decisions we make as a society become
more difficult in the area of allocation of resources. Environmental protection remains just as
important, but the tools we use must become more refined. Unfortunately, while many program officers
understand the need for changing priorities, enforcement officers often view
the world in a binary fashion with little room for subtlety.
There seems to be a bipartisan consensus that
such an approach makes little sense, and can even produce perverse
results. Then-Vice President Al Gore,
in his September 1994 report to President Clinton on the progress of
governmental reinvention activities, observed that, "EPA Administrator
Carol M. Browner, for instance, is reaching out to all parties with potential
roles to play. Environmental protection, she says, can no longer succeed as an
adversarial process, with the polluter on one side of the table and the
offended party on the other. Now, all parties must sit and work together."[5] Two years later, Vice President Gore
revealed the successes that could be achieved when pilot projects were adopted B sometimes over the objections of enforcement
officers B such as Project XL and the Common Sense
Initiative at EPA. He stated, "EPA
has found that when they let companies volunteer to cut pollution without the
government dictating how they had to do it, thousands of companies jumped at
the chance."[6]
What Vice President Gore and Administrator
Browner recognized from their efforts at governmental reform is what is evident
today: as the nature of environmental challenges has changed, so too must
antiquated notions of a purely adversarial approach to enforcement.
Two thoughtful legal observers have
articulated a rubric for judging effective environmental enforcement. To be effective, an enforcement regime must:
_ be clear in
what it mandates and prohibits;
_ be
predictable in how it punishes violations of the regulations, and rely where
possible on cooperative, problem-solving approaches; and,
_ seek environmental
improvement, not numerical enforcement targets.[7]
By the standards of this approach, it would
appear that the current approach to environmental enforcement is less than
optimal. One the first measure B clarity B the New Source Review program is an example presently of what NOT to
do. But it is hardly alone in a lack of
clarity. In fact, one widely-quoted
study has it that fewer than one third of the responding attorneys felt
that it was even possible to comply fully with federal environmental laws given
their current lack of clarity.[8]
Unfortunately, the mechanism used to address enforcement clarity often
is part of the problem: when EPA issues enforcement guidance documents that
have the effect of creating entirely new obligations without notice and comment
rulemaking, obligations become all the more confusing and less respectful of
proper process.[9]
The second observation, the need for
predictability, is also missing in many of today's enforcement activities. Again, the NSR program is an excellent
example of the problems faced by the regulated community. As we further discuss in the White Paper
attached to this Statement as Appendix One, EPA's NSR rules, which for thirty
years have been consistently applied only to new greenfield sources or major
modifications of existing sources, are now being reinterpreted without any
rulemaking change and applied to routine repair, replacement and maintenance
activities at all existing sources, causing major disruption in routine
maintenance schedules, curtailing power output, and dismembering whole Titles
of the Clean Air Act.
The rationale for the radical shift in
interpretation is in the allegation that utilities are by illicit maintenance
keeping afloat old plants that were "grandfathered" from any CAA
controls and that are now threatening the nation's health. But the 1990 CAA
Amendments mandated sweeping reductions for all power plants regardless of age
through the use of highly efficient market incentives. The 1990 Act thus
established a flexible market-based system that is working very efficiently to
drive down pollution through 2010 and beyond, but that is now being repealed by
administrative fiat and replaced by an outmoded, inefficient and
counterproductive command and control regime.
And the clear truth is that many of the
targets of the current NSR enforcement initiative are functionally related to
routine maintenance, repair and replacement.
They cannot usefully be characterized as major modifications or boiler
or powerplant expansions. Appendix Two
delves into the exact nature of the activities at issue here.
The last component of effective enforcement B a desire to embrace outcomes over mere
numbers of cases B is
again often missing in today's approach to enforcement. Of course, current enforcement efforts are
not without their traditional numerical successes. Indeed, EPA released data on its enforcement and compliance
assurance results earlier this year, which included "record-setting
amounts of money violators have committed to environmental cleanups and
restoration, and for projects to protect the environment and human health
beyond injunctive relief, and to record penalty assessments."[10]
Despite this numerical success, Administrator
Whitman has recognized that such numbers are not the sole relevant benchmark
. "With our state and local
partners, we set a high priority on areas that posed serious threats to health
and the environment," said EPA Administrator Christie Whitman. "The
Administration is determined to actively pursue those who fail to comply with
the law while working closely with the regulated community to find workable and
flexible solutions."[11] Clearly then, there is growing recognition
that it is important to prioritize enforcement; to target areas of greater
environmental reduction; and to work cooperatively towards solutions.
Perhaps it is Administrator Whitman's
experience as a Governor that has led her to this conclusion. We should remind ourselves that the number
of federal enforcement actions are not the sole indicators of success. In fact, two years ago, the U.S. Congress
commissioned the Environmental Commission of the States to examine relevant
differences and interrelationships between federal and state enforcement actions. ECOS reported that in one year alone, States
passed over 700 environmental statutes for which there were no federal
counterparts. However, federal
statistics collected by EPA do not count enforcement efforts undertaken by the
States in reference to these actions.[12] Indeed, of the universe of all enforcement
actions undertaken by both the States and EPA, States alone conducted about 90
percent.[13] However, the great majority of these actions
are undertaken in a spirit of cooperation and compliance assurance. ECOS concluded:
"Many State environmental leaders do not
believe that their primary goal is just to conduct enforcement actions. It is more important to assure compliance,
and more important still to improve environmental quality and public
health. For this reason, States have
been leaders in developing 'compliance assistance' programs."[14]
But, in any event, it is curious and
misplaced criticism to look at elements such as numbers of cases and workyears
of budget allocation as reflective of actual realities. If it is to succeed in moving the needle
towards additional compliance, enforcement programs must be less adversarial
and of greater real assistance. As one
State regulator put it, "the true measure of successful enforcement is in
quantifiable improvement in our environment. Improved natural resources, not
fines, must be the primary objective of any effective environmental
policy." She concluded:
"Allowing states to establish, develop, and implement environmental
improvement policies is critical to their autonomy and the health of the
environment. Heavy fines simply encourage litigation and slow environmental
progress."[15]
3. The
Price of Failure: the Case of NSR Clarification.
EPA's reinterpretation is not only flawed as
a matter of law, but it also undermines our energy supply, environmental
protection and workplace safety. Because NSR is a costly and time-consuming
process, EPA's current position discourages utilities from undertaking needed
maintenance projects. This makes plants more reliant on deteriorating
components, resulting in less efficient, less reliable and higher emitting
power generation. For example, the efficiency of currently available steam
boiler equipment deceases over time as plant components deteriorate. Boiler
tubes, in particular, are subject to very harsh temperature, pressure, and
chemical conditions, and leaks result. Short-term fixes include patching tubes
where there are leaks, but eventually whole sections begin to wear out and must
be replaced if the plant is to continue to operate. Yet EPA's reinterpretation
of NSR could have such a routine and necessary activity declared non-routine.
There are 300,000 megawatts of coal-fired
generating capacity which is 55% of all electricity generated in the United
States. Approximately 1,200 coal-fired generating units are in service. These
generating units involve two distinct sets of operations: (1) a steam cycle
(e.g., the boiler and related equipment), and (2) the turbine cycle (where the
electricity is generated). In the past few years, there have been some very
exciting innovations in the turbine technology area. For example, just one type
of efficiency improvement project, the so-called Dense-Pack which enhances the
efficiency of turbine blades, can result in a very significant improvement in
the efficiency with which steam is turned into electricity.
