Hybridization: Pairing Technologies for Synergistic Enhancements (Including sCO2 Hybrids)

 

     Hybridizing technologies can offer some practical advantages. One of the most well-known of “hybrids” is hybrid vehicles where an electric motor is paired with an internal combustion engine to improve vehicle mileage, emissions, and fuel costs. The Toyota Prius, introduced in the early 2000’s is still a popular hybrid choice. Now there are many others. Then came plug-in hybrids, pairing a plug-in EV of lesser range with an ICE engine, which enable further improvements in mileage, emissions, and fuel costs while avoiding issues with pure EVs like range limitations and longer charging times.

     In energy there are several other kinds of hybrids. One of the most well-known is the combined-cycle natural gas plant where a combustion turbine is paired with a steam turbine to take advantage of the waste heat from combustion. Another in the pairing of solar energy and energy storage, or solar-plus-storage that takes advantage of excess solar generation during peaks in the sunniest parts of a day when production is more than needed and saves it for later in the day by feeding it to a battery. In a sense a grid-tied rooftop solar system is a kind of hybrid since it provides power for a house or business and any excess during peak production is fed to the power grid.

    

Diesel-Electric Hybrid Drilling Rigs, Fuel Blending, E-Frac, and Other Hybrids in Oil & Gas

 

     One kind of hybridization used in the oil and gas industry and in other applications is dual fuel engines. Some reciprocating engines and turbines can accommodate dual fuels and blends of natural gas, diesel, propane, and hydrogen. Blending hydrogen with natural gas in pipelines, storage fields, and power plant combustion turbines can be considered a hybridization. Diesel-Electric hybrid drilling rigs have been pioneered by Equinor and other operators and rig fleet companies like Maersk active in the North Sea. These hybrids can utilize braking similar to how automobile hybrids do in order to save energy expenditure and lower emissions. Maersk first deployed their retrofitted diesel-electric hybrid rig Intrepid in November 2020. The Intrepid utilizes battery power to address variable power and the high peak loads that rigs encounter. Braking energy is recovered. A digital energy management system optimizes rig energy use. Energy use and emissions are both reduced significantly. In 2021 a 2^nd retrofitted Maersk rig, the Integrator was deployed. The rigs utilize Siemens Blue-Vault lithium-ion battery storage system which is designed for offshore vessels. Siemens thinks that 300 of the world’s 500 ultra-harsh environment jack-up rigs can be outfitted with these hybridized features. They are also exploring powering with shore power.

     Electric fracking (E-frac) and other oilfield electrification applications can be considered to be hybrids. E-fracking often involves field-treated field natural gas powering gas turbines which in turn power efficient and powerful electric motors for pressure pumping. These are very high horsepower electric pumps that are integrated with digital energy management systems. These can be considered to be natural gas and electric hybrids. Energy management systems like those deployed by Equinor and Maersk for their rigs are also deployed in onshore drilling rigs to optimize power use with assistance from strategically deployed battery storage. The batteries charge when loads are low and discharge when loads are high and can eliminate the need for an extra generator. One such management system is made by EcoCell. It can charge when a rig makes a connection while the mud pumps are off and discharges when the mud pumps are running. Efficiency gains resulting in less energy use and less emissions are the result. Electrification is now utilized routinely and integrated with diesel and/or natural gas power in many different parts of drilling and completion of wells.

    

 

Hybridization in Power Generation

 

     As mentioned, a combined-cycle natural gas plant is a hybrid system where a gas turbine is paired with a steam turbine. There are many other possibilities with varying practicalities. One is simply a solar-plus-storage setup that can aid a homeowner in going “offgrid.” Solar-plus-storage is also used at utility-scale and more of these projects are being proposed to the interconnection ques. There are several other examples of hybrid power plants. Some plants that burn gas also retain coal units for use in cold snaps and others can burn fuel oil during cold snaps. Gas turbine plants can be paired with short duration battery assist. Several kinds of microgrids and combined-heat-and-power, or co-generation can be considered to be hybrids. Waste-heat recovery is a common feature. Hybrids pairing natural gas and renewables in microgrids of various sizes have been deployed. Solar, wind, or batteries are employed.

 

The following sections are excerpted from my 2022 book: Natural Gas and Decarbonization so may be just slightly outdated.   

 

Hybrid Gas Peakers with Battery Power for Start-up, Ramp-up, Spinning Reserve, and Lower Emissions: GE’s Hybrid Electric Gas Turbines

 

     In 2017 Southern California Edison and General Electric began operations on what GE calls hybrid electric gas turbine (EGT) units. The model is the LM6000 GE Hybrid Electric Gas Turbine (EGT). These were installed as 50 MW gas peakers with 10MW/4MWh of lithium battery power. Peaker plants are usually designated as “energy service’ resources, either ramped up or off but with added battery power they can provide “spinning reserve,” which is required for quick response. The batteries provide an ideal ramping resource for quick start and quick ramp-up. That allows the plant to respond quickly to short time signals in the 5 to 15-minute range. The batteries increase the flexibility of the plant quite a bit. The turbines run less since they are not required for the power consuming start-up and ramp-up processes. Thus, fuel use is reduced as are carbon and NOx emissions. It also makes these plants cost-effective to run as the batteries can be charged with lowest cost curtailed wind and solar generation. The quick start-up and quick ramp-up provided by the batteries also decrease maintenance costs compared to the turbines powering those functions. These plants can potentially make peaker plants more economic investments for utilities and since they also provide significant decarbonization that makes them attractive for company and regional decarbonization goals. The software-based digital controls and associated equipment can reduce both fuel use and water use and provide seamless operation. The SCE and GE project is expected to reduce greenhouse gas emissions and air pollution by 60%. These ‘digitalized’ gas plants show that gas turbines and energy storage can be quite complementary in optimizing plant function and increasing capacity factors, making such plants less likely to become stranded assets.^{[i] [ii]}

     At the end of September 2020, just a month or so after the California rolling blackouts, a similar gas peaker and battery hybrid plant with the same companies involved, the Stanton Reliability Center, began operations in the state. This one involves two 49 MW gas combustion turbines paired with two 10MW lithium batteries. Cost was $150 million with a 20-year resource adequacy contract. The California Energy Commission explained: “Stanton is designed to operate during periods of peak power demand, providing “greenhouse gas-free spinning reserve, high-speed regulation, primary frequency response, and voltage support with the combined response of the gas turbine and the battery storage system.”^[iii]

 

     Pintail Power’s Natural Gas Combined Cycle and Thermal Energy Storage Hybrid Systems

 

