Prepare Your Gas Plant for Cold Weather Operations

Cold weather operations are challenging for plant designers and operators alike, particularly where severe winter weather is rare. However, another cold winter is expected, so now is the time to review the lessons learned by many plants after the February 2011 Southwest freeze. 

A sustained Arctic blast composed of freezing rain, record snowfalls, and high winds hit 22 states, from Mexico to New England in early February 2011. The extreme weather severely affected the power generation and delivery systems in the southwestern U.S. beginning on Tuesday, Feb. 1, finally diminishing the following Saturday. El Paso, for example, experienced the second-worst winter weather in a century, and the worst in 50 years, with 60 consecutive hours of temperatures below 20F. The temperatures in the Electric Reliability Council of Texas (ERCOT) region during the systemwide emergency ranged from 11F to 35F, equivalent to –5F to the low teens when the wind chill factor is considered. In Austin, temperatures remained below freezing for over 70 consecutive hours.

In Texas, the deep freeze affected every generating company. A reported 225 individual units, including several recently constructed plants, experienced a trip, were derated, or failed to start, reflecting 14,855 MW of unplanned unavailable capacity. Coupled with 12,413 MW of prescheduled generation outages, ERCOT was unable to serve electricity demand, and the results were widespread outages and rolling blackouts caused by frozen equipment (Figure 1).

1. Frozen solid. Many combined cycle plants located in southern states were unable to reliably start or run during the freeze that occurred in early February 2011 because important equipment was not cold-weather protected, as can be seen with this heat-recovery steam generator steam desuperheating station. Source: POWER

The Federal Energy Regulatory Commission and North American Electric Reliability Corp. (NERC) subsequently released their report “Outages and Curtailments During the Southwest Cold Weather Event of February 1–5, 2011” in August 2011. That report describes the cause of the Texas extreme weather event as well as several proactive measures that would improve plant reliability in the future. According to the report, while “many generators were proactive in their approach to winterization and preparedness, others were not.” A key finding of the report was that “the lack of any state, regional or Reliability Standards that directly require generators to perform winterization steps has left winter-readiness dependent on plant or corporate choices.”

Re-Learned Lessons

Plant outages caused by extreme cold weather events (as well as impacts on natural gas pipelines that supply the rising number of gas-fired combined cycle plants now operating) appear to be more problematic in the southern region of the U.S. Natural gas–fired plants in the northern states continued to operate reliably because they were designed to do so from the outset. For example, Minnesota Municipal Power Agency’s Faribault Energy Park, located in Faribault, Minn., routinely operates for months at a time without a problem when the outside temperature is below zero (see “How to Make a Power Plant a Welcome Neighbor,” March 2008).

In contrast, plants built in the southern states, from Florida to Arizona, are often of an outdoor design that makes retrofit an expensive proposition. Regulators in some NERC regions, such as ERCOT, have since become more proactive with plant inspections and third-party design reviews of plants vulnerable to extreme cold and are ordering temperature-related reliability upgrades.

Our survey of several of the lessons-learned reports prepared in the wake of the February 2011 freeze found a number of common failure modes, many of which have since been the subject of reliability upgrades at many affected plants.

Instrument and Sensing Lines. Many plants reported outages caused by frozen boiler airflow, deaerator level, and boiler drum instrumentation and transmitters. A commonly reported problem was a unit trip from a low drum level signal caused by frozen instrumentation and sensing lines.

According to Black & Veatch, which analyzed the impact of the event on one Texas utility, “The frozen sensing lines prevented the automatic drum level control system from operating to maintain the water level in the drum within predetermined limits to prevent damage to the boiler. Damage could be caused either by running the drum dry, resulting in major damage due to overheating of drum and tubes, or by allowing the level to rise too high, which can result in carrying over slugs of water into the steam tubes and possibly into the steam supply lines to the turbine.” To the operator’s credit, the drum water controls were placed into manual mode, and drum water levels were monitored by operators with radios reporting status to the control room.

At a different plant, once the unit tripped and residual heat was lost in the water systems, other instrumentation and sensing lines froze, thereby preventing a unit restart. Another plant reported the same problem, though it was able to continue operation at reduced load.

The solution to frozen instrumentation and sensing lines (particularly, critical drum level, feedwater flow, and steam flow transmitters) must be holistic. For example, there must be freeze protection in the main circuit breaker panel that powers the instruments and the panel board transformer, insulated and heated drum level transmitter(s) enclosure(s), a means to continuously monitor enclosure temperature, and a means to confirm operation of the heat trace cable used throughout the system.

