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

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.