A more efficient turbine results in more
electricity output from the same steam input, with no greater fuel use. For
example if one assumes that most generating units could improve efficiency by
between 2% and 4% (a very conservative estimate, based upon the actual
operating experience of several units which have installed the Dense-Pack
technology), this would mean an additional output of 6,000-12,000 megawatts of
power in the near term, with significant decreases in emissions
per unit of fuel burned. This increase in available installed capacity is the
equivalent of building 20-40 new plants of 300 megawatts each with no new
emissions. We should recall that the
very definition of pollution is inefficiency; getting more electrons out of
less coal is the best way to prevent pollution.
Last, we should be clear that many of our
colleagues in organized labor support the notion that the NSR program should be
clarified in order to allow for sufficient routine maintenance activities. The greater the incentive for maintenance,
the safer our work environment will be.
Attached for the Subcommittee's review as Appendix Three is a statement
offered by the International Brotherhood of Boilermakers at EPA's regional
conference on NSR held last summer.
APPENDIX ONE: ELECTRIC RELIABILITY
COORDINATING COUNCIL
WHITE PAPER ON CLARIFICATION OF NEW SOURCE
REVIEW
SUMMARY
EPA's NSR ("New Source Review")
rules, which for thirty years have been consistently applied only to new
greenfield sources or major modifications of existing sources, are now being
reinterpreted without any rulemaking change and applied to routine repair,
replacement and maintenance activities at all existing sources, causing major
disruption in routine maintenance schedules, curtailing power output, and
dismembering whole Titles of the Clean Air Act. The rationale for the radical
shift in interpretation is in the allegation that utilities are by illicit
maintenance keeping afloat old plants that were "grandfathered" from
any CAA controls and that are now threatening the nation's health. But the 1990
CAA Amendments mandated sweeping reductions for all power plants regardless of
age through the use of highly efficient market incentives. The 1990 Act thus
established a flexible market-based system that is working very efficiently to
drive down pollution through 2010 and beyond, but that is now being repealed by
administrative fiat and replaced by an outmoded, inefficient and
counterproductive command and control regime.
I. How did we get here?
·A The
CAA, which has produced dramatic reductions in air pollution over the last
three decades despite explosive economic growth, operates through two
approaches. The first approach develops national health and environmental
standards for the states to apply to the existing sources in their
jurisdictions. DOE reports that the utility industry alone has spent more than
$30 billion to achieve compliance with these health standards.
·A The
second approach applies the best current technology to new sources and major
modifications of old sources that increase pollution levels where inclusion of
such technology can be integrated in an efficient manner without highly
disruptive retrofitting. The purpose is to prevent new pollution by new plants,
both to preserve air quality in areas that attain health standards, and to
avoid complicating ongoing plans to clean up existing plant and equipment in
areas that do not.
·A
Because of delays and regulatory difficulties primarily associated with ozone
attainment and a need to address acid rain not previously regulated, the
Congress enacted the 1990 CAA Amendments ("1990 CAAA") to impose a
sweeping array of new pollution reductions on power plants (and other pollution
sources as well). These new programs included the acid rain program of Title
IV, which mandates a 50% reduction in SO2 by 2010, and the interstate transport
provisions of Title I, which are now being implemented to impose additional NOx
controls in Midwestern power plants that may themselves be located in
attainment areas, but that send pollution through tall smoke stacks to the
neighboring states.
·A These
new programs adopt a different -- and highly successful -- approach that
assigns and limits the absolute number of tons a plant can emit, leaving to the
plant the decision as to how to reduce its tons, rather than assign a
particular technology to the plant which it must build. Because the preexisting
NSR program is technology-based, rather than ton-based, EPA issued a rulemaking
in 1992 to reconcile the old with the new, as described more fully below. It is
this 1990 CAAA and 1992 rulemaking which EPA is now blatantly violating -- by,
for example, forcing utilities to accelerate reductions much faster than those
mandated by Title IV of the 1990 CAAA.
·A As
indicated above, NSR was intended primarily to apply to new sources and can
also apply to existing plants only when a large industrial source of air
emissions, a refinery or a power plant makes a non-routine physical or
operational change that results in or causes an emissions increase.
·A Over
the last thirty years, EPA's regulations and practice have excluded from NSR
all "routine maintenance, repair and replacement" activities
undertaken by power plants and other industries. Additionally, EPA surveyed
utility maintenance projects, including "life extension projects," in
the early 1990s and concluded that those did not trigger NSR. EPA also has
published guidance in the Federal Register defining what was routine by
reference to the standard practices of the relevant source category, in this
case the utility industry. Likewise, EPA's regulations specifically exclude any
increases in emissions associated with operating a facility more hours, unless
such an increase is prohibited by a federally enforceable permit condition.
·A EPA's
practices interpreting the NSR rule were explicitly described to Congress by
then-EPA Administrator Reilly and other Agency officials when Congress was
considering the Clean Air Act Amendments of 1990. One of the reasons Congress
adopted the Acid Rain provisions of Title IV to reduce SO2 by 50% (10 million
tons) was because utility units typically operate for 65 years or longer
without major modification and the NSR program would not obtain equivalent
reductions. To help facilitate cost-effective compliance by the utility
industry with both the ton-based 1990 CAAA and the pre-existing
technology-based NSR program, EPA, after an extensive notice and comment
process in 1992, promulgated a rule which explicitly laid out all of the NSR
procedures applicable to the utility industry and confirmed that
"pollution control" projects would not trigger NSR.
·A In
1996, EPA initiated a rulemaking to revise the 1992 NSR rule, but never
finished it. Instead, in 1999, EPA commenced a major enforcement initiative
against virtually every coal-fired utility plant in the country for repair and
replacement activities undertaken over the past 20 years. Under EPA's
reinterpretation, virtually every maintenance, repair or replacement project
undertaken by any utility plant could be considered non-routine. Any project
that increases availability or efficiency or corrects problems causing forced
shutdown of plants potentially triggers NSR. EPA abandoned its simple test for
determining when maintenance practices are routine -- common industry practices
-- and now applies a multi-factor (more than 20 different factors) weighing and
balance test that only it can perform with any sort of regulatory certainty.
Amazingly, even installation of pollution control equipment by utilities may now
be viewed as an NSR-triggering event.
·A
Whatever policy merits EPA believes justify its new position on NSR
applicability, EPA's efforts to achieve this through enforcement actions
against utilities for projects undertaken decades ago is inconsistent with
current law. If EPA believes this NSR reinterpretation is correct, it should
only apply it after notice and comment rulemaking or ask Congress for new
legislation to revise the 1990 CAAA.
·A In
justifying its enforcement actions, EPA claims that its sole goal is to avoid
emission increases by power plants operating more hours than in the past. This
point is so important that a more detailed explanation is in order. Under the
Clean Air Act provisions, every power plant in the country is allowed to emit a
certain quantity of various regulated pollutants, of which NOx and SOx are the
two key ones. Each utility plant has a legally mandated emission rate -- a
maximum amount of pollution that can be emitted per hour, per day, per month,
or even annually, depending upon air quality and other consideration. But, any
time a plant slows down because of a maintenance problem, it will necessarily
be able, once repaired, to operate more hours -- and emit more -- than it did during
the problem period -- even the emissions are well within the limits spelled out
in the State SIP and the federal reductions required by Title IV. These various
limits are spelled out in permits held by utility plants or in state
implementation plans, and they reflect EPA-prescribed public health-driven
ambient standards. These limits cannot be breached by power plants under any
circumstances, and there is no claim that any of the plants subject to the EPA
enforcement did exceed the permitted limit of emissions. However, every unit
must be prepared to operate more hours within their tonnage limits in order to
meet customer demand.
