WITH ANOTHER POLAR VORTEX UPON US, DURING THE 2014 COLD WEATHER, Many outages were the result of extreme cold weather that was below the design basis of generating units
Increased reliance on natural gas
during the polar vortex exposed the industry to various challenges with fuel
supply and delivery. Many outages,
including a number of those in the southeastern United States, were the result
of extreme cold weather that was below the design basis of generating units. Industry should identify and protect against
failures that occurred within the design basis of their plants. SERC experienced 25 hours during the study period
where they were below their typical temperature design basis, including 17
continuous hours below that basis.
In a September 2014 report, NERC describes what happened during the polar vortex and
why some of the conditions occurred, and it presents lessons learned and
recommendations for future actions. In early January of 2014, the Midwest,
South Central, and East Coast regions of North America experienced a weather
condition known as a polar vortex, where extreme cold weather conditions
occurred in lower latitudes than normal, resulting in temperatures 20 to 30° F
below average. Some areas faced days that were 35° F or more below their
average temperatures. These temperatures resulted in record high electrical
demand for these areas on January 6 and again on January 7, 2014.
During the polar vortex, the cold weather also increased demand
for natural gas, which resulted in a significant amount of gas-fired generation
being unavailable due to curtailments of gas. Balancing Authorities (BAs) and
Load-Serving Entities in both the Electric Reliability Council of Texas (ERCOT)
and the Eastern Interconnection were mostly able to maintain their operating
reserve margins and serve firm load. By properly and appropriately
communicating through the NERC Energy Emergency Alert (EEA) process using
interruptible load, demand-side management1 tools, and voltage reduction, only
one BA was required to shed firm load. The amount shed was less than 300 MW,
representing less than 0.1 percent of the total load for the Eastern and ERCOT
Interconnections. Many outages, including a number of those in the southeastern
United States, were the result of temperatures that fell below a plant’s design
basis.
Generation facilities have made improvements in their winter
preparation activities since February 2011; however, every extreme event
provides insight for future improvements. Generation facilities across all
Regions have indicated that they have reviewed or implemented recommendations
from the February 2011 Southwest Cold Weather Event Lessons Learned, as
well as the Generating Unit Winter Weather Readiness reliability
guideline.
System Operators had many challenging decisions to make as a
result of lost capacity from both weather conditions exceeding the design basis
of generating units, and from the lack of availability of natural gas. They
successfully maintained reliability through extensive training and preparation.
For example, during the polar vortex, several System Operators used load
reduction techniques such as voltage reduction or interruptible loads. They
also made effective use of emergency procedures to manage loads and generation.
While the NERC Event Analysis process has clearly defined
categories for electric disturbances in small defined geographic areas, based
on the combined unintended loss of generation during the three-day period
(January 6–8), this event reached the equivalent of an ERO Event Analysis
Process level of Category 5 (unintended loss of more than 10,000 MW of
generation). WECC and the majority of the Canadian entities are not included in
this analysis as the report is based on the geographic areas that observed
effects of this extreme event.
The report also contains more than a dozen observations and
recommendations to improve performance ahead of and during cold weather events.
The recommendations include:
·
Review natural gas supply and transportation
issues and work with gas suppliers, markets, and regulators to develop
appropriate actions.
·
Review and update power plant weatherization
programs, including procedures and staff training.
·
Continue or consider implementing a program for
winter preparation site reviews at generation facilities.
·
Review internal processes to ensure they account
for the ability to secure necessary waivers of environmental and/or fuel
restrictions.
·
Continue to improve operational awareness of the
fuel status and pipeline system conditions for all generators.
·
Include in winter assessments reasonable losses
of gas-fired generation and considerations of oil burn rates relative to oil
replenishment rates to determine fuel needs for continuous operation.
·
Ensure that on-site fuel and fuel ordered for
winter is adequately protected from the effects of cold weather.
·
Consider (where appropriate) the temperature
design basis for generation plants to determine if improvements are needed for
the plants to withstand lower winter temperatures without compromising their
ability to withstand summer temperatures.
