Powerplant Emergency Fuel Supplies, Past, Present and Future
This article Is written as a continuation of the discussion started by the Energy Bad Boys in their article “Battery Storage is 141 Times More Expensive Than Liquefied Natural Gas Storage”. The reports coming out of NERC and out of the news have not been very optimistic about the ability of our power system to survive intact in the event of a major cold weather event. The NERC 2024 Winter Reliability Assessment highlighted a number of areas of concern.
Two recent winter Storms, Winter Storm Uri (February 13–17, 2021 North American winter storm) and Winter Storm Elliot (December 2022 North American winter storm). The NERC/FERC Reports on these storms, Report | The February 2021 Cold Weather Outages in Texas and the South Central United States, and Winter Storm Elliott Report: Inquiry into Bulk-Power System Operations During December 2022 both discuss fuel delivery problems to Bulk Electric System (BES) generation facilities as a major contributing cause to wide area power outages. Both these storms resulted in a significant number of fatalities, many due to direct hypothermia from loss of heat. Before we talk about where we are, let’s talk about where we came from and how we got here.
If we venture back to the 1960’s and 1970’s, the vast majority of our power came from coal. Coal was, for the most part, naturally weather resistant. Most coal fired power plants kept a week or more of fuel on site to ensure against rail breakdowns, mine accidents and mine strikes, or anything that might interrupt the flow of fuel. A 1200 MW coal plant burns about half a railcar load of coal an hour, so a 1-week coal pile is not small
. That being said, coal plants are not completely weather resistant with their fuel. Coal plants pulverize coal to the texture of talcum powder and blow it into the boiler, where the fire ball is then suspended mid-boiler. The coal mills depend on a steady flow of small pieces of coal to pulverize. The coal pile is subject to water penetration and freezing, which creates large frozen blocks of fuel that will not move down the conveyor. (For a more in-depth breakdown of how coal is processed and used in power plants, see the document below). Regardless, that is an operational problem, not a supply problem.
The west coast has no natural coal deposits due to its volcanic nature. It did, however, have significant oil and gas deposits. Because of that, the large thermal plants were built as dual fuel, to both burn natural gas and to burn fuel oil. The plants always had several refinery size tanks to store fuel oil and nearly always kept at least a partial capacity on hand. Utilities would switch between fuel oil and natural gas based on the market price of the fuel. This provided the thermal plants with a reserve fuel by design.
Gas turbines were not really a big player at that time. They were used for black start, peaking, and non-spin reserves. The size of gas turbines available were pretty small by modern standards, less than 100kW. A great many were liquid fueled, burning diesel, kerosene, or jet-a. The black start units were often equipped with a piston diesel engine to crank the gas turbine, The object of these small black start plants was to provide energy to start the bigger boiler plants. Many of the black start investments were a direct result of the 1977 New York Blackout.
Before the 2003 Northeast Blackout, NERC did not have enforcement power. They had a list of guidelines that were recommended practices, but there was no central enforcement. Some regional entities like WECC did have binding agreements with signed members to enforce certain rules, but there was no requirement to join. WECC did have an alternative fuel rule in place for member agencies, Redding Electric Utility (REU) put in three 100,000 gallon propane tanks when they constructed a small powerplant in 1993. REU sold off the propane and the tanks in approximately 2010.
Utility operations stayed relatively stable for the next twenty years. Starting in the late 1990’s, the following events played a big part in shaking things up:
Lobbying by Enron brought about electric de-regulation in 1996, suddenly electric power was a commodity, not a regulated utility business.
In the early 2000’s lobbying by environmental groups moved natural gas forward as a cleaner alternative to coal. Rapid development in large high efficiency gas turbine technology followed on the heels of this political change making combined cycle a viable alternative.
In 2008 the new advancements in drilling and fracking opened the gas boom that dropped the price of natural gas and made it widely available as an energy source. Operating a combined cycle plant was now more cost effective than operating a coal plant unless it was grandfathered.
From 2000 on, PUCs continued to pressure Investor-Owned Utilities to divest ownership in powerplants. Owning and operating a powerplant became a private business venture.
The 2003 Northeast Blackout resulted in FERC establishing national enforceable standards for the Bulk Electric System (BES) and any company connected to it. After negotiation the National Electric Reliability Council became the National Electric Reliability Corporation and became the standard writer and enforcement agency for FERC. All regional guidance ended.
NERC listed certified black start facilities as CIP High Impact. This tremendously increased the cost of maintaining the required security at these facilities. This resulted in a significant number of black start resources being removed from the certification pool, and efforts to maintain their black start capabilities were abandoned.
This decade of massive change completely overhauled the electric power industry. Those changes also impacted the fuels that were consumed to generate power.
Under ever increasing pressure from the EPA, coal lost its place as the preferred fuel source for power generation. Forced retrofits for mercury, SO2, and other emissions drove up the cost of running existing plants. New safety standards, runoff pollution standards, land reclamation standards, and other regulations drove up the price of mining a ton of coal. At the same time, shale gas dropped natural gas below coal on a cost per MMBTU comparison. The new combined cycle plants did more with less fuel, were cheaper and faster to build, and had fewer emission issues. (EIA write up on CCPP)
The EPA also stepped into fuel oils; Heavy Fuel Oil (HFO) that had been used to fuel boilers in the past was largely regulated out of existence for domestic use. HFO is still used by freight ships as soon as they reach international waters. EPA also essentially outlawed all high sulfur content fuels causing a significant increase in the cost of diesel, kerosene, and jet fuel. As a utility generation fuel, these types of liquid fuels require additional emission controls to filter out particulates which is not an issue with natural gas. New England remains the single remaining North American bastion of fuel oil generation. Many of the old fuel oil boilers are grandfathered but burning stove oil now. There’s also a fair number of very old duel fuel gas turbines still in service. This is mostly due to the very limited natural gas infrastructure in the area, and the resulting high gas prices from the congestion.