·A EPA's
definition of an emission increase is artificial and arbitrary. Power plants
operate under extremely harsh conditions; every several years, as the plant
equipment deteriorates, the plant's efficiency, availability and reliability go
down. Eventually, the plant operator performs a set of routine maintenance
procedures to restore and maintain the plant's efficiency, availability and
reliability. To emphasize, throughout all of these changes, the plant never
increases or exceeds its legally binding and public health-driven emission
limits. EPA, however, compares a plant's actual emissions at the time it was
operating in the recent past before a maintenance procedure with its future
potential emissions following that procedure, assuming that the plant will, as
a result of the project, operate every hour of every day in the year at maximum
output. In other words, EPA's methods always predicts an emission increase even
though none may occur, and even though the plant may not under any
circumstances exceed the CAAA's mandated reductions.
II. EPA's Reinterpretation Discourages Needed
Maintenance Procedures and Reduces Generating Capacity
·A EPA's
reinterpretation is not only flawed as a matter of law, but it also undermines
our energy supply. Because NSR is a costly and time-consuming process, EPA's
current position discourages utilities from undertaking needed maintenance
projects. This makes plants more reliant on deteriorating components, resulting
in less efficient, less reliable and higher emitting power generation. For
example, the efficiency of currently available steam boiler equipment deceases
over time as plant components deteriorate. Boiler tubes, in particular, are
subject to very harsh temperature, pressure, and chemical conditions, and leaks
result. Short-term fixes include patching tubes where there are leaks, but
eventually whole sections begin to wear out and must be replaced if the plant
is to continue to operate. Yet EPA's reinterpretation of NSR could have such a routine
and necessary activity declared non-routine.
·A A
plant operator typically will accept some level of deterioration in efficiency
for a short period of time but must eventually undertake the repair and
maintenance necessary to regain lost efficiency and to maintain unit
availability. The timing of these projects depends in part on the demands being
placed on the power plant to operate to meet energy supply needs. Unit
unavailability can seriously impair a utility's ability to meet customer demand
and nearly always results in running less efficient units. Operating
inefficient units increase the amount of pollution emitted. Under the EPA
Office of Enforcement and Compliance Assurance's new interpretation of the NSR
rules, it is these projects, designed to maintain efficiency and availability,
that are no longer regarded as "routine." EPA then assumes the unit
will operate more hours than before the project and further assumes that the
project, rather than customer demand, weather, or other unit outages, causes
this increase. Once EPA thus determines that NSR will be triggered, the unit
cannot even begin to proceed with the project without either going through the
lengthy NSR permitting process, which takes a year or more, or without
"capping" operations at historical levels. Thus, the unit must either
wait or derate. Either alternative can have significant adverse consequences
for the reliability of the country's electric supply. Waiting can idle a unit
during peak demand for 12-24 months, more if intervenors challenge the
permitting. Derating effectively confiscates capacity, even when the unit is
permitted to operate at maximum output year-round.
·A Over
the next 3-5 years, thousands of megawatts of existing generating capacity will
be lost if companies are not able to undertake these routine maintenance and
repair projects, or if companies must accept caps on utilization to avoid
lengthy NSR. In the longer term, EPA's new position would involve the loss of
an even greater number of megawatts. The result of EPA's reinterpretation will
be the decrease in available installed power plant capacity at a time when we
already have a supply shortage -- something this nation, and the West in
particular, can ill afford.
III. EPA's Reinterpretation Discourages
Efficiency Improvements
·A There
are 300,000 megawatts of coal-fired generating capacity which is 55% of all
electricity generated in the United States. Approximately 1,200 coal-fired
generating units are in service. These generating units involve two distinct
sets of operations: (1) a steam cycle (e.g., the boiler and related equipment),
and (2) the turbine cycle (where the electricity is generated). In the past few
years, there have been some very exciting innovations in the turbine technology
area. For example, just one type of efficiency improvement project, the
so-called Dense-Pack which enhances the efficiency of turbine blades, can
result in a very significant improvement in the efficiency with which steam is
turned into electricity.
·A A more
efficient turbine results in more electricity output from the same steam input,
with no greater fuel use. For example if one assumes that most generating units
could improve efficiency by between 2% and 4% (a very conservative estimate,
based upon the actual operating experience of several units which have
installed the Dense-Pack technology), this would mean an additional output of
6,000-12,000 megawatts of power in the near term, with significant decreases in
emissions per unit of fuel burned. This increase in available installed
capacity is the equivalent of building 20-40 new plants of 300 megawatts each
with no new emissions.
·A As an
example, this type of efficiency improvement, if installed by the approximately
1,000 utility units (out of some 1,200 existing coal-fired utility plants) that
can be most easily retrofitted with Dense-Pack technology, would reduce
criteria pollutants that NSR was meant to address (NOx and SOx) substantially.
·A
However, under EPA's reinterpretation of its NSR rules, the installation of
even this type of beneficial technology requires an elaborate, expensive and
time-consuming permitting process, which results in the imposition of
additional costly control technology requirements on existing plants, and
therefore discourages the installation of new and more efficient technologies.
IV. Conclusion
Overall, the effect of EPA's recent position
is to block routine maintenance, repair and efficiency improvement projects
that could immediately expand generating capability without increasing fuel
burning and will decrease by a significant percentage the total available
installed capacity through caps on operations. Stated differently, EPA's
reinterpretation of NSR is tantamount to shutting down dozens of utility units
every year at a time when electricity supply is already so short as to be
unreliable in many areas.
APPENDIX TWO: THE TRUE NATURE OF REPAIR AND
REPLACEMENT
This document provides more detail on major
repair and replacement projects that must be undertaken at utility generating
stations, in order to keep those facilities operational. The utility industry
generally plans for a major outage at each generating unit at a regular
interval, which has changed over time. During the 1970s and earlier, annual
outages were the norm, and each unit would be removed from service for several
weeks at a time to undertake a comprehensive boiler inspection and repair
outage. Currently such outages occur on schedules ranging from 18 months to
three years, and they therefore last longer. Turbine overhauls are planned on
longer intervals, approximately every five to eight years, and generally last
even longer due to the nature of the work required. In the years when turbine
overhauls are scheduled, more extensive boiler work can also be scheduled to
occur.
During each major outage, work will be
conducted on one or more of the projects discussed below. For each, this
document provides examples of the types of major repair and replacement
projects that are conducted in the industry, a discussion of the consequences
of not undertaking the project, and information on typical project costs. There
are many smaller repair and replacement projects that take place in each of
these projects that are not discussed here, given our focus on major repair and
replacement projects that are common in the utility industry. These smaller
projects will typically be performed during forced outages as time permits,
during shorter scheduled outages on weekends, or during the planned outages
scheduled for the more significant projects discussed in this paper. These
smaller projects add to the overall capital costs incurred for repair and
replacement projects at an individual unit over time.
1. Boiler Tube Assemblies
a. Project Description
Boiler tube assemblies include superheaters,
reheaters, economizers and boiler walls and floors. These tube assemblies may
also be known as division walls, wing walls, waterwalls or steam generation
tubes. Boiler walls consist of rows of tubes mounted along (and essentially
forming) the interior walls of a boiler. Superheaters, economizers and
reheaters are typically bundles of tubes which hang from the ceiling or sides
of a furnace into the hot combustion gasses. The heat in the furnace is thereby
transferred to the water or steam passing within each tube.
Boiler tubes function in extreme conditions.