     Low utilization rates of thermal power plants, both coal and gas, leads to more emissions per unit of energy produced. Using these plants, most efficient for baseload operation, to follow and firm intermittent generation makes them more emissions intense as they may have to start a couple times in a day and start-up is emissions intense. One solution specifically for peaking plants is utilizing battery power for start-up as described in the previous section. Another is utilizing thermal storage by combining liquid molten salt thermal storage with natural gas combined cycle (LSCC). Peaking plants as simple-cycle plants with combustion turbines but no recovery of waste heat for a steam cycle can be outfitted. Pintail Power’s patented LSCC system utilizes combustion turbine exhaust heat. A big factor in the design is moving the boiler outside the gas stream, resulting in improved output and efficiency: “A key innovation is moving the boiler outside the gas path, reserving exhaust gas for heating feedwater to the boiler and superheating steam from the boiler. This increases the available steam flowrate by 2.5 to 3 times compared to conventional heat recovery steam generation, resulting in substantially higher steam cycle power output.” That is quite a boost for the steam cycle. This happens “due to the synergistic use of stored energy for evaporation and exhaust energy for sensible heating.” The LCSS system can yield about 50% improvements in plant heat rate. Redesigned flow parameters and a non-reheat steam cycle enable fast start-up and system readiness is designed to be enabled by curtailed renewables (which in places like solar-heavy California is most available just hours prior to solar generation drop-off in the typical evening duck curve). They market it as an optimal way to use curtailed renewables, provide resiliency by providing dispatchable generation, having a storage component that can provide islanding and reduced fuel costs and delivery for remote applications, and for reducing emissions considerably. The system can work with any turbine. Molten salt storage has long been used in concentrated solar plants and is considered proven safe and effective. “Rather than using solar salt, which freezes at 460F (238C), LSCC uses a lower freezing point 288F (142C) eutectic salt, such as the HITEC heat transfer and storage medium from Coastal Chemical. This mixture of water-soluble, inorganic salts of potassium nitrate, sodium nitrite, and sodium nitrate is safe, non-flammable, non-explosive, and non-toxic. It provides exceptional heat transfer performance in a low-cost, reliable, and compact system.” The salt is heated with electric heaters and stored in insulated carbon steel hot tanks with thermal losses less than 1 deg C per day. The electric heaters help the system provide demand response and frequency control to the grid, and temperature control for the system. System components like the flexible electric heaters and the molten salt steam generator for discharging are widely available on the market.

 

“A typical LSCC application requires about 12.25 metric tons of salt per MWh of delivered energy at a cost of roughly $2,000 per metric ton, or about $25/kWh, a fraction of the incremental cost of lithium batteries.”

 

“To minimize the cost of storage, three identical tanks are used in a round-robin scheme, alternately 2-hot/1-empty when fully charged and 2-cold/1-empty when fully discharged.”

 

“By combining low-cost electric charging, low-cost bulk storage media, and proven combined cycle equipment, LSCC can meet the $150/kWh target as a new-build system with a 12-hour duration, while adding LSCC to an existing plant can reduce the cost below $100/kWh. Further cost reductions can be achieved with larger-scale plants, two-pressure steam cycles, or by adopting solid thermal storage media that proponents claim would be lower cost than molten salt.”

 

     The key is the synergies provided by the hybrid model – the hybrid synergies. An analogy might be just as hybrid plug-in electric vehicles enable lower fuel use and emissions while solving range anxiety so too does a hybrid power system like Pintail’s LSCC or Liquid Air Combined Cycle LACC (see below) while solving renewables variability anxiety compared to renewables-only charged storage. In terms of levelized cost of storage (LCOS) this system can beat lithium battery costs by quite a lot, by about 50% according to Pintail. The ability to retrofit existing thermal power plants with LCSS is a key cost savings feature. The safety issues with lithium batteries are eliminated. The salt storage media is also expected to have a long lifetime without the degradation that occurs in batteries. There is also more flexibility in charging and discharging than with batteries. These advantages posit this technology as potentially disruptive to utility-scale battery storage at some point in the future.[iv]  To recap, the performance advantages for LCSS include less fuel usage, higher plant utilization rates, daily load following through discharging short-duration storage, emergency and event response capable of longer-duration storage, solve renewables curtailment issues, and reduce overall emissions. The emissions reduction advantage depends on plant utilization rate and how much power comes from curtailed renewables. Pintail just calls it low-carbon power. One might call these plants Combined-Storage-Heat-and-Power. They can be scaled for all sizes of microgrids. In sum “the LSCC integrates electrically- heated thermal energy storage with combustion turbine exhaust heat to boost power output and fuel efficiency, while also using the exhaust heat to boost storage efficiency.”[v]

     The LSCC system is quite applicable to places where there is high solar penetration and an abundance of natural gas peaking plant capacity like California. However, ideally it can be adapted where there is existing combine cycle(s) since retrofitting on an existing steam system would be cheaper than adding a new steam system. In 2021 an LSCC pilot plant is being designed possibly for deployment in North Carolina, another solar-heavy state. The project is a public-private partnership and collaboration between the National Energy technology Lab (NETL), utility Southern Company, Pintail Power, Electric Power Research Institute (EPRI), and Nextant ECA.[vi]  

     Pintail’s patented Liquid Air Combined Cycle system is another similar hybrid power plant with storage provided by air cooled to cryogenic temperatures and stored in above ground tanks. It is known as cryogenic thermal storage, or cold thermal storage. High-capacity energy storage and very long-duration energy storage of days to weeks are possible with liquid air. This would be applicable to address seasonal variability of solar generation especially, in places where it is heavy on the grid like California. The high energy capacity is due to the high energy density of liquid air. Both exhaust heat from turbines and the cooled air are used for energy conversion, which maximizes efficiency. The system utilizes widely available refrigeration components and cryogenic tanks and processes and equipment from the industrial gas and LNG industries. “There are two air streams involved in Liquid Air Combined Cycle: Air for cryogenic storage, and air for regasification. In addition, there is an Organic Rankine Cycle which elegantly bridges the hot and cold air streams by extracting additional energy during discharge.”[vii]

     Pintail also has a patented concentrated solar combined cycle (CCSC). This is similar to the LSCC but instead uses CSP for heat instead of electric heaters to charge the thermal storage. Utilizing a combustion turbine and its waste heat the CSCC is much more efficient than the integrated solar combined cycle (ISCC) used in CSP plants. It also provides better performance. It can be added on to existing CSP plants, increasing their value as grid assets.[viii]   

 

Supercritical CO2 Power Cycles Integrated with Waste Heat Recovery for Gas-Fired Generation and Many Other Thermal Applications

 

     Supercritical CO2 (sCO2) power cycles like those used in Allam Cycle and Brayton Cycle apps can also be used with or without oxy-fuel combustion and carbon capture. The STEP Demo in San Antonio is working with versions of the Brayton Cycle for sCO2. Any fuel or energy source can be utilized for heat. The supercritical CO2 cycle is very efficient. It can be used in industrial waste heat recovery and for shipboard propulsion. The sCO2 is utilized as a closed loop working fluid, above it’s critical point of 1070 psi and 88 deg F, in these applications. The fluid is cooled and recirculated. Compared to water sCO2 is a denser fluid. Since there is high fluid density at relatively low temperature there is less compressor work and more efficient compression. “The thermodynamic properties of sCO2 offer better efficiency than organic Rankine cycles at low temperatures and improved efficiency vs. steam Rankine cycles at turbine inlet temperatures exceeding 1000-1100 °F.” These cycles are in the process of being commercialized and components are being built.^[ix] “It is the unique properties of supercritical CO2 that offer intrinsic benefits over steam as a working fluid to absorb thermal energy, to be compressed, and to impart momentum to a turbine. This higher efficiency results in lower cost and lower emissions for the same amount of power produced.” Another interesting fact about sCO2 cycles is that the components such as heat exchangers and turbomachinery can be considerably downsized, up to 85% in the case of turbomachinery. This is a result of the high sCO2 fluid density. This saves space and reduces cost. The smaller components also help give the cycles a higher ramp rate, an improved response time for adapting to changing power load demands, adding flexibility and reliability. The STEP Demo is currently in an extensive test for demand response. Far smaller components, less fuel use, less water use, and a smaller footprint can reduce capital costs.^[x]

