December 2023Heat Transfer—Malhotra (S&B Engineers and Constructors)

HP Tagline--Heat TransferDesign considerations and decarbonization options for fired heatersK. Malhotra, S&B Engineers and Constructors, Houston, TexasAs greenhouse gas (GHG) emissions policies and regulations become more stringent, carbon dioxide (CO₂) emissions have taken center stage, with many nations targeting net-zero carbon emissions. Fired heaters are a significant source of these emissions, as they utilize fossil fuels, resulting in high carbon emissions. Industry is researching and deploying viable carbon-mitigating options as they become more mature, well-understood and established.It must be noted that most fired equipment in existing plants utilize fossil fuels. Selection of the most suitable decarbonization options should be based on existing plants’ infrastructure, fuel option availabilities, potential fired heater efficiency improvements and carbon capture viability. In some cases, electric heaters could help minimize process loads from fired heaters. Cost and long-term sustainable operations are key factors in determining the best combination of decarbonization options for a plant. FIG. 1 summarizes the options being considered for the decarbonization of fired heaters. Some technologies are in experimental studies but could be viable options in the future (e.g., ammonia fuels, oxy-firing).Malhotra Fig 01Heater efficiency improvement. As a first step toward the decarbonization effort, heater efficiency improvement options should be evaluated. Since many of these require only minimal modifications, this pathway is much easier to achieve. This could be a combination of higher heater efficiency achieved by either improving process heat recovery or by adding air-preheat. This includes fuel heating or a better tuned heater with minimal tramp air leakage. FIG. 2 shows the heater efficiency gain for a tuned heater as a function of stack temperature and excess oxygen. FIG. 3 shows the relative CO₂ emissions reduction (by percentage) for a process heater running on natural gas. Depending on the efficiency of the furnace, significant CO₂reductions are available with efficiency improvements. Malhotra Fig 02Malhotra Fig 03Design considerations for heater efficiency improvements. The following are several design considerations to increase heater efficiency:

Environmental triggers—Required heater modifications may trigger environmental permit compliance needs, necessitating best available control technology (BACT). Personnel should work closely with environmental authorities on any heater modifications, especially if additional permits are needed.

Acid dewpoint considerations—Most heater efficiency improvement projects involve extracting heat from exit flue gas, thus lowering flue gas temperatures. Based on the fuel’s sulfur content and corresponding flue gas acid dewpoint condensation, all cold metal temperatures must be evaluated for the adequate design of the furnace from design to turndown conditions. If the heater is equipped with selective catalytic reduction (SCR), salt-formation temperatures of ammonium sulfate and bi-sulfate should be considered.

Emissions checks—If installing an air preheater or if considering fuel preheat or other heater modifications, nitrous oxide (NO_x) and carbon monoxide (CO) emissions must be reconfirmed with the burner vendors to ensure environmental compliance. The impact of increased air temperature on fuel temperature must be evaluated by the burner’s supplier.

Heater evaluation—The heater should be evaluated with regard to the new conditions to ensure adequate design operation and turndown conditions.

Cost drivers—Pre-turnaround (pre-TAR) activities should be prioritized, and modularization should be maximized to ensure the lowest TAR costs and improved schedule.

Low-carbon fuel blend options. Fuel blending is an effective option that must be evaluated when considering the decarbonization of fired heaters. As a primary step in fuel blending, if the heavy hydrocarbons in the fuel can be substituted with higher hydrogen (H₂)-by-carbon (H₂/C) fuel, it can result in a noticeable reduction in CO₂. FIG. 4 shows a comparative chart on CO₂reduction with high H₂/C fuels relative to methane (CH₄).FIG. 5 shows CO₂ reduction in a blend of CH₄ and H₂ with increasing H₂content and a corresponding reduction (percent) in CO₂ emissions.Malhotra Fig 04Malhotra Fig 05Design considerations for fuel-blending options. The following are several design considerations for fuel blending:

Nitrogen oxides (NO_x) emissions—Fossil fuel blending with high H₂/C fuels will typically result in increased NO_x emissions; however, each case can be different. The burner supplier must verify the adequacy of installed burner tips, or potentially replace them and advise if any other burner changes are needed. This usually involves a burner test to check for flame stability and emissions. New burner curves must be developed, and alarm and trip setpoints must be adjusted.

Environmental triggers—Environmental authorities will need to advise if the required modifications trigger environmental permit compliance needs.

Area classification—Area classification must be checked, specifically if carbon-free fuels (e.g., H₂) are being utilized for blending. This can result in increased instrumentation scope.