These tubes are not exotic alloys and therefore are expected to experience wear
and periodic failure. Corrosion and erosion, in addition to temperature and
pressure-related stresses, wear or weaken the tubes. When boiler tubes leak,
those tubes, and typically surrounding tubes, must be repaired or replaced. If
deterioration is limited to a few tubes, repairs can be effected by cutting out
the leaking section of tubes and welding in place a new tube section. More
extensive deterioration, including deterioration anticipated based on the
results of nondestructive analysis of the boiler walls, requires replacing an
entire tube assembly. When materials that can better withstand the destructive
environment of the boiler and can reduce the susceptibility of the tubes to
wear are available, it is common practice to use those materials to the extent
it is cost-effective. Similarly, improvements in tube arrangement in the boiler
are common as the individual air/gas flow patterns of a boiler are established.
Finally, the headers that collect the water or steam and feed it into the tube
assemblies and the structural components associated with the tube assemblies
are also subject to deterioration due to the same failure mechanisms.
b. Consequences of Forgoing Project
Once a tube develops a leak, the unit can
only operate for a few hours to a couple of days, depending on where the leak
is in the boiler and whether the leak endangers the integrity of other tubes or
components. After that short time, the unit must be shut down in order to
repair or to replace the leaking tubes, because tube repairs must be conducted
off-line after the boiler has cooled. Replacement of an entire tube assembly
becomes necessary as anticipated or projected failures increase. Forgoing
replacement severely jeopardizes the reliability of the unit by requiring that
it be repeatedly shut down in response to tube leaks. Ultimately, tube leaks
can require that the plant be shut down. Foregoing replacement also jeopardizes
the integrity of other tubes and components, creating a risk of massive boiler
failure that would endanger employees and prevent the boiler from being
operated to supply electricity.
c. Other Information
Repair of leaking sections and wholesale
replacement of tube assemblies are common projects. Replacing tube assemblies
can cost up to $40/kw on a large coal-fired boiler, and even more on a smaller
boiler. A census of repair and replacement practices at coal-fired utility
boilers shows that entire tube assemblies have been replaced by almost every
boiler in the industry, with some replacements occurring as early as 5 years after
commercial operation.
2. Air Heaters
a. Project Description
Electric steam generating plants use air
heaters to pre-heat the combustion air to improve the combustion process and
the overall efficiency of the unit. Generally, air heaters receive hot flue gas
passing through the economizer and cooler combustion air from the forced draft
fan. Air heaters transfer the heat from the hot flue gas to the cooler
combustion air. Regenerative air heaters perform this heat transfer through the
use of air heater tubes or baskets (which are comprised of rows of metal plates
with corrugations and undulations designed to facilitate flow paths and heat
transfer).
Condensation and the presence of ash can
corrode, erode or plug air heater baskets or tubes. While washing and
sootblowing (see project family #10) may address short-term plugging issues,
corrosion of the metal surfaces and the resulting losses in heat transfer
require the replacement of air heater baskets or tubes at a frequency ranging
from 5 to 15 years.
Air heaters also suffer from the erosive
effects of ash and other materials, especially if gaps in air heater seals are
worn or weakened. This may lead to the replacement not only of air heater tubes
and basket layers, but also of structural elements, seals and gaskets. When air
heater tubes or basket layers and associated equipment are replaced, it is
standard practice to consider improvements in plate configuration, in materials
or in the corrugation or undulation of the plates, or in the arrangement of
tubes to account for the specific requirements of a particular boiler.
b. Consequences of Forgoing Project
If air heater tubes, baskets and other air
heater equipment are not replaced when they deteriorate, the plant loses
efficiency because the incoming combustion air is not warmed sufficiently. As
the air heater becomes further plugged or corroded, the unit is further limited
in its capability to generate electricity because less air and exhaust gases
can pass through the air heater. As the efficiency of the unit decreases, the
amount of emissions per unit of electricity generated increases. If most or all
of the air heater is plugged, no air can flow through, and the unit cannot
operate. Ultimately, if not replaced, pieces of the air heater that have been eaten
away could be sucked into the boiler, causing damage and forcing the boiler to
shut down.
c. Other Information
The replacement of air heater basket layers,
tubes and the seals around the air heater are common projects. Replacing tubes
and basket layers can cost up to $6/kw on a large coal-fired boiler. As with
other components, costs in $/kw tend to be higher on smaller boilers. A census
of repair and replacement practices at coal-fired utility boilers shows air
heater baskets/tubes have been replaced by over 80% of the units surveyed.
3. Fans
a. Project Description
A fan consists of a bladed rotor, or impeller
and a housing to collect and direct air or gas. Many boilers operate with both
forced and induced draft fans - also known as "balanced draft." These
boilers use the forced draft fan to push air through the combustion air supply
system into the furnace. The induced draft fan is on the other end of the
furnace, and sucks combustion gases through. In this way, the two fans maintain
the pressure of the boiler in "balance" or at atmospheric pressure or
slightly negative pressure.
Other boilers were designed to operate at
positive pressure, using only a forced draft fan and no induced draft fan.
However, this design forces heat and ash through the joints of the boiler and
ducting system, resulting in employee health, safety and other concerns
stemming from the dusty environment. These include increased equipment
maintenance needs due to the high dust levels. Accordingly, many companies with
positive pressure boilers have replaced the forced draft fan system with a
balanced draft fan system to correct these maintenance and employee safety
problems.
Another kind of fan necessary to pulverized
coal-fired boiler operation is a primary air fan. Primary air fans supply coal
pulverizers with the air needed to dry the coal and transport it to the boiler.
Primary air fans may be located before the air heater (cold primary air system)
or downstream of the air heater (hot primary air system).
In some cases, gas recirculation fans are
used for controlling steam temperature, furnace heat absorption and slagging of
heating surfaces. They are generally located at the economizer outlet to
extract gas and re-inject it into the furnace.
Fans rotate at high speeds, and experience
erosion and cyclic fatigue. They therefore need to be replaced periodically.
Fans (e.g., induced draft fans) may also be subject to high temperatures,
erosive ash, and corrosive gases.
b. Consequences of Forgoing Project
Poor fan operation translates immediately and
directly to reduced boiler load and less production of electricity. If a large
fan fails, it can shut down the unit. Failure of small fans in a multiple
system will result in reduced boiler load. Fan systems that fail or that cause
maintenance and employee safety problems must be replaced for the boiler to
continue to operate.
c. Other Information
Common replacement projects include balancing
and blade replacements, and wheel, motor and rotor replacement. Fan replacement
projects can cost up to $20/kw. Replacement of a forced draft fan system with a
balanced draft fan system can cost up to $70/kw. A census of repair and
replacement practices at coal-fired utility boilers shows that fans have been
substantially replaced at more than 70% of the units in the industry.
4. Mills/Feeders
a. Project Description
Feeders deliver raw coal from the coal bunker
to the pulverizer (also called "mills"). Coal crushers and
conditioners are used in some cases to prepare the coal for the mills. Coal
pulverizers then grind coal to a fine powder, suitable for efficient combustion
in the furnace.
Various types of feeders are used in the
industry, including gravimetric feeders, volumetric feeders, and bucket-type
feeders. Replacing volumetric feeders with technologically superior gravimetric
feeders is common in the industry, in order to improve the consistent
measurement of coal added to the mills.
Pulverizers are manufactured in several
designs. Some pulverizers use metal balls that roll around a metal track and
crush coal. Other pulverizers use rollers to crush the coal. Both designs
contain motors and gear boxes to drive the grinding mechanism. Pressurized air
created by seals and air fans keeps the fine coal dust out of the motor and
gears. Nevertheless, fine coal dust is present and causes continual wear and
eventual failure of mills.