Where does that leave us now? Powerplants are largely privately owned, bidding their output into energy markets. Because they have become separate profit driven entities, instead of a department in a vertically integrated utility, reliability is often not their first motivation. PJM has tried to create some accountability by creating a capacity market where generators get paid for being available and get fined when they fail to perform. There is little incentive to spend more than is required.
Unless it is a special-order small unit, dual-fuel gas turbines are a thing of the past. Large, combined cycle gas turbines are designed with special lean burn fuel nozzles and turbine blade material. Lean burn technology and dual fuel are not compatible, so building a turbine to those specs means it will burn more natural gas for the same output.
Winter Storms Uri and Elliott have brought to light some glaring issues with the generation supply as it exists today:
Low pressure gas distribution systems fall under State PUC guidance. They have an obligation to deliver gas to the low-pressure gas distribution system even in adverse weather, which gas distribution providers have designed their systems to provide. Residential gas delivery takes priority over industrial delivery.
The natural gas transmission system is prone to significant drop-offs in supply capability in severe cold weather.
There is no national agency like NERC overseeing the reliability of the bulk natural gas piping system. The Department of Transportation is responsible for pipeline safety, but that is the only federal oversight.
Because there is no national agency, there are no nationally consistent standards to operate the gas system by.
FERC lacks the authority from Congress to implement a national oversight organization or department.
Failures on the bulk gas system translate to major impacts in generation loss on the BES.
NERC has done several studies on the cold weather gas issue, including this 117-page report; “2013 Special Reliability Assessment: Accommodating an Increased Dependence on Natural Gas for Electric Power”. They have worked with the gas industry to make improvements. But ultimately if a gas operator does not want to spend the money on improvements, there is no method available to compel them to do so.
NERC introduced “Reliability Guideline Fuel Assurance and Fuel-Related Reliability Risk Analysis for the Bulk Power System September 2023”. This 47-page guideline is an outline to follow for assessing the reliability of a fuel source. NERC did not discuss alternative fuel supplies.
This leads us to a conversation about how to address the immediate problem of natural gas interruptions during the same periods when the power system is severely stressed during cold weather events. On a normal operating day there is almost always sufficient operating reserves to cover any loss of generation. However, during a cold weather event electrical demands are extremely high, and virtually all resources are needed to cover any contingencies. Time has proven that no matter how well prepared some, generation facilities will fail due to the cold from problems unrelated to fuel. Adding fuel to the mix just exasperates the problem. A potential solution is to co-locate LNG storage that was proposed by the Energy Bad Boys for critical generation, let’s look into it a bit.
The first question is how much fuel we need to store. Per EIA, an average CCPP will burn 7.5 MMBtu per MWh, simple cycle turbine 11 MMBtu per MWh (see EIA table). Let’s do a little math and see what we would need to do. A 1000MW combined cycle plant will burn 7500 MMBtu per hr at full load, at 12.1 gallons of LNG per MMBtu, that’s 90,750 gallons of LNG, or at .086 cubic ft of LNG per MMBtu, that’s 645 cubic feet. Fuel storage tanks are rated in cubic feet, that is why I used that number. The largest LNG tank in the USA that is recorded is in New England at 150,000 cubic feet. Based on these numbers you would need a 50,000 cubic foot storage tank for 72 hours, or a 110,000 cubic foot tank for a week. (calculation page, math checks are welcome)
So, a gas fired plant is looking at a major capital investment to make itself largely fuel supply interruption proof. In addition to the tank, they are looking at a cryogenic plant to liquify the gas. The cryogenic plant only needs to be large enough to fill the tanks at a pre-determined offline rate (backup fuel). However, the fuel vaporizers need to be able to keep up with the full fuel load of the plant plus the fuel load of the vaporizers (unless steam extraction is used). You would probably want to split the load over several vaporizers so if one failed it wouldn’t take you offline. You would need sufficient supply line capacity to fuel the plant plus feed the cryogenic plant. Then you need to pay for all that fuel in storage that is not generating income.
For obvious reasons most generating facilities are unlikely to make this kind of capital investment under our present market and regulation structure. It is quite likely that any attempt to force this type of investment would result in the facility shutting down. There needs to either be a market incentive, or the government should consider offering a subsidy if they implement a rule that would cause this type of investment. Currently, it is not clear if there is enough customer pressure to make that a priority.
The conclusions are that this is an extremely viable option to provide fuel reliability to natural gas fired plants during major weather events. However, this a capital intensive option, and does not offer the Power Plant Operator/Power Plant Owner much Return On Investment (ROI) for installing and filling this equipment. Market conditions need to change to provide Power Pants with an ROI to create opportunities to grow this technology.
Right now effective solutions to winter fuel supply problems are not being discussed. You can help be promoting this article, pushing the topic of winter fuel issues, and forcing the conversation. I certainly do not have the horse power to make this a topic of discussion, but some of you do, let’s push.
That might account for some of the issues during Uri, but it does not explain the issues during Elliott. During Uri some power plants had their gas supplies curtailed, which when they were forced offline, de-energized electric powered gas compressors. From there things started to cascade on the Texas gas system.
Elliott the gas line pressure simply dropped below operational pressure for many combined cycle plants. Most large frame gas turbines need in excess of 600 psi gas pressure to operate. Spot market gas purchases had nothing to do with it.
It should be noted the incoming energy secretary was a big mover in pushing gas transmission compressors to electric power.
Would it be practical or cheaper to store natural gas underground, e.g. salt caverns?