Safety instrumentation—Safety instrumentation system (SIS) trips requiring CH₄ as the identifying trip function in the heater bridge wall (flue gas instrumentation) must be evaluated. Typically, CH₄ analyzers work with a very high H₂ content in the fuel gas, but it still must be evaluated. As an alternative, an ultraviolet/infrared (UV/IR) flame scanner can be used to identify flame loss.

Heater evaluation—The heater should be evaluated for the new fuel gas composition to ensure adequate design operation on both design and turndown scenarios.

Cost drivers—Pre-TAR activities should be prioritized for potential cost savings.

Carbon-free fuel options. Among the carbon-free fuel options being considered, 100% H₂ as a fuel has made significant progress in fired heaters. H₂ burners have been tested, and existing field installations have shown promising burner performance. The vast majority of H₂ production is achieved through steam methane reforming, which utilizes CH₄ and steam with higher temperatures and pressures to produce H₂—gray H₂is essentially the same as blue H₂ but without the use of carbon capture and storage (CCS). Electrolysis technology is making progress to achieve higher H₂production efficiency. Electrolysis consists of breaking water molecules by using an electric current in an electrolyzer to extract H₂. The electricity must be generated through a carbon-free pathway (e.g., solar, wind) to be labeled green or renewable. However, ammonia has also gained attention as a H₂energy carrier, as it can be liquefied at low pressures with ambient temperatures and transported more efficiently than H₂, whichneeds cryogenic temperatures and extremely high pressures for liquification. Cryogenic temperatures can cause potential steel embrittlement and a concern for shipment. Ammonia has a long history of production and transportation, making it a viable source as a H₂carrier and also as a potential source of direct fuel for combustion. Ammonia as a fuel is being extensively studied in the power generation industry. Studies are being planned for its viability and practicality as a potential future direct fuel source for fired heaters. TABLE 1 shows a comparison of heater performance (100 MMBtu/hr process absorbed duty) of natural gas with carbon-free fuels (H₂ and ammonia). It must be noted that TABLE 1 is presented for information purposes. Each process type, process condition and heater type must be evaluated individually.Malhotra Table 01Merits of carbon-free fuels. The following are some of the benefits associated with carbon-free fuels in fired heaters:

Emissions—Carbon emissions elimination is the most significant benefit of utilizing carbon-free fuels in burners. The following emissions merits are achievable:

Carbon emissions (CO/CO₂): Negligible

Sulfur oxide (SO_x) emissions: Negligible

Volatile organic compounds (VOC) emissions: Negligible

Particulate matter (PM) emissions: Negligible

Pilots may still utilize a fossil fuel or a fossil fuel blend (tested up to a maximum of 90%–95% H₂), which will contribute to some negligible carbon emissions.

Improved heater efficiency—Nearly all fossil fuels have sulfur components, which can condense out as sulfuric acid in flue gas on the coldest portion of metals (when metal temperatures get below the acid dewpoint). Acid dewpoints can vary, depending on the amount of sulfur in the fuel gas. This can adversely affect heater efficiency, especially when utilizing air preheat, where the air inlet minimum tube metal temperatures witness acid dewpoint, especially at turndowns. To avoid acid dewpoint, exit flue gas temperatures must be increased, thereby compromising heater efficiency. Ammonium sulfate and bi-sulfate salts are concerns that may also limit heater efficiency when fossil fuels utilize ammonia for SCR.

Stack height—Apart from the minimum draft requirements, on most occasions, the stack height is dictated by the environmental dispersion analysis. With negligible PM and VOC emissions, stack height requirements can be reduced significantly, which will result in reduced project cost.

Tax credit advantages—The U.S. Inflation Reduction Act (IRA) provides tax credits for clean H₂ production and reduced GHG emissions. These incentives could benefit project costs for the long-term operation of carbon-free fuels.

Design considerations for H₂ fuel. When considering H₂ as a fuel, a few design considerations must be evaluated:

Heater performance—H₂ fuel results in a higher radiant flux compared to that of natural gas, with an overall increase in heater efficiency when compared to natural gas fuel. TABLE 1 provides more details on the heater performance comparison to natural gas. A detailed heater analysis should be conducted for each specific process and heater type for both the design and turndown cases for adequate heater performance.

Flame profile and NO_x—In general, combustion relies on time, temperature and turbulence. H₂ burners benefit from the higher flame temperature, and higher flame speeds contribute to faster time and turbulence of combustion, which helps to reduce the flame profile. However, higher adiabatic flame temperatures increase NO_x emissions by 25%–40%, and this increase depends