The coal is sorted within the pulverizer and
delivered to the burners by the primary air fan. In some designs, exhauster
fans then deliver the pulverized coal through pipes to the burners for
introduction into the furnace. The "classifier," located at the top
of the pulverizer, contains openings through which fine coal passes on its way
to the burners; coarser particles hit the classifier and fall back to the
grinding mechanism.
The major causes of wear and deterioration in
pulverizer systems are abrasion due to exposure to hard minerals such as quartz
and pyrite found in raw coal, and erosion due to the stream of solids that
strikes pulverizer surfaces. Given the constant wear experienced in a
pulverizer, repair and replacement of pulverizers and related equipment is
essential to continued operation of the boiler.
The components that experience direct,
constant wear and that require periodic replacement include rollers, tables,
and balls; classifiers; bearings in rollers and the shaft; and seals and
motors. Within the feeder system, belts, flow control devices, and associated
piping must periodically be repaired or replaced. Eventually, abrasion and
erosion of the pulverizer may become so severe that the pulverizer or mill
internals must be replaced.
b. Consequences of Forgoing Project
The obvious consequence of mill/feeder
failure is the reduction of the capability of the mill to deliver coal to the
boiler, and hence of the unit to generate electricity. As less fuel is
available to the boiler, less steam can be produced. More subtly, improper mill
performance leads to combustion problems that not only damage other equipment
but that increase emissions. For example, coal which remains too coarse will
not combust completely, and will cause a loss of efficiency and an increase in
particulate emissions. Some equipment in a mill or feeder cannot be repaired
effectively more than a few times because the mill parts then will not work
together properly. Replacement of the mill is then necessary.
c. Other Information
Replacing wear parts in the interior of the
mill can cost up to $2/kw, and replacement of a mill can cost up to $5/kw. A
census of repair and replacement practices at coal-fired utility boilers shows
that pulverizer mills have been replaced or substantially replaced (e.g., the
entire grinding zone) at more than 50% of the units in the industry.
5. Turbines and Generators
a. Project Description
In the steam turbine at a modern power plant,
superheated steam from the boiler is exhausted over turbine blades (these look
like the fanjet blades in a jet engine). Because the steam is very hot (about
1000E°F), enters at very high pressure (2400 to
3600 pounds per square inch), and contains impurities, turbine blades
experience substantial wear and tear. For example, there are impurities in the
steam - like little pieces of sand - hit the turbine blades at extremely high
velocities and damage the blades by pitting them. When turbines are inspected,
some blades or rows of blades (e.g., the "high pressure" or HP
section) may need to be replaced.
When blades are replaced, the manufacturer
typically offers a new, more efficient design or better alloys as the result of
R&D or new, more durable materials. Indeed, the older, less efficient
design may no longer be available. Use of more efficient turbine blades also
allows the turbine to use a smaller amount of steam to produce the same amount
of electricity, thereby decreasing emissions per megawatt of power output.
Other turbine components, including nozzles, diaphragms and rotors, are also
commonly replaced when they deteriorate or fail.
Generator rotors and stators are also subject
to failure. The generator rotor turns (is rotated) inside the stator. Both the
stator and the rotor are typically made of steel and have "slots"
that run their length. Both the rotor and the stator have windings, that is,
wires that fit into the slots. A direct current is applied to the rotor
winding, which turns this large piece of steel into an electromagnet. The
stator winding is a conductor (typically copper). When an electromagnet is
turned relative to a conductor, it produces a current in the conductor. The
current produced in the stator winding is the electricity made by the
generator, which is then sent to the transmission grid.
The windings are surrounded by insulation.
This insulation can wear out due to heat, electrical and/or vibratory stress
(e.g., rubbing on adjacent insulation.) Also, insulation can deteriorate due to
exposure to contaminants such as moisture and oil, particularly from the
cooling mechanism. If the wear is extensive, the entire winding itself must be
replaced.
Finally, the steam turbine shell may develop
defects due to stresses created by high temperatures and high pressures. If the
turbine shell develops defects, it is commonly repaired or replaced at the same
time the turbine blades are replaced.
b. Consequences of Forgoing Project
Replacement of damaged turbine blades is a
necessity both from a reliability and from a safety standpoint. Damaged,
rotating turbine blades can break off and fly through the turbine casing at
extremely high velocity, creating the risk of serious injury or death and
extensive damage to the power plant. To avert this catastrophe, turbine blades
are inspected and replaced if wear and tear indicates they may fail.
Besides the employee safety issue, a broken
blade can damage other portions of the generating unit, resulting in prolonged
unit shut-down. Even prior to failure, deteriorated blades reduce the
efficiency with which steam is turned into electricity, thereby reducing the
electric output of a generating station and increasing the amount of emissions
per unit of electricity produced.
Worn windings and insulation in the generator
stator and rotor decreases the efficiency of the generator to convert
mechanical energy to electrical power. This translates to increased fuel
consumption and increased emissions per unit of electricity and decreases the
capacity of the unit to produce electricity. Failed insulation also presents a
fire hazard, and can result in faults that prevent the generator from operating
at all.
c. Other Information
Common projects include the replacement of
turbine blade rows or sections and turbine rotors. Moreover, a generator rotor
or stator is rewound periodically in the life of a unit. Turbine blade and
turbine rotor replacement projects can cost up to $20/kw, while shell
replacements can cost up to $60/kw. A census of repair and replacement
practices at coal-fired utility boilers shows that more than 90% of the units
in the industry have replaced turbine blades or rotors.
6. Condensers
a. Project Description
Once steam has passed through the turbine, it
is condensed back to water, which is cleaned, pumped again to high pressure and
returned to the boiler. The condenser provides the heat transfer necessary to
convert the spent steam into water.
The condenser consists of a large chamber
containing bundles of long, thin tubes. The tubes contain flowing water
(typically river water or some other source of cooling water). Low temperature
steam exiting the turbine at pressure approaching a perfect vacuum is directed
into the chamber across the outside of the bundles of tubes, which are arranged
perpendicular to the steam path. As the steam flows over the outside of the
tubes, the heat from the steam is transferred to the cooling water inside the
tubes. As enough heat is removed from the steam, the steam condenses to water.
The combination of steam constantly passing
across the outside of the condenser tubes and water (filtered, but typically
untreated) passing through the inside of the tubes leads to corrosion and
erosion. Also, the interior of the tubes is subject to plugging and biological
fouling. Despite constant efforts to clean the tubes, tubes eventually become
partially or entirely plugged and no longer provide heat transfer. Also, if a
condenser tube leaks, untreated river water will enter the steam path due to
the vacuum on the steam side and will contaminate the high purity steam.
Short-term repairs include intentionally
plugging a leaking tube. When numerous tubes have become plugged, it is
necessary to replace an entire set of condenser tubes (also known as retubing
the condenser). When new materials designed to better withstand the destructive
environment of the condenser are available, it is typical to use the improved
materials.
b. Consequences of Forgoing Project
Because the steam side of the condenser is at
a vacuum, when a leak occurs, the dirtier cooling water flows into the steam
side. This necessitates shutting down the unit so as not to allow the untreated
water to damage the boiler and the turbine. The leaking condenser tubes are
then plugged. As tubes are plugged, the unit becomes less efficient, meaning
that its ability to generate electricity declines and more emissions are
associated with each unit of electricity produced. Condenser tube leaks
eventually become so significant that the unit is constantly being shut down to
plug tubes. Eventually, the condenser must be retubed or the unit can no longer
operate.
c. Other Information
The replacement of entire tube bundles is
common, and such replacement projects cost up to $10/kw at larger boilers. A
census of repair and replacement practices at coal-fired utility boilers shows
that more than 60% of the units in the industry have replaced condenser tubes.