     The STEP Demo is adaptable and is testing different configurations to compare. This should yield some interesting results and new opportunities to both decarbonize and reduce costs. The early testing is of a simple recuperated configuration followed by a higher-temperature recompression cycle configuration. After this “The reconfigurable facility can be adapted to perform validation testing of alternative component designs, cycle layouts or control logic. The system may also be extended to include additional components (such as thermal energy storage, oxycombustion hardware) or to perform validation/qualification testing of full-scale waste heat recovery systems.” Relative to steam cycles, sCO2 cycles can increase power plant efficiency up to 10%. It is thought by some that this tech could revolutionize the power plant industry.^[xi] The key to sCO2 cycles having an effect on overall emissions will be widespread adoption. When scaled-up, costs of an sCO2 cycle are expected to be comparable to a steam cycle. sCO2 with waste-heat recovery is expected to be commercialized soon. The Allam Cycle pilot test facility in LaPorte, Texas, operational since May 2018, proved Allam Cycle viability. Several Allam Cycle projects in different areas have been announced and the STEP project has long been working on supply chain development for sCO2 cycles which should catalyze commercialization.

     The 10MWe STEP demonstration plant, a public-private partnership with current federal funding from DOE’s NETL of $115 million and $41 million in private funding, is expected to be up and running in 2022. Other partners in the project include Gas Technology Institute (GTI), Southwest Research Institute, and General Electric Global Research. It is an indirect sCO2 recompression closed Brayton cycle. One goal of the project is to “verify the performance of first-of-a-kind components—including its turbomachinery, recuperators, compressors, and seals—and demonstrate that they can operate at a turbine inlet temperature of at least 700C.” Potential future apps include concentrated solar, nuclear, waste-heat recovery, fossil energy, biomass, long-duration energy storage, closed-loop geothermal energy, and shipboard propulsion. The turbines can be less than one tenth of the size of equivalent output gas turbines which is advantageous in several ways. This is due to the much higher density of CO2 in a supercritical state compared to steam. GTI Senior Program Director John Marion gave an update of the project in October 2021 in an interview with Power Magazine’s Sonal Patel who has been following and writing about sCO2 cycles for a few years now: “Mechanical completion is expected in the spring of 2022. Commissioning and testing in a simple recuperated cycle system configuration is scheduled through 2022. The STEP demo system will then be modified to add additional heat recuperation and operate in an RCBC (Recompression Brayton Cycle) configuration to demonstrate the highest efficiency potential of the technology through 2023. This pilot is a fully operational electric generating power plant and testing is planned that will put power generated on a local grid. Extensive testing is planned to fully explore the operating envelope and confirm performance and control strategies.”^[xii]

     sCO2 power cycles are not new but have been explored for decades. CO2 has clear advantages as a working fluid over steam that result in better efficiency. Its density is nearly twice that of steam giving it a higher volumetric heat capacity which means turbomachinery and components can be less than one tenth in size of steam components. The energy requirements to increase temperature and pressure to get to a supercritical state, with properties of both gases and liquids, are relatively low. Power Magazine’s Sonal Patel, with help from Qian Zhu, an engineer and specialist on clean coal technologies at the IEA Clean Coal Centre, wrote an informative primer on sCO2 power cycles in April of 2019. Zhu noted that sCO2 is “considered an ideal working fluid because it is non-explosive, non-flammable, non-toxic, and relatively cheap.” The sCO2 power cycles are considered to be Brayton Cycles. This includes the special configuration that is the Allam-Fetvedt Cycle. The two types of Brayton cycles are indirectly fired closed-loop sCO2 Brayton Cycles and directly fired cycles. The Allam-Fetvedt Cycle is a direct fired cycle utilizing oxyfuel combustion where the exhaust heat is recycled to be used to re-heat the CO2 recycling system. One might call it a directly fired oxyfuel Brayton cycle with waste heat recovery to re-heat the CO2 recycling system. Among the indirectly fired types there is a simple closed-loop Brayton cycle, a recuperated closed-loop Brayton cycle, and a recuperated recompression closed-loop Brayton cycle. Ohio-based Echogen Power Systems developed a multi-stage recuperated closed-loop Brayton cycle that recovers heat from an industrial plant’s exhaust stream through an sCO2 heat exchanger. sCO2 power cycles lead to more efficient waste heat recovery and are applicable to many thermal energy projects. Directly fired cycles include semi-closed direct oxyfuel Brayton cycle and the Allam-Fetvedt cycle.^[xiii]

     Siemens Energy and Canada’s TC Energy are working on the first commercial deployment of an sCO2 power cycle at a pipeline compressor station in Alberta as mentioned. It is expected to be operational by 2022. They will utilize Echogen’s sCO2 waste heat recovery system which is essentially a heat engine – “the 7.5-MW EPS100—that uses a multi-stage recuperated closed-loop cycle, where heat from an industrial plant’s or gas turbine’s exhaust stream is recovered though an sCO2 heat exchanger. “The turbomachinery pumps the liquid CO2 to high pressure and passes through a combination of recuperators and waste heat exchangers (without using a secondary oil loop) before entering the turbo-expander, which drives the shaft that in turn drives a generator,” the company explained. “Effluent CO2 exits the turbine, and passes through a series of recuperators to exchange more heat, and finally enters the condenser where it is converted back to liquid CO2.” Siemens noted that this type of sCO2 power cycle is quite applicable to many oil and gas operations, including remote ones: “Benefits include a 25% to 40% smaller footprint than steam-based systems, a 10% increase in compressor station efficiency, and the capability to produce clean, emissions-free electricity, Siemens said. “Moreover, because the working fluid is contained within a closed-loop system, no boiler operator is required, making the system suitable for remote operation.” Thus, sCO2 power cycles have much potential to add value at reasonable cost while increasing efficiency and reducing carbon emissions and pollution. Widespread adoption can help decarbonize the oil and gas, power generation, industrial, and transport sectors. The increase in efficiency, especially as costs to deploy the tech come down is expected to help bottom lines too with the potential to make sCO2 waste heat recovery projects more economic than steam so that they will get built and be deployed. There are many candidates where waste heat is simply lost that could be recovered. Larger projects with more cost and emissions benefits are likely in the future.^[xiv]  

 

 

 

 

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[i] St. John, Jeff, April 18, 2017. Inside GE and SoCalEdison’s First-of-a-Kind Hybrid Peaker Plant with Batteries and Gas Turbines. GreenTech Media. Inside GE and SoCal Edison's First-of-a-Kind Hybrid Peaker Plant With Batteries and Gas Turbines | Greentech Media