·
Review the basis for reporting forced and
planned outages to ensure appropriate data for unit outages and de-ratings.
Cold weather effects on equipment
The extreme cold weather had a major impact on generation
equipment. Of the approximately 19,500 MW of capacity lost due to cold weather,
over 17,700 MW was due to frozen equipment.
The following list illustrates some of the challenges faced by
generator owners and operators due to the effects of cold weather on equipment.
These challenges affected almost every dimension of the generation, from
instrumentation, to fuel quality, to air-fuel mix, etc. Newer generation units’
cold weather preparations were tested for potentially the first time for these
temperature extremes, and many older units experienced extremes beyond what
they were designed to operate. The examples below are individual occurrences
that are representative of the challenges faced during this extreme period. Not
all of these instances resulted in a forced outage; many just delayed the
unit’s ability to come on-line or resulted in the unit’s derating.
Examples of extreme cold weather effects on generation:
·
The drum level transmitter sensing lines froze,
indicating a false drum level and consequently tripping the boiler.
·
Moisture ingress caused gear boxes, valve
positioners, and solenoid valves to fail due to freezing.
·
Heat trace electric circuits not working prior
to the event tripped during the event, or were miswired.
·
Cold air backflow down the stack and into the
boiler affected performance.
·
During start-up from the previous outage, the B
phase stab disconnect was not fully engaged, which resulted in voltage
differential between phases. The unit had to be removed from service to repair
the disconnect. Upon investigation, the damage to the disconnect was caused by
ice build-up from the unit’s cooling towers.
·
Circulating water was frozen, causing a loss of
supply of needed cooling water.
·
Extreme cold weather and cold oil resulted in
oil pressure control tripping.
·
A plant steam pressure transmitter froze due to
extreme cold conditions, which limited the operation of the condenser air
removal equipment, and the unit tripped on low vacuum. The transmitter is
located inside the main building close to an exterior wall louver.
·
Impulse tube lines, level transmitters, or
pressure sensing lines were uninsulated or underinsulated, resulting in
freezing components.
·
A transformer had water in it and froze.
·
A feedwater heater pressure sensing line froze,
which required the unit to be taken off-line.
·
Fan damper operation was sluggish during cold
weather due to cold grease, and a deaerator level indication had a frozen
sensing line.
·
Steam and water flow transmitters were
uninsulated or underinsulated, resulting in freezing components.
·
The unit tripped due to a frozen super heat
pressure transmitter.
·
A collector ring failure was caused by
insufficient brush tension resulting from very cold temperatures.
·
Air entrainment in the sensing lines caused a
transmitter to fail. The line did not actually freeze, but it interfered with
instrument compensation.
·
A frozen gas valve caused a unit outage.
·
The diesel fuel changed consistency, rendering
the fuel unusable in the cold weather.
·
Moisture in an air line to the inlet bleed heat
valve froze.
·
The static frequency converter initiated a trip
during preparation of Static Frequency Converter & Static Excitation System
(SFC/SES) caused by not receiving exciter circuit breaker checkback signal for
the closed position. Subsequent failures were caused by not receiving the
checkback signals from the start disconnect switch in the generator breaker.
Extreme cold temperatures caused grease on start disconnect switch stabs to
become tacky and not allow it to close without binding.
·
Oil pressure was affected due to cold oil from
the lube oil (LO) cooler entering the LO supply header too rapidly. The LO
temperature control valve has no cold ambient bias to slow down movement in
winter.
·
Frozen NOX water header pressure sensing lines in the unit
resulted in no available NOX water injection for emissions control.
·
Water froze in a water manifold that had not been purged of water.
·
Generator logic tripped the turbine due to a frozen water flush
transmitter. The transmitter was frozen due to cold weather; however, the logic
should not have tripped the unit.
·
The outage was due to a failure of the water injection heating
system. Cold weather may have contributed to but was not the primary cause of
the outage. Power was removed from the heating system due to a water leak that
caused an electrical short circuit. It is not known if cold weather caused or
contributed to the initial water leak. Once power was removed from the heat
tracing on the water injection pipes, they froze. The situation was corrected
by placing a tent around the problem area and using a torpedo heater to
unfreeze the water lines.