7. Control Systems
a. Project Description
Careful monitoring and control of operating
conditions at a coal-fired electric steam generating unit are necessary to
insure safe, efficient, and reliable operation of the unit. Control and monitoring
equipment at a unit consists of three major (core) systems: 1) boiler controls;
2) turbine controls; and 3) balance of plant management. Instruments and
controls have advanced rapidly in the past two decades to provide greater
operator knowledge and ability to optimize unit performance and to control
emissions. For this reason, it is typical to replace out-dated benchboard type
switches, lights, gauges, recorders, and manual/automatic stations with
digital, computerized controls with touch screen monitors.
b. Consequences of Forgoing Project
Because controls help manage all aspects of
combustion, unrepaired or outmoded controls will prevent the boiler from
operating as efficiently and safely as is possible with modern controls.
Moreover, because outmoded controls cannot manage a unit with the same
efficiency as modern controls, failure to replace outmoded controls will result
in higher emissions associated with start-up, shut-down and combustion staging.
Often, replacement parts for outmoded controls may simply be unavailable.
c. Other Information
The replacement of pneumatic controls with
solid state, computerized or automated controls has occurred at most units, and
will continue to occur as technology improves. Such projects can cost up to
$10/kw on larger units, and $40/kw on smaller units.
8. Coal and Ash Handling
a. Project Description
Coal handling equipment includes everything
involved in unloading the coal from its transportation device (a railcar, barge
or truck), storing it in a pile, and then conveying it to the plant so that it
arrives at the feeders. After unloading, the coal is typically transported to a
storage pile by a conveyor belt and reclaim system. While on the pile, the coal
is usually managed by bulldozer, and then pushed onto a conveyer belt feeder.
Sometimes a crusher in the coal storage area "pre-crushes" the coal.
The coal travels by conveyor belt to the plant, where it is distributed among a
series of bunkers by the tripper cars. The bunkers sit above and supply the
feeders.
Much of the coal handling system is exposed
to the weather. Moreover, coal is a hard substance that wears away the handling
equipment. For example, conveyor belts, the motors that drive them, and
structural equipment wears and corrodes over time, and this equipment is
therefore commonly repaired and/or replaced. The rate at which the coal
handling equipment deteriorates is influenced by the type of coal that is
burned, with the result that variations in the coal that is burned in a boiler
can lead to accelerated deterioration or obsolescence of existing coal handling
equipment. Other factors that contribute to deterioration include local climate
and proximity to salt water.
Once coal is combusted, the ash that results
from the combustion process is collected in hoppers (bottom ash) or by
pollution control equipment (fly ash). Once collected, the ash is recycled or
treated and stored in ash storage ponds or landfills. The equipment for
collecting, transporting and storing ash is subject to deterioration resulting
from corrosion, abrasion and exposure to the environment.
b. Consequences of Forgoing Project
If coal handling equipment is not repaired or
replaced when it deteriorates, fuel cannot be fed to the units and the plant
must reduce load or eventually be shut down. Replacements are necessary when
deterioration is so severe that repairs would be ineffectual, or where repairs
would not resolve reliability problems. If ash handling equipment and disposal
systems are not subject to constant maintenance and repair, the boiler will
have to reduce load or cease operation until the ash it generates can be properly
handled.
c. Other Information
Common projects involving coal handling
equipment include the replacement of conveyer belts and motors, pre-crushers,
barge and rail unloaders, and tripper cars. Such projects can cost up to $4/kw.
Common projects involving ash handling equipment can cost up to $15/kw.
9. Feedwater Heaters
a. Project Description
Once the turbine has finished with the steam,
the steam is condensed into water in the condenser and sent back to the boiler
for reuse. Between the condenser and the boiler are a series of low pressure
and high pressure feedwater heaters that gradually raise the temperature of the
feedwater prior to returning it to the boiler, where it is then converted to
steam. The feedwater system includes a condensate polishing unit (more common
on larger, newer units) where impurities are removed, low pressure feedwater
heaters, a deaerator heater, a boiler feed pump and high pressure feedwater
heaters. From the last high pressure feedwater heater, the feedwater is
delivered to the economizer inside the boiler.
A feedwater heater consists of a shell that
covers a densely packed bundle of U-shaped tubes in which the condensate or
feedwater flows. On top of the shell, there is an inlet for extraction steam
from the turbine. As the condensate or feedwater flows through the tubes,
extraction steam passes over the outside of the tubes and transfers heat to the
water inside the tubes. Condensate or feedwater passes through the heaters in
series, gradually increasing temperature thereby making the overall unit more
efficient.
The feedwater heater system is subject to
deterioration due to the effects of pressure, temperature and corrosion. It is
common for tubes in this system to spring leaks, with the result that the
heater must be bypassed until the unit can be taken off line to conduct repair
or replacement activity. Newer corrosion resistant alloys to reduce maintenance
problems are under constant development.
When leaks are detected, feedwater tubes are
typically plugged. From 10 to 30% of the tubes may be plugged in some units,
resulting in a significant reduction in unit efficiency. At some point,
plugging tubes is no longer an option and replacement is necessary.
b. Consequences of Forgoing Project
Failure to plug leaking tubes results in a
loss of overall unit efficiency and reliability. A tube leak therefore requires
that the feedwater heater be bypassed until the unit can be taken off line for
plugging or replacement of the leaking tubes. Plugged tubes cannot be feasibly
repaired, so replacement is necessary once enough tubes have been plugged.
Failure to replace the heater means that the heater must be removed from
service, which can cause significant losses in efficiency and reduce the
capacity of the unit to generate electricity, increase the emissions from the
boiler per amount of electricity generated, and increase the reliability
problems of the other feedwater heaters.
c. Other Information
Replacing an individual feedwater heater can
cost up to $5/kw for a large unit. A census of repair and replacement practices
at coal-fired utility boilers shows that more than 80% of the units in the
industry have replaced feedwater heaters or major tube bundles in the feedwater
heaters.
10. Sootblowers/Water Lances
a. Project Description
When coal is burned in the boiler,
"ash" is produced which adheres to the boiler walls and tube
assemblies and to the air preheater. The buildup of ash immediately reduces the
heat transfer capability of these components which, in turn, means that more
fuel is required to maintain the same load. In the long term, the presence of
ash (slag) will cause tube overheating and boiler tube leaks, and may
completely plug an air preheater.
Sootblowers are mechanical devices used for
on-line cleaning of ash and slag deposits in the boiler, in order to maintain
the heat transfer efficiency and to prevent damage to tube assemblies and other
components. Various types of sootblower are used in a boiler depending on the
location in the boiler, the cleaning coverage required and the severity of the
deposit accumulation. Sootblowers basically consist of: (1) a tube element or
lance which is inserted into the boiler and carries the cleaning medium
(typically steam or compressed air), (2) nozzles in the tip of the lance to
accelerate and direct the cleaning medium, (3) a mechanical system to insert or
rotate the lance, and (4) a control system.
Acoustic blowers, which rely on sound waves,
are also used. Sootblowers of all designs must function in the harsh
environment of the boiler and are subject to wear due to exposure to high
temperatures, corrosion, and erosion from high velocity particles. Accordingly,
sootblowers are commonly replaced as they wear out. Also, because the slagging
characteristics of a boiler can change over time, it is common to change the
type of sootblower as the slagging characteristics change or become better
understood.
b. Consequences of Forgoing Project
Failure to replace a deteriorated sootblower
so that it can continue to remove soot, ash, and slag, will limit the capacity
of the unit to generate electricity, and will eventually shut the unit down.