Heater strips in instrument cabinets were often overcome by freezing temperatures, though additional insulation and additional heating strips often solved this problem. A single point failure in the heating system can cause a trip of the unit. Modern heat trace cables are available that are prefabricated, not easily broken, and have a self-regulating heating element. Some users report installing lights to give a visual indication of the box temperature. Steady lit means the circuit is on and the box is at set temperature, flashing light means the circuit is on but the box is below set temperature, and when the light is out it means there is no power available to the heater. This approach works well when the enclosure is covered with an insulating blanket and operators can see the lights at elevation from ground level (Figure 2).

2. Saving steps. The proper operation of important instruments and weather enclosure heating systems at this plant can be confirmed by operators at ground level by the four red LED lamps, instead of by climbing stairs multiple times each shift. Further, networked instruments can often display an error message on the plant distributed control system in the event of an enclosure heater failure, without adding any additional wiring. Source: POWER

Pipes and Valves. Several plants reported that frozen steam turbine drain lines prevented unit restart until ambient temperatures rose above freezing so the ice could melt. Another unit experienced frozen deaerator level control sensing lines that failed to signal the need for makeup water, causing a plant shutdown signal generated by low boiler feedwater pump suction pressure.

Another utility attempted to start a unit that was offline when the sub-freezing temperatures hit, but frozen instrument lines prevented the restart. Heat tracing of instrument and sensing lines is commonly found at most outdoor plants, though heat tracing is used to prevent freezing, not to thaw frozen lines.

Users also reported problems with small piping supports, because they can act as a heat sink and cause the pipe to freeze even when insulated. The same applies to external pipe hangers that penetrate pipe lagging. Heat sinks should be eliminated from plant piping.

Non-heat-traced pipes froze at several plants, causing pipes to rupture (Figure 3), including outside fire protection piping and piping located near building ventilation louvers (thus rendering the fire protection system inoperable). The National Fire Protection Association (NFPA) has established clear fire protection system freeze prevention requirements (NFPA 13). From a safety viewpoint, you should heat trace the water supply to the safety showers located throughout the plant.

3. Frozen pipes. Frozen water in pipes and valves often caused extensive damage during the February 2011 freeze, particularly to water mains and fire protection water pipes. Source: POWER

Ammonia lines to the selective catalytic reduction system of a gas-fired plant must be properly heat traced and insulated. A crack in this line could easily become a significant environmental issue if left undetected. The same should be said for chemical lines used for boiler water treatment and the boiler water sample lines.

Compressed Air Systems. Compressed air systems may also be at risk. The typical southern climate plant uses compressed air outside directly after the coalescing filter. Plants built in northern climates use air dryers to provide compressed air at a dew point temperature below the minimum design temperature to prevent freezing of instrument air lines. Air compressor condensate vent lines should also be heat traced, unlike the typical southern plant. High moisture levels in the instrument air often caused freezing of air-operated valve actuators.

Redundant dew point monitors may be used to continuously monitor compressed air quality. Do not rely on automatic air tank drain systems for moisture control. One utility reported the failure of an automatic air tank drain resulted in the contamination of its instrument air system, which is very difficult to clean. At least one plant reported that moisture in the control air system caused a pneumatically controller positioner on a fan damper to fail, causing a complete unit forced outage.

Other Plant Systems. Freeze protection must also be considered for outdoor equipment that will not be operated. For example, a heat-recovery steam generator (HRSG) full of water may need to be drained when exposed to unexpectedly low temperatures. The time to freezing must be determined based on multiple factors: design low temperature, coincident wind velocity, assumed temperature of the water within the equipment (usually the heat tracing design criteria), and the existing insulation of the equipment. The plant staff response time to instigate additional freeze protection actions (typically 24 hours) can then be compared to the time to freeze for the HRSG to determine if the HRSG must be drained to prevent water freezing and tube ruptures.

Sub-freezing weather can cause harmful problems with forced-draft cooling tower operation, particularly when there is freezing within the tower fill media. In one instance, operators observed ice forming on the tower and shut down the circulating water pumps and fans to one or more cells. Ice formation on the cooling tower should be avoided, because it could be a risk to the circulating and other cooling water pumps that take suction from the tower basin. One plant noted that it quickly shut down the cooling tower to prevent icing when the plant unexpectedly tripped (Figure 4).