·
A unit water injection variable frequency drive (VFD) controller
tripped due to extreme weather, requiring a unit shutdown to prevent emission
exceedance.
·
A unit heater tripped, which affected operation of VFD. During
restarting the water injection VFD, unit was at upper load and flamed out from
inrush of water.
·
A frozen water valve located outside for the oil cooling system
caused the unit to trip. The ambient temperature at the time of the trip was
-3° F with an 8 mph SW wind.
·
The unit would not transfer to “Pre-Mix Steady State” due to
operating in the cold ambient temperatures; it required combustion tuning for
the colder conditions.
·
A gas transfer purge valve froze.
·
The pressure dropped due to regulator not being able to react
quickly enough because of the extreme cold temperature.
·
An output breaker would not close due to the cold.
·
The premix line froze due to heat tracing failure.
·
Fuel oil gelled the filters due to the cold temperatures.
·
A hydraulic starter pressure sensing line froze.
·
Lube oil temperature was below 50° F, causing the unit to be in a
not-ready-to-start state.
·
The diesel fuel being provided to the starting motor gelled due
the extreme cold temperatures.
·
The diesel starting engine failed to provide enough turbine speed
to initiate firing.
·
A liquid fuel modulating valve frozen (located in unheated engine
compartment when off-line).
·
A starter duct pressure switch located in unheated engine compartment
froze.
·
A unit tripped on loss of flame due to the combination of fuel oil
delivery temperature being low and ignition gas being insufficient to maintain
the flame.
·
A unit could not start due to hydraulic temperatures too low for
proper operation of fuel valves.
·
Frozen regulator on monitor valve at meter station caused low fuel
gas pressure.
·
The inlet air intake was covered with snow and ice.
·
Moisture in a fuel oil pressure switch froze and the pressure
switch diaphragm burst.
·
The fogging and overspray were put in a
winterized state. The systems were available but required additional time to
return to service.
·
Cold weather caused water injection lines to
become frozen, which resulted in a transmitter control issue.
·
The gas control and purge valves were sluggish
due the extreme temperature. The control timers for the valves were adjusted to
allow for the longer valve operating time.
·
The relay setting did not take into account the
higher-than-normal output for the extreme cold weather.
·
The lube oil was too cold because the
compartment heater malfunctioned. This caused the lube oil temp alarm to trip
the unit in start-up.
·
A solenoid was frozen on the water injection
system. This caused an emissions issue.
·
Compressor blade icing caused a unit outage.
·
Units tripped when the units were being
transferred from gas to liquid fuel. These CTs were running on gas when the
site was asked to transfer them to liquid fuel due to limited gas availability.
Extremely cold temperatures along with the liquid fuel heaters being out of
service contributed to an increase in fuel oil viscosity that led to a high
filter differential pressure and subsequent fuel system fault trips while
attempting to transfer to liquid fuel.
·
Low ambient temperature led to fuel waxing and
clouding.
·
Frazil ice blocked the intake, causing
insufficient water supply to the turbine.
·
Due to low temperature, the seal oil regulator
froze, allowing the oil pressure to rise above the hydrogen pressure, therefore
putting oil inside the steam turbine generator.
·
A steam turbine exhaust pressure switch for HP
turbine froze, which signaled a false high pressure, thereby tripping the steam
turbine.
·
Cold temperature caused materials on the
generator hydrogen cooler cooling water loop to contract, and the flanged joint
at generator shell began to leak hydrogen. The flange bolting was re-torqued to
stop the leak.
·
A seal steam pressure transmitter sensing line
froze, causing pressure to read high opening bypass to condenser, which in
turned caused loss of sealing steam to turbine.
·
A unit tripped due to cooling tower drift
freezing onto and restricting flow through the inlet bird screen; with enough
build-up, this caused the implosion doors to open.
·
While switching from gas to oil, a process step
was missed, resulting in the trip.
·
A unit was shut down for inspection because a
noise could be heard during the hourly inspections. Ice was found on the inlet
guide vanes.
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