Moreover, if boiler tube assemblies are not kept clean, more tube failures will
occur, requiring more frequent shut downs to replace tube assemblies (see
project family #1). Uncontrolled slagging can also cause catastrophic boiler
damage if the accumulated slag falls from the boiler wall or roof onto the
boiler floor.
c. Other Information
Sootblowers damaged from wear have been
replaced at most units in the industry. Replacement of water lances, sonic
blowers and related technology is also common. Such projects can cost up to
$9/kw.
11. Burners
a. Project Description
Burners provide the final link between the
fuel and combustion air and the boiler. Burners are specialized tubes or barrels
(in the case of cyclone boilers) which direct pulverized coal (carried by
primary air) and combustion air (or secondary air) into the combustion zone.
Each boiler has many burners. The arrangement and performance of the burners
have a direct impact on the distribution of air, the stability of the flame in
the boiler and the combustion efficiency. These factors are adjusted by
controlling the rate and pattern in which air and fuel enter the boiler.
For boilers other than cyclone boilers, dampers
(driven by attached linkages) and vanes control the swirl and volume of air,
while restrictors may be used to manage the volume of coal. Each burner
consists of a coal (or other fuel) pipe and nozzle with a nozzle tip or
impeller at the end of the nozzle at the interior wall of the boiler.
Surrounding the fuel nozzle is the windbox, with secondary air passing through
the windbox and into the boiler via a toroidal opening with the nozzle tip at
the center. Accessories such as flame scanners and lighters are commonly found
in the burner assembly.
Burners, particularly the nozzle tips, are
required to function in extreme conditions. Corrosion, erosion and
temperature-related stresses wear or weaken the tips. Further, the combustion
zone can extend to the tip itself, and the high temperatures can effectively
destroy the tip. The damper linkages are subject to high use and may fail from
exposure to the boiler environment. Finally, because burner configuration and
performance play a key role in staging and controlling combustion, entire
burners may be replaced with modernized designs intended to control the
formation of NOx or otherwise improve the efficiency or completeness of the
combustion, thereby reducing emissions.
A cyclone boiler is designed to melt as much
ash in the coal as possible during the combustion process, and then to drain it
from the bottom of the furnace in order to keep molten slag off of the
superheater and other tube assemblies. This design objective is accomplished by
creating a combustion zone outside the main furnace. These combustion zones or
"cyclones" are cylindrical barrels attached to the sides of the main
furnace. Crushed coal and air are introduced into the cyclone in a tangential
pattern, in order to create a swirling motion to promote mixing of the coal and
air to ensure complete combustion of the coal. The introduction of crushed coal
and air at high velocities erodes the cyclone, and the hot molten slag
environment causes corrosion. High temperatures cause metal fatigue and
deterioration of the cyclone.
b. Consequences of Forgoing Project
Failure to replace damaged burners or
cyclones reduces the efficiency of combustion. Moreover, a damaged burners can
clog and create a safety hazard. Unrepaired damper linkages prevent the unit
operator from controlling the volume and spin of combustion air and will reduce
the efficiency of the unit, thereby increasing emissions for each unit of
electricity generated.
c. Other Information
Common projects involving burners include the
replacement of cyclones, burner tips, burner linkages and the wholesale
replacement of burners for low NOx designs. Burners or cyclones have been
replaced one or more times at most units in the industry, at a cost of up to
$30/kw.
12. Motors
a. Project Description
There are numerous electric motors in a power
plant. For example, motors are used to drive fans, pumps, conveyor belts,
pulverizers, and so on. All motors have insulation which breaks down over time,
causing the motor to overheat and even short out. Usually, when motors short
out they shut down automatically, but they can even catch on fire or explode.
When motors short out, they can be rewound or, if rewinding is too expensive,
they must be replaced.
b. Consequences of Forgoing Project
Failure to replace or to rewind a damaged
motor risks a fire (or explosion if the motor is near coal dust) if the motor
continues operating. Shutting down the motor means the pump, fan, mill,
conveyor, etc. will no longer operate. This means that the unit must either
operate at a lower capacity or potentially even that the unit must be shut
down.
c. Other Information
It is common to rewind or to replace a motor.
Replacement projects can cost up to $5/kw per motor. A survey of repair and
replacement practices at coal-fired utility boilers shows that it is common in
the industry to replace electric motors.
13. Electrical Equipment
a. Project Description
Electrical equipment is used to transmit
electricity and make it usable for electrically-powered fans, motors,
conveyors, lights, and numerous other applications in a power plant. There are
several types of electrical equipment, including buses or wires that transmit
the electricity, transformers that convert it into a usable form, switchgear or
breakers that turn it on and off and protect it from electrical surges. In
addition, for motors, there are often motor control centers and motor starters.
Also, the plant itself uses buses, transformers and switchgear in the process
of supplying electricity from the generator to the grid.
Shorts and overloads can occur in any of this
equipment due to coal dust and the harsh environment of power plants. Damaged
equipment is either repaired or replaced, depending on the severity of the
damage.
b. Consequences of Forgoing Project
Replacement of electrical components that
have deteriorated or are damaged due to the harsh power plant environment is
necessary to support the electrical equipment at the power plant. If the
electrical circuits are not operating, the equipment served by that circuit
cannot operate and the unit will be unable to supply electricity at its
previous capacity, if at all.
c. Other Information
Replacement of switchgears, and other
electrical equipment components are very common. Replacement projects can cost
up to $9/kw.
14. Pumps
a. Project Description
Pumps are used to convey fluids around a
power plant, including water (condenser circulating pumps) or water containing
ash (ash sluice pumps). Pumps have moving parts. Ash sluice pumps are exposed
to erosive, highly stressful environments. Other pumps, such as boiler feed
pumps, are exposed to extreme temperatures and are expected to operate at very
high pressures. These failure mechanisms lead to deterioration, which often
requires replacement of a pump.
b. Consequences of Forgoing Project
If a pump is not repaired, additional stress
is placed on other pumps in the system, and reliability problems will result.
Eventually (immediately for some pumps) failure to replace certain broken pumps
means that the boiler cannot operate at its design pressure.
c. Other Information
Common projects involving pumps include
replacement of boiler feed pumps and ash sluice pumps. Replacement projects can
cost $10/kw. A census of repair and replacement practices at coal-fired utility
boilers shows that nearly 100% of the units in the industry have overhauled or
replaced boiler feedpumps.
15. Piping/Ducts/Expansion Joints
a. Project Description
Pipes are used to carry mass (fluids or
fluids containing solids) through a power plant. Ducts are essentially square
pipes that carry air or flue gas. In an industrial environment like a power
plant, pipes and ducts spring leaks due to the high pressure, high temperature
and corrosive environment. If a section of pipe or duct leaks on an ongoing
basis, the economic choice is to replace that section.
Expansion joints are flexible pieces that
connect two sections of ductwork or piping. They are used because temperature
differences cause different sections of ductwork or pipe to expand and contract
at different rates. Even though expansion joints are designed to move as the
contraction and expansion occurs, they can experience cracks and separations
due to fatigue. If too many leaks occur, they must be replaced.
b. Consequences of Forgoing Project
Leaking ducts, pipes or expansion joints
dilute the power of the fan or pump. Failure to repair or replace the pipe,
duct or joint, therefore, will prevent the unit from generating electricity at
its design capacity. Moreover, leaks of steam, gasses or fuel present safety
hazards which must be addressed in a timely manner once they are identified.
c. Other Information
Replacing leaking ductwork, high temperature
steam pipes, ash handling pipes, fuel piping, and expansion joints are common
projects. It is also common to convert from fabric to metal joints or the
reverse, depending upon boiler characteristics. Replacement and repair projects
can cost up to $23/kw.