4. Towering problem. Ice forming on a forced-draft cooling tower during freezing conditions can damage the tower internals. Ice forming within the basin can reduce flow and damage the cooling tower pumps. Source: POWER

Plant demineralized water systems should be freeze protected and capable of delivering properly treated water during a cold weather event. Also, ensure that there is sufficient chemical inventory, and/or have a plan in place for delivery of critical chemicals and gases (such as hydrogen) during extreme weather. Some plants experienced freezing of water treatment chemicals used for demineralizer regeneration and have since installed reverse osmosis water treatment plants to eliminate the problem. Also, if vendors can’t get to the plant during extreme cold weather, critical material deliveries will be delayed. Make sure offsite support personnel for critical systems, such as the substation, are identified and can be contacted in an emergency.

The combustion turbine (CT) main fuel gas regulator and fuel gas stop valve must be well insulated or they can freeze and cause a trip. Also, icing of inlet air ducts and filters can cause a spike in the differential pressure, causing a unit trip or derate. The worst case is a frozen inlet filter causing the CT compressor to stall, which can in turn cause significant damage to the turbine internals. Inlet heating systems will keep the inlet filter ice-free. Finally, carefully inspect the compressor water wash and evaporative cooling systems for leaks that can form ice (Figure 5).

5. Damaged blades. Compressor blade damage can occur when water wash and evaporative cooling systems leak. Unidentified water leaks can form ice on the compressor blades or compressor inlet, which can cause damage to the airfoils. Source: POWER

CTs must also be properly tuned for cold weather operation. As ambient temperatures drop, power output increases. This means that at very low temperatures the power output is maximized but so is mass flow of emissions and the possibility of permit exceedances. The turbine control system should be tuned so that permit limits are not exceeded at low temperatures.

Transformer insulators and arrestors should be thoroughly cleaned prior to the cold weather season in order to minimize the risk of flashover. This is very important for those plants where the prevailing winds push cooling tower drift toward the switchyard. Corona discharge can damage insulators and other substation hardware and is a sure way to force a unit offline.

Setting Priorities

Chances are your list of low-temperature operation upgrades is extensive and expensive. You may want to consider the following method of sorting your list with your budget request.

The first category is specific equipment that, when frozen, will prohibit the plant from starting or restarting during the coldest expected conditions or equipment that is likely to cause a forced outage when frozen while operating. Also identify equipment that, when frozen, will cause equipment damage or personnel safety concerns. Essential instrumentation and sensing lines, exposed service water piping, and fire protection pipes fall into this category. So do employee emergency shower stations typically found around chemical storage and use areas.

The second category is equipment that, if frozen, will cause an equipment malfunction or even damage, but will not cause a forced outage of an operating plant or prevent a start or restart of a unit. Nonessential instrumentation and sensing lines fall into this category. For example, one utility that uses lake cooling water requires the continuous operation of one circulating water system screen wash pump to ensure piping integrity. The suction leg of the standby unit is drained to prevent freezing. Frozen condensate drains from continuous emissions monitoring systems may also fall into this category.

The third and final category is equipment that, if frozen, has the potential of reducing the availability or reliability of the plant or may temporarily reduce unit output. Multiple cell, forced draft cooling towers and nonessential water lines fall into this category. Another example may be failed heaters or heat tracing used to warm lubricating oil and greases that can result in motor or pump vibration and unit trips or runbacks.

ERCOT Makes Preparations

The next unexpected cold weather blast should mean less bad news for ERCOT generators, because in ERCOT, and all NERC regions, winter preparation planning is now a regulatory requirement. Winter preparation surveys must be completed by generators, as are emergency operations and resource weatherization plans. Generators must submit their severe weather preparation plans by affidavit.

ERCOT also performs spot reviews of generator plans, makes site visits to verify plans, and conducts unannounced black start unit testing. The surveys include information on backup fuels available and how long a unit can operate on the backup fuel. This is an important consideration, as 89 of the 130 units with dual-fuel capability experienced a trip, failure to start, or derate during the February 2011 severe weather event. Only four units successfully switched to backup fuels. The surveys also must identify primary and alternate gas pipeline fuel supplies. Finally, the surveys require generators to estimate derating and forced outage rate based on two extreme temperature scenarios. ■

Dr. Robert Peltier, PE is POWER’s consulting editor.

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