 

[ii] Stewart, Kent, August 6, 2017. Digitalized Gas Plants and Battery Storage on the Grid: Integration, Collaboration, Competition, and Implications for Cost-Saving, Dealing with Demand Spikes, and Optimizing Gas Peakers. Blue Dragon Energy Blog. Blue Dragon Energy Blog: Digitalized Gas Plants and Battery Storage on the Grid: Integration, Collaboration, Competition, and Implications for Cost-Saving, Dealing with Demand Spikes, and Optimizing Gas Peakers

 

[iii] Hering, Garrett, September 22, 2021. Gas-battery hybrid peaker nears completion in capacity-hungry California. S&P Global Market Intelligence. Gas-battery hybrid peaker nears completion in capacity-hungry California | S&P Global Market Intelligence (spglobal.com)

 

[iv] Conlon, Bill, December 2, 2019. Decarbonizing with Energy Storage Combined Cycles. Power Magazine. Decarbonizing with Energy Storage Combined Cycles (powermag.com)

 

[v] Liquid Salt Combined Cycle. Pintail Power (website). Liquid Salt Combined Cycle – Pintail Power

 

[vi] Hume, Scott (EPRI), April 6, 2021. Liquid Salt CombinedCycle Pilot Plant Design. National Energy Technology Lab. EPRI Title Slide (doe.gov)

 

[vii] Liquid Air Combined Cycle. Pintail Power (website). Liquid Air Combined Cycle – Pintail Power

 

[viii] Concentrated Solar Combined Cycle. Pintail Power (website). Concentrated Solar Combined Cycle – Pintail Power

 

[ix] Allison, Timothy. STEP Advances Supercritical CO2 Power Cycles for Gas-Fired Generation. Pipeline & Gas Journal. July 2021, Vol 246, No. 7. STEP Advances Supercritical CO2 Power Cycles for Gas-Fired Generation | Pipeline and Gas Journal (pgjonline.com)

 

[x] Benefits of STEP Demo. Gas Technology Institute. Improve Efficiency, Lower Emissions in Commercial Energy Applications • GTI

 

[xi] A Step Toward Transformational Energy: Advanced Supercritical CO2 Power Cycles to Improve Efficiencies, Lower Emissions. Southwest Research Institute. Technology Today, Fall 2020. A STEP Toward Transformational Energy | Southwest Research Institute (swri.org)

 

[xii] Patel, Sonal, October 27, 2021. The POWER Interview: Pioneering STEP Supercritical Carbon Dioxide Demonstration Readying for 2022 Commissioning. Power Magazine. The POWER Interview: Pioneering STEP Supercritical Carbon Dioxide Demonstration Readying for 2022 Commissioning (powermag.com)

 

[xiii] Patel, Sonal, April 1, 2019. What Are Supercritical CO2 Power Cycles? Power Magazine. What Are Supercritical CO2 Power Cycles? (powermag.com)

 

[xiv] Patel, Sonal, April 1, 2021. First Commercial Deployment of Supercritical CO2 Power Cycle Taking Shape in Alberta. Power Magazine. First Commercial Deployment of Supercritical CO2 Power Cycle Taking Shape in Alberta (powermag.com)

 

Natural Hydrogen: Exploring for H2 Through the Drillbit: Reserves and Economic Estimations

 

     Until very recently, I was unaware as a geologist that hydrogen can occur in significant volumes as a natural reservoir gas to be able to be produced. Hydrogen has developed quite a color scheme: black = coal sourced; brown = biomass sourced; gray = natural gas sourced; blue = natural gas w/carbon capture; green = renewables powered electrolysis; turquoise = combo of renewables and blue H2 such as methane pyrolysis; pink = nuclear sourced; gold = H2 from wells in depleted oil reservoirs. Natural hydrogen has been proposed to be called ‘white hydrogen’.

     Hydrogen is the most abundant element in the universe. However, free hydrogen in nature at significant volumes has long been thought to be quite rare. It may not be as rare as thought. Hydrogen is quite reactive and diffuses quickly. Its high reactivity makes it seemingly less likely to occur in a pure gaseous form. That may not be wholly true. H2 has not been looked for or recorded in many chemical analyses of subsurface gases and it may occur in different conditions than hydrocarbons or mineral ores so many potential accumulations may be very much under-explored. It is thought that free hydrogen in the vicinity of hydrocarbon systems will become bound up with those hydrocarbons but may appear unbound where there are no hydrocarbon systems.  

 

“The processes that create natural hydrogen are not fully understood. It is found in a large range of geological settings – in oceanic and continental crust, volcanic gases and hydrothermal systems.”

     Mechanisms of subsurface hydrogen generation are thought to include:

● degassing of magmas and deep-seated hydrogen from the Earth’s core and mantle

● cataclasis

● oxidation of divalent iron (Fe2+) rich minerals and lithologies through rock-fluid interaction (e.g. serpentinisation); equivalent redox reactions may also occur using other multivalent elements such as sulfur, nitrogen and manganese

● natural radiolysis of water

● biogenic and abiogenic decomposition of organic matter

● a combination of coincident genetic factor

Hydroma’s website gives the four main means of generating hydrogen: serpentinization, radiolysis (separation of H2 from water), degassing from earth’s crust, and rock crushing along fault lines.

     It is found in some geothermal brines. Natural hydrogen can have both abiotic (non-life) and biogenic sources. Natural hydrogen has been ignored by explorers. However, it has been known to occur in non-negligible quantities in a few places for about a hundred years. It occurs in both sedimentary and igneous rock settings. It has yet to be determined if natural hydrogen occurs in quantities that can be commercially produced, aside from the accumulation in Mali, but it seems quite likely.

Global Locations of Natural Hydrogen Anomalies. Source: Current perspectives on natural hydrogen: a synopsis. Betina Bendall. Energy Resources Division, Department of Energy and Mining. MESA Journal 96, 2022 (37–46). Current perspectives on natural hydrogen: a synopsis (pir.sa.gov.au)

     One interesting factor in natural hydrogen exploration is that hydrogen can occur with associated helium, which is a commercial drilling target as well. The company Natural Hydrogen Energy, LLC, with offices in France and the U.S., is pursuing hydrogen and helium prospects. Helium is a rare gas and demand currently exceeds supply. The company believes they can produce both hydrogen and helium commercially.

     Hydrogen was known in the past from some natural seeps. There was a seep into a German salt mine in the early 1900’s that kept up a similar rate for several years. A groundwater aquifer in Mali in West Africa was known to contain H2 from the late 1980’s but in 2012:

 

“Hydroma Inc. (a Canadian company previously known as Petroma Inc.) re-discovered a hydrogen-rich aquifer in Bourakébougou, Mali and, moreover, managed to flow the natural hydrogen to the surface in commercial quantities.”

 

The hydrogen accumulation in Mali has a content of 98% H2. It is apparently trapped and sealed differently than local hydrocarbons so there may be differences in the trapping and sealing mechanism for hydrogen vs. hydrocarbons.

 

     In 2019 Natural Hydrogen. LLC drilled an exploration well in Nebraska, the Hoarty NE3, that reported hydrogen. Volumes are unknown but the well is apparently still being evaluated. The target is hydrogen sourced in Precambrian basement rocks. In nearby Kansas there have been hydrogen shows recorded:

 

“In Kansas, hydrogen is present in several zones within late Mississippian sandstone, siltstone and limestone units, and an artesian aquifer directly overlying the Precambrian basement. Gas pressures and chemistry in the various Kansas drillholes appear to vary temporally and can be influenced by restricting exchange between the aquifer and the basement (Coveney et al. 1987; Guelard et al. 2017), suggesting recharge from an active hydrogen flux which may be migrating up adjacent fault structures from a deeper source (Coveney et al. 1987; Guelard et al. 2017).”

 

     The hydrogen in Kansas and Nebraska is associated with the Mid-Continental Rift System, a long buried, failed rift system. Basement hydrogen outgassing is known around the world from active oceanic rift systems, ie. the Mid-Ocean Ridges. The H2 in Kansas occurs with N2, He, and occasionally CH4 (methane). The proposed mechanism for hydrogen generation there is “deep crustal H2: water reduction associated to iron oxidation in the Precambrian basement.” Some of the hydrogen was also thought to be generated by chemical reaction within the well-tubing which has high amounts of reduced iron and/or dissolved organic carbon in the water.

     Natural Hydrogen Energy, LLC seems to think that hydrogen reservoirs are fed in such a way that they will not deplete like hydrocarbons do after significant production. They estimate a production cost for natural hydrogen at $0.1-1 per kg. Associated helium production is also expected to improve economics.

     As noted, natural hydrogen can be generated in a number of geologic conditions. In the discovery in Mali the hydrogen was sealed by dolerite that formed a volcanic sill. From the article in Geoscientist magazine:

 

“Denis Briere introduced the concept of Hydrogen System Logic (as opposed to the traditional approach of Petroleum System Logic). Derived from his work on the Bourakébougou discovery in Mali, in the Hydrogen System Logic model the hydrogen reservoir is not a pressurised stagnant reservoir trapped under impervious shale barrier, but a slowly flowing accumulation being regenerated in the fractures and matrix. Natural hydrogen is periodically replenished via migration of hydrogen through fractures and then the subsequent diffusion into a host rock.”  

 

Host Rocks and Seal Rocks (Dolerite) in the Natural Hydroegn Accumulations in Mali, West Africa. Source: Hydroma's website: Activities – Natural Hydrogen – Hydroma

     It is not known whether hydrogen is stored as gas reservoirs over geologic time periods as oil and gas is. It is thought that salts/halite, intrusions like the dolerite sills in Mali, and clay-rich rocks like shales could act as hydrogen seals and barriers to migration. The Mali hydrogen accumulation is thought to be more than 8km in areal extent and to be producible from five stacked reservoirs. The potential of this prospect is that it will be cheaper to produce than to manufacture hydrogen, either through electrolysis or through fossil fuels. 24 wells were drilled in 2017-2019 to assess the accumulation. Hydroma began a new drilling campaign in Mali in May 2022. Thus far gas with over 95% H2 content has been recovered in all wells drilled.

     Hydrogen generation in the subsurface may be much different than that of hydrocarbons. Betina Bendall writes that:

 

“It is possible then that some natural hydrogen accumulations are long-lived dynamic systems resulting from continuous, diffuse generation of hydrogen approaching a steady state in the crust, similar to conductive geothermal systems, rather than static accumulations more akin to oil and gas fields. The permeability of individual rock layers and the presence of aquifers, together with subsurface hydrogen-fixing reactions, may mediate the balance between rates of migration from active generation sites and rates of continuous surface seepage.”

 

     Natural hydrogen exploration is taking off in some parts of the world but has yet to be supported at the level of decarbonized manufactured hydrogen, ie. blue and green hydrogen. There has been some legislative support in South Australia where several exploration wells have been permitted. High hydrogen content was found in gas samples in old wells. In two shallow wellbore examples hydrogen makes up to 84% of the gas which also contains nitrogen and lesser amounts of oxygen, CO2, and methane.

 

     “Bendall (2022) provides a recent synopsis of the geology of natural hydrogen occurrences and exploration methodologies. Potential exists for natural hydrogen plays in South Australia – Gaucher (2020) indicated that there are two main geological settings where hydrogen could be generated - Proterozoic crystalline shields and serpentinized ultramafic rocks in mid-ocean ridges and in land-based ophiolite-peridotite massifs. Potential natural hydrogen source rocks include ultrabasic rocks and iron-rich cratons (hydrogen generation from the oxidation of Fe(II) bearing mineral such as siderite, biotite, or amphibole by water) and uranium-rich basement with hydrogen generated by radiolysis of water (Gaucher, 2020).”  

 

     Salt/halite and possibly volcanic intrusives are considered the best seal rocks for hydrogen in South Australia. Despite H2 being a small molecule with low density it has a similar seal capacity to methane and better than CO2. This is, of course, why hydrogen can be successfully stored in underground storage reservoirs, particularly salt dome storage fields as exist in the U.S.

     Yet to be determined are reserves estimates of local and regional deposits and what the carbon intensity of drilling and producing natural hydrogen will be. Certainly, the carbon intensity will be far less than natural gas, since burning hydrogen produces no CO2 and there are no fugitive ghg emissions. One preliminary analysis suggests that it will be much less carbon intensive (4 times less) than even green hydrogen. That will depend on the production volumes and length of time the wells produce. However, the energy produced per well or per projects will likely be far less than natural gas and the energy content of hydrogen is also much less (about two-thirds) than that of natural gas.

     Betina Bendall offers the following guidelines for exploring for natural hydrogen:

 

● Target basement areas which contain Fe2+ -rich and/or uranium-rich rocks as these have potential for generating hydrogen via oxidation and radiolytic processes, respectively (e.g. Archean greenstone and Precambrian basement terranes).

● If these potential source areas are fractured and seismically active, then deep-seated faults can act to both channel migrating hydrogen from deeper sources to surface and introduce water downward for further chemical reaction with exposed Fe2+-rich rocks.

● A sedimentary overburden may enable entrapment of migrating hydrogen, particularly if aquifer systems and/or evaporites are present in the sedimentary sequence. Evaporites may also constitute a hydrogen source.

● Targets may be associated with surficial hydrogen seeps. Seeps can be blind or coincident with visible subcircular topographic depressions on the metre to kilometre scale, often associated with perturbed vegetation cover. Soil gas monitoring over extended periods can identify an active hydrogen flux.

● Routine monitoring for hydrogen in mines, and groundwater, oil and gas drillholes is a worthwhile practice which should be encouraged to bolster our understanding and existing records of natural hydrogen occurrences.

 

     Company HHe Exploration Technologies Ltd. Utilizes unmanned aerial systems (UASs), or drones, to detect methane, hydrogen, and helium in anomalous quantities. They utilize a combination of optical gas imaging (OGI) and ambient air analysis in tandem to detect minute hydrogen and helium anomalies. They have entered into joint venture agreements to explore the ambient air over certain areas, including South Australia.

References:

Natural hydrogen: the new frontier. Phillip J. Ball and Krystian Czado. Geoscientist. March 1, 2022. Natural hydrogen: the new frontier - GEOSCIENTIST

Hidden hydrogen might be the key to carbon-free fuel for future generations. Zeleb.es. The Daily Digest. MSN. Hidden hydrogen might be the key to carbon-free fuel for future generations (msn.com)

Hydrogen in Australian natural gas: occurrences, sources and resources. Christopher J. Boreham A C, Dianne S. Edwards A, Krystian Czado B, Nadege Rollet A, Liuqi Wang A, Simon van der Wielen A, David Champion A, Richard Blewett A, Andrew Feitz A and Paul A. Henson A. Journal of the Australian Petroleum Production & Exploration Association (APPEA). Vol. 61. July 2021. CSIRO PUBLISHING | The APPEA Journal

Natural Hydrogen. Government of South Australia. Natural hydrogen | Energy & Mining (energymining.sa.gov.au)

Current perspectives on natural hydrogen: a synopsis. Betina Bendall. Energy Resources Division, Department of Energy and Mining. MESA Journal 96, 2022 (37–46). Current perspectives on natural hydrogen: a synopsis (pir.sa.gov.au)

Natural H2 in Kansas: Deep or shallow origin? J. Guélard, V. Beaumont, V. Rouchon,09 F. Guyot, D. Pillot, D. Jézéquel, M. Ader, K. D. Newell, E. Deville. Geochemistry, Geophysics, Geosystems. Volume18, Issue5. May 2017. Pages 1841-1865. Natural H2 in Kansas: Deep or shallow origin? - Guélard - 2017 - Geochemistry, Geophysics, Geosystems - Wiley Online Library

Discovery of a large accumulation of natural hydrogen in Bourakebougou (Mali). Alain Prinzhofer, Cheick Sidy Tahara Cissé, Aliou Boubacar Diallo. International Journal of Hydrogen Energy. Volume 43, Issue 42, 18 October 2018, Pages 19315-19326. Discovery of a large accumulation of natural hydrogen in Bourakebougou (Mali) - ScienceDirect

Press release from Hydroma Inc. August 6 2022. New Natural Hydrogen Drilling Campaign at Bourakougou. Hydroma-Press-Release-August-6th-2022-EN-.pdf

NATURAL HYDROGEN ENERGY LLC – PIONEER OF HYDROGEN EXPLORATION. Key Player’s Insights. H-Nat Summit 2022. Natural Hydrogen Energy LLC – pioneer of hydrogen exploration | H-NAT SUMMIT (hnatsummit.com)

CAN WHITE HYDROGEN SOFTEN NET ZERO’S INCONVENIENT TRUTH? Key Player’s Insights. H-Nat Summit 2022. Can white hydrogen soften net zero’s inconvenient truth? | H-NAT SUMMIT (hnatsummit.com)

HHE JUNE 2022 NEWSLETTER. Key Player’s Insights. H-Nat Summit 2022. HHe June 2022 Newsletter | H-NAT SUMMIT (hnatsummit.com)

Emissions Control Systems at Coal-Fired Power Plants, Rules that Require Them, and Marketable Byproducts

 

     Combustion at coal-fired power plant produces many potentially toxic pollutants including heavy metals (mercury, arsenic, cadmium, chromium, selenium, uranium, and more) and criteria pollutants (lead, NOx, SO2, ozone, carbon monoxide, and particulate matter). Other processes at the plants produce different products requiring environmental remediation, including fly ash, bottom ash, and various effluents and sludges. Criteria pollutants from coal-fired plants are regulated at certain levels under the Clean Air Act. MATS, or mercury and air toxics are regulated at certain levels under the MATS rule. While there are other methods for pollution abatement than listed here, I am focusing on the most used methods.

Overfire Air Systems to Reduce NOx: Combustion-Based NOx Control

     Nitrogen oxides (NOx) is a precursor to ozone and is a major source of air pollution. Over-fire air systems can reduce NOx by up to 60% or more. Air is injected into the combustion zone of a coal, oil, or gas burner to enhance combustion. Combustion air is diverted from the burners to make a fuel-rich zone in the lower furnace. Fuel-bound nitrogen conversion to NO is inhibited. The result is less NOx released into the atmosphere. Each individual coal combustion system is modeled with computational fluid dynamics (CFD) to maximize combustion air penetration and optimize NOx reduction. Overfire air systems are typically used in conjunction with low NOx burners and flue gas recirculation. It is also known as fuel-air staging where 20-30% of the air is redirected utilizing various oriented ports and sometimes boosters to increase pressure.

Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR): Post-Combustion NOx Control Where Ammonia or Urea is Injected with or without a Catalyst to form N2 and H20

     With SNCR and SCR the reagent, ammonia or urea, is injected into the post-combustion flue gas. In SCR systems the reagent is injected upstream of the catalyst bed. SCR systems offer the highest NOx reductions but also the highest cost. They are customized to optimize based on system sizes and configuration, temperatures, and fuel conditions. These systems can be paired with an ammonia production facility. Ammonia can be made on-site as needed from urea derived from fertilizer production.

NOx Emissions Control. Source: EES Corporation

Electrostatic Precipitators and Baghouses for Removing Fly Ash Particles

     Electrostatic precipitators (ESPs) can remove more than 99% of fly ash particles produced by coal combustion. The fly ash in the combustion exhaust passes through electrically-charged plates which pull the particulates out of the flue gas stream. Low NOx burners lead to higher carbon content in fly ash. That can change the parameters of operation. Dry electrostatic precipitators can remove more than 99% of particulates but adding a wet electrostatic precipitator can remove some of the toxic gases and aerosols that a dry ESP misses. Wet ESPs are common in the metallurgy industry. According to Dilip Kumar and Deepak Kumar in their 2018 book ‘Sustainable Management of Coal Preparation’, “Particles passing through the precipitator are given a negative electrical charge by being forced to pass through a region, called a corona, in which the gas ions flow. Once the particle has been negatively charged, it is forced to the positively charged plate. Particles are removed from the plate by a knocking action.” ESPs require very little maintenance and have low operating costs. Wet ESPs are smaller than dry ESPs. Dry ESPs are more energy efficient than wet ESPs. Wet ESP’s can also address the formation of sulfur dioxide (SO2) sulfur trioxide (SO3) and sulfuric acid mist (H2SO4) as we will see in the next section.

     A baghouse is basically a very large fabric bag that acts as a filter to collect dust or fly ash. They typically capture 99% or more of particulates. The felt or woven fabric collects dust via four methods:

“Inertial collection – Dust particles strike the fibers placed perpendicular to the gas-flow direction instead of changing direction with the gas stream.

Interception – Particles that do not cross the fluid streamlines come in contact with fibers because of the fiber size.

Brownian movement – Submicrometre particles are diffused, increasing the probability of contact between the particles and collecting surfaces.

Electrostatic forces – The presence of an electrostatic charge on the particles and the filter can increase dust capture.

A combination of these mechanisms results in formation of the dust cake on the filter, which eventually increases the resistance to gas flow. The filter must be cleaned periodically.

Baghouses are classified by the cleaning method used. The three most common types of baghouses are mechanical shakers, reverse gas, and pulse jet.”

 

Flue Gas Desulfurization (FGD): Wet Scrubbers Utilizing Jet Bubbling Reactors and Spray Towers for Removing Sulfur Dioxide (SO2)

     Sulfur dioxide is the main sulfur compound released from coal burning power plants. It is a toxic pollutant. It is an acid gas. It is also responsible for what is known as acid rain, where acidic deposition into streams, lakes, and soils is the result down wind and down weather. About 85% of flue gas desulfurization systems installed at U.S. coal-fired plants are wet scrubbers. Wet scrubbers achieve the highest levels of SO2 removal at over 90%. The process is sometimes referred to as wet limestone flue gas desulfurization. The flue gas is passed through a limestone and water slurry. The limestone acts as a sorbent to collect the acid gas SO2. The products after pass through are CO2 and calcium sulfite (CaCO3). The basic reaction is as follows:  CaCO3(s) + SO2(g) → CaSO3(s) + CO2(g). If hydrated lime is used as the sorbent the reaction is as follows: Ca(OH)2(s) + SO2(g) → CaSO3(s) + H2O(l). The CaCO3 may be further oxidized to make marketable gypsum as a byproduct to be used mainly for drywall in the building industry and as a soil amendment in agriculture. That reaction, known as forced oxidation, is as follows:  CaSO3(aq) + 2H2O(l) + 1/2O2(g) → CaSO4·2H2O(s). The following is from Wikipedia:

 

“Types of wet scrubbers used in FGD”

“To promote maximum gas–liquid surface area and residence time, a number of wet scrubber designs have been used, including spray towers, venturis, plate towers, and mobile packed beds. Because of scale buildup, plugging, or erosion, which affect FGD dependability and absorber efficiency, the trend is to use simple scrubbers such as spray towers instead of more complicated ones. The configuration of the tower may be vertical or horizontal, and flue gas can flow concurrently, countercurrently, or crosscurrently with respect to the liquid. The chief drawback of spray towers is that they require a higher liquid-to-gas ratio requirement for equivalent SO2 removal than other absorber designs.”

“FGD scrubbers produce a scaling wastewater that requires treatment to meet U.S. federal discharge regulations.[16] However, technological advancements in ion-exchange membranes and electrodialysis systems has enabled high-efficiency treatment of FGD wastewater to meet recent EPA discharge limits.[17] The treatment approach is similar for other highly scaling industrial wastewaters.”

Fly ash removal as covered above is considered a part of the FGD system but is usually separate from the wet scrubbers. Fly ash is removed first. Then the flue gas is passed through a sorbent that removes over 90% of the SO2. The remaining SO2 in the water slurry can cause corrosion in downstream equipment so the gases may be heated above their dew point and/or material that resists corrosion can be used in some parts of the system. That material is typically fiberglass reinforced plastic.

     Spray towers are typical coal-fired power plant wet scrubber designs as are jet bubbling reactors. Spray towers are simple in design and easy to keep operational. Jet bubbling reactors can remove up to 98% of SO2. They have to be monitored for corrosion potential. Utilization of fiberglass reinforced plastic replacing metal helps in some parts of the system. They are more expensive to install and operate but selling the gypsum to the building and agricultural industries can help offset that extra cost.  

     According to Daniel Valero’s Fundamentals of Air Pollution (5^th edition 2014):

 

   “Wet-scrubbing controls acid gases, metals, PM, and semivolatile organic compounds (SVOCs), e.g. chlorinated dioxins and furans. Single-stage scrubbers can be used to remove acid gases. Two-stage scrubbers can be used for acid gases and metals. Three-stage systems having a two-stage scrubber followed by a high-efficiency wet particulate control system are designed for improved control of fine particulates, metals, and SVOCs. Single-stage scrubbers can also be installed following other pollution controls for increased pollutant control (i.e. polishing scrubbers).”

 

     Wet scrubbers of most types produce large amounts of wastewater that must be treated before it is released back into the environment. This is relatively easy to do with modern technologies but adds to costs. Wet scrubbers can also remove oxidized mercury.

     Other types of wet scrubbers like the venturi scrubber have been used for droplets and mists of sulfuric and phosphoric acids. These work effectively but require high energy inputs. They also may condense volatile gases which may increase opacity in the local sky.

     There is even a new technology being explored for simultaneous NOx and SO2 removal. It is a “combined spray-and-scattered-bubble technology based on preozonation compared with spray or jet bubble reactor technology, with removal efficiency increased by as much as 17%, for the spray column and 18% for the bubble reactor for NOx and 11% for the spray column, and 13% for the bubble reactor for SO2, for liquid/gas ratio of 4 dm3/m3 or immersion depth of 100 m.” Liquid/gas ratio reflects the total amount of water required. Energy consumption in this tech is 10% less than spray tech. As of 2019 this was moving from lab stage to pilot stage of development.

 

Automated Continuous Emissions Monitoring Systems (CEMS)

    Automated Continuous Emissions Monitoring systems are used in the smokestacks to monitor stack gas emissions. Theses systems are used to confirm compliance with clean air requirements for SO2 and NOx emissions and opacity.

 

Coal Ash Processing Systems

     Coal ash is processed with two main types of coal ash handling systems in order to transfer the ash from boilers to storage units. Coal combustion residuals include several types of solids: fly ash, bottom ash, boiler slag, and flue gas desulfurization material such as gypsum. Fly ash is light ash that flies out with flue gases as part of the ‘smoke’ of combustion. This is what ESPs capture. Bottom ash is in solid form and accumulates in ash hoppers below the boilers. It is non-combustible. It must be ground down. Fly ash handling systems direct the fly ash through abrasion resistant heavy-duty steel from the flue to lockhoppers and bins. It is then processed through feeders and pumps to ‘beneficiation’ equipment that preps it for use in blocks and cement. It is then transferred to loading facilities. Bottom ash handling systems involve scraping the sides and bottoms of boilers into hoppers below then crushing it into manageable sizes. It is then transferred via conveyer to another crusher which makes it smaller yet and ready to be transferred to storage units. In the mid-2000’s most coal ash handling systems changed from wet to dry since dry systems are more environmentally benign. About two thirds of fly ash handling systems in the U.S. are now dry systems. Bottom ash handling systems are still mostly wet but new EPA CCR rules will lead to many more dry systems. Recirculation systems can convert wet sluice assemblies into dry ash systems quickly. The recirculation system is intended to reduce the moisture content of the ash while re-using the water for additional cycles. This wet-to-dry conversion can save millions of gallons of water use.

Some Byproducts from a Coal-Fired Plants

     As mentioned, one of the byproducts from flue gas desulfurization at a coal-fired plant may be gypsum for the building and agricultural industries. Another may be slag left over in the boilers. Slag may be sold to be used in shingle manufacturing and for the blasting grit markets. A sellable byproduct becoming more common is the coal ash itself after collection to be used in composite construction materials and for other uses. Coal ash recovery systems at power plants are utilized to treat or prep the ash before sale. Two types of beneficial use of fly ash are in encapsulated and unencapsulated forms. Encapsulated coal ash is coal ash that has been encapsulated into building products like bricks, concrete, wall board, or roofing materials in such a way as it cannot escape into the environment. The EPA reports that in 2018, 13.4 million tons of fly ash were used in concrete/concrete products/grout making up a little over 30% of coal ash use. Nearly another 30% of coal ash beneficial use was used in making gypsum during flue gas desulfurization that may be encapsulated into wall board. In 2013 EPA developed a methodology to evaluate encapsulated (and unencapsulated) coal ash so that products must be demonstrated to release equal or less pollutants into the environment than existing products used for those purposes. They determined that replacing Portland cement in concrete with fly ash can have net environmental benefits. Coal ash beneficial use in an unencapsulated form as dry particles or as a sludge has been used mainly for structural fills/embankments. The same EPA rule applies to unencapsulated coal ash. Use of unencapsulated coal ash makes up 20% of coal ash beneficial use.

 

Coal-fired Plant with Emissions Control Systems and Wastewater Streams. Source: U.S.EPA

U.S. EPA Coal Combustion Residuals (CCR) Guidelines

     According to the EPA:

“Coal ash, also referred to as coal combustion residuals or CCRs, is produced primarily from the burning of coal in coal-fired power plants.  Coal ash includes a number of by-products produced from burning coal, including:

1)    Fly Ash, a very fine, powdery material composed mostly of silica made from the burning of finely ground coal in a boiler.

2)     Bottom Ash, a coarse, angular ash particle that is too large to be carried up into the smoke stacks so it forms in the bottom of the coal furnace.

3)     Boiler Slag, molten bottom ash from slag tap and cyclone type furnaces that turns into pellets that have a smooth glassy appearance after it is cooled with water.

4)     Flue Gas Desulfurization Material, a material leftover from the process of reducing sulfur dioxide emissions from a coal-fired boiler that can be a wet sludge consisting of calcium sulfite or calcium sulfate or a dry powered material that is a mixture of sulfites and sulfates.

Other types of by-products are:

  )     fluidized bed combustion ash,

6)     cenospheres, and

7)     scrubber residues.”

     Coal ash is potentially very dangerous stuff with concentrated levels of carcinogens and several toxic heavy metals. Coal ash impoundments are required to have groundwater monitoring wells around them since many such monitoring wells continue to detect troubling levels of pollutants in nearby groundwater. More data provides more accurate and more conclusive determinations of contaminant pathways. The CCR Part B Final Rule was published on November 12, 2020. It gives facilities the option to demonstrate to EPA that, “based on groundwater data and the design of a particular surface impoundment, the operation of the unit has and will continue to ensure there is no reasonable probability of adverse effects to human health and the environment. EPA approval would allow the unit to continue to operate.” On January 25, 2023 the EPA denied six facilities permission to continue current CCR disposal. The reasons given were:

1)     Inadequate groundwater monitoring networks.

2)     Failure to prove groundwater is monitored to detect and characterize any elevated levels of contaminants coming from the coal ash surface impoundment.

3)     Evidence of potential releases from the impoundments and insufficient information to support claims that the contamination is from sources other than the impoundments.

4)     Inadequate documentation for the design and performance of the impoundment liners.

5)     Failure to meet all location restrictions.

Again according to the EPA the CCR rule finalized in 2020 requires liners for coal ash impoundments that plan to continue receiving coal ash:

“The court vacated provisions that allowed unlined impoundments to continue receiving coal ash unless they leak, and classified “clay-lined” impoundments as lined, thereby allowing such units to operate indefinitely. In addition, EPA is establishing a revised date by which unlined surface impoundments must cease receiving waste and initiate closure, following its reconsideration of those dates in light of the USWAG decision. Lastly, EPA is finalizing amendments proposed on August 14, 2019, to the requirements for the annual groundwater monitoring and corrective action report and the requirements for the publicly accessible CCR internet sites.”

 

U.S EPA Effluent Limitation Guidelines (ELG)

     The EPA plans to strengthen wastewater discharge standards from coal-fired power plants. Three wastewater streams: flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate are targeted. According to the EPA:

“Coal-fired power plants discharge wastewater containing pollutants into our nation’s waters. The discharges include toxic and bioaccumulative pollutants such as selenium, mercury, arsenic, and nickel, halogen compounds such as bromide, chloride, and iodide, nutrients, and total dissolved solids. These pollutants can contaminate drinking water sources, recreational waters, and aquatic life. In people, health risks may include cancer and non-cancer effects and, in children, lowered IQs. In fish and wildlife, the pollutants may cause deformities and reproductive harm. Many of these pollutants can remain in the environment for years.”

EPA estimates that the new effluent limitations rule will lead to a reduction of 584 million pounds per year of these pollutants.

 

References:

Over-Fire Air (OFA) Systems: Deep-Staging for Maximum NOx Reduction. Fuel Tech. FT-109230_OFA.pdf (ftek.com)

Combustion-based NOx Control. EES Corporation. Combustion-based NOx Emission Control | EES Corp

Sustainable Management of Coal Preparation. Dilip Kumar and Deepak Kumar. 2018. Elsevier.

Electrostatic Precipitator. Wikipedia. Electrostatic precipitator - Wikipedia

Baghouse: Wikipedia. Baghouse - Wikipedia

Wet Scrubber. Wikipedia. Wet scrubber - Wikipedia

Coal Ash Basics: U.S. EPA. Coal Ash Basics | US EPA

Fundamentals of Air Pollution. 5^th Edition. Daniel Valero. Academic Press. 2014.

Coal Ash Reuse: U.S. EPA. Coal Ash Reuse | US EPA

A Primer on Coal Ash Handling Systems. Process Barron.  A Primer on Coal Ash Handling Systems | ProcessBarron

Steam Electric Power Generating Effluent Guidelines - 2023 Proposed Rule. U.S. EPA. Steam Electric Power Generating Effluent Guidelines - 2023 Proposed Rule | US EPA

Simultaneous removal of SO2 and NOx by a new combined spray-and-scattered-bubble technology based on preozonation: from lab scale to pilot scale. Tong Si, Chunbo Wang ,Xuenan Yan, Yue Zhang, Yujie Ren, Jian Hu, Edward J. Anthony. Applied Energy, Volume 242, 15 May 2019, pp. 1528-1538. *Microsoft Word - Si et al (cranfield.ac.uk)

Fiberglass plastics in power plants. D. Kelly. Power Engineering (Barrington) Journal Volume: 111; Journal Issue: 8; Journal ID: ISSN 0032-5961. 2007. Fiberglass plastics in power plants (Journal Article) | OSTI.GOV

Wet Flue gas Desulfurization System. Ohio’s Electric Cooperatives. Cardinal Operating Company WFGD System FactSheet.pdf (firelandsec.com)

Hazardous and Solid Waste Management System: Disposal of Coal Combustion Residuals From Electric Utilities; A Holistic Approach to Closure Part A: Deadline To Initiate Closure. U.S. EPA. August 28, 2020. Federal Register :: Hazardous and Solid Waste Management System: Disposal of Coal Combustion Residuals From Electric Utilities; A Holistic Approach to Closure Part A: Deadline To Initiate Closure