16. Air Compressors
a. Project Description
Air compressors are mechanical devices
similar to a pump, except that they compress air instead of a liquid. Air
compressors have moving parts that are subject to wear. The principal use of
compressed air in steam plants is for pneumatic drives for dampers and valves,
system controls, some types of sootblowers, and power repair hand tools.
b. Consequences of Forgoing Project
Failure to repair the service air system will
affect at least some and perhaps many aspects of the plants controls. If
control air is no longer available, it becomes impossible to position valves
properly and the unit cannot be operated.. Failure of the air compressors that
service sootblowers will prevent the operation of those devices, with the
resulting damage to the boiler (see project family #10).
c. Other Information
Replacement is often the most economical
choice for fixing a damaged compressor. Replacement projects can cost up to
$2/kw.
APPENDIX THREE: BOILERMAKERS STATEMENT
Statement of Paul Kern, Recording
Secretary, Local Number 105
International Brotherhood of
Boilermakers, Iron Ship Builders,
Blacksmiths, Forgers and Helpers,
AFL-CIO
4561 U.S. 23 - South
Piketon, Ohio 45661
Public Meeting Regarding New
Source Review
Members of the panel, thanks for
allowing the Boilermakers Union to provide a statement at today's discussion of
New Source Review. The Boilermakers are
a diverse union representing over 100,000 workers throughout the United States
and Canada in construction, repair, maintenance, manufacturing, professional
emergency medical services, and related industries. I am recording secretary at one of our large locals, located in
the Greater Cincinnati area.
First, let me be clear today that
Boilermakers do not oppose the Clean Air Act, nor do we oppose its rigorous
enforcement. In fact, construction
lodges of our union look forward to doing much of the actual work for the
installation of new technologies and controls at utility plants and for
industrial boilers across this region and the country. In reference to the Nox control program
alone, our international President Charlie Jones recently wrote:
"The EPA estimates that
compliance measures will cost about $1.7 billion a year. A sizeable portion of
that money will go to the Boilermakers who do the work necessary to make the
additions and modifications required by the SCR technology."[16]
Aside from Nox control,
Boilermakers have always led the way on Clean Air Act issues. For example, Boilermakers were pioneers in
installation of scrubbers and further in fuel-substitution programs at our
cement kiln facilities. In short,
Boilermakers have been there to meet the challenges of the Clean Air Act, to
the benefit our members and all Americans that breathe clean air.
However, Boilermakers cannot
support the EPA's recent interpretation of its authority under the New Source
Review program. NSR, correctly
interpreted, forces new sources or those undergoing major modifications, to
install new technology, like the technology President Jones mentioned. We support NSR in that context.
But, when NSR is applied to the
routine maintenance policies and schedules of existing facilities, very
different results occur. In those
cases, facilities are discouraged from undertaking routine actions for fear of
huge penalties or long delays or both.
By applying NSR in that way, we are pretty sure that Boilermakers won't
have the opportunity to work on maintenance projects that we know are extremely
important to energy efficiency. Just
hearing about recent events in California is enough to make the case that
facilities need to be as efficient as possible.
Efficiency is not the only reason
to encourage routine maintenance. Experienced professionals or Boilermakers new
to the trade can both tell you:
maintenance is necessary to maintain worker safety. Electric generating
facilities harness tremendous forces:
superheater tubes exposed to flue gases over 2000 degrees; boilers under deteriorating conditions; and
parts located in or around boilers subjected to both extreme heat and
pressure. Any EPA interpretation which
creates incentives to delay maintenance is simply unacceptable to our workers.
As you can see, Boilermakers do
not ask for repeal or substantial revision of the NSR program. We encourage the development and
installation of new technology, and we stand ready to continue to train and
apprentice workers to meet the needs of the Clean Air Act. However, when the NSR programs goes where it
wasn't intended - and discourages the very maintenance, repair and replacement
activities that constitute the livelihood of Boilermakers - we must strongly object.
Thanks for the opportunity to make
a statement.
[1]Foundation for Clean Air Progress, Air
Pollution Plummets as Energy Use Climbs (release of study results)(January 17,
2002), available at: www.cleanairprogress.org /news/energy_01_02.asp. The study's state‑by‑state
analysis tracks air quality and energy consumption during the 15‑year
period of 1985 to 1999. The data were drawn from the National Emission Trends
(NET) database which is available from EPA.
[2]Venturi is quoted in the Statement of C.
Boyden Gray, Hearings: Air Emissions from Power Plants, Senate Committee on
Environment and Public Works, July 26, 2001.
[3]Id.
[4]U.S. Environmental Protection Agency,
Automobile Emissions: An Overview, Factsheet OMS-5 (August 1994). With respect to Nox emissions, a comparison
of reductions required of mobile sources and electric utilities shows that the
utilities are pulling their own weight. Mobile sources contribute 58% of annual
NOx emissions, more than double the 25% generated by electric utilities, and
consequently would seem to have much more scope for emissions reduction.
[5]Vice President Al Gore, Creating A Government
That Works Better and Costs Less (Chapter III - Creative Approaches to
Environmental Protection)(September 1994).
[6]Vice President Al Gore, "The
Environment" from 1996 Annual Report: The Best Kept Secrets in Government
(report to President Clinton regarding Reinvention of Government and the
National Performance Review).
[7]Alexander
Volokh and Roger Marzulla, Environmental Enforcement: In Search of Both
Effectiveness and Fairness, RPPI Policy Study No. 210 (Aug. 1996) at
http://www.rppi.org/environment/ps210.html.
[8]Jonathan H. Adler, Anti-Environmental
Enforcement (Feb. 1, 1997), at
http://www.cei.org/utils/printer.cfm?AID=1307(citing a 1993
survey of 200 corporate general counsels conducted by the National Law
Journal).
[9]The same source continues: "Federal
agencies publish more than 65,000 pages of rules and interpretive statements in
the Federal Register each year, and issue countless pages of regulatory
guidance. Much of this "guidance" actually attempts to change the
meaning of the regulations, or to add new requirements not contained in the
published rule. These thousands upon thousands of pages of regulations and
interpretations often are inaccessible to most Americans, creating a welter of
"private regulations" of which citizens are completely unaware. These
memoranda, letters, and notes, prepared by thousands of separate government
employees, are sometimes inconsistent with each otherCCas well as with the regulation. Indeed, the
more ambiguous the regulation, the greater the proliferation of interpretations
and guidance, leaving the citizen to pick through them to ascertainCCat his perilCCwhat those regulations require of him. The results, in many instances,
include ruinous penalties and the shattering of lives of ordinary, law-abiding
Americans who tried to do the right thing."
[10]U.S. EPA, FY 2001 Enforcement and Compliance
Results (Jan. 31, 2002), available at:
http://es.epa.gov/oeca/main/2001eoy/index.html.
[11]Id.
[12]The Environmental Council of the States,
State Environmental Agency Contributions to Enforcement and Compliance (April
2001), at 9.
[13]Id. at 14.
[14]Id. at 10.
[15]Becky
Norton Dunlop, Environmental Enforcement: Supporting State Efforts to Encourage
Voluntary Compliance at http://www.adti.net/html_files/reg/dd/dddunlop.htm
[16]Boilermaker Reporter, vol. 38, No.
1 (1999) SCR means selective catalytic reduction. SCR essentially consists of injecting
ammonia into boiler flue gas and passing it through a catalyst bed where the NOx
and ammonia react to form nitrogen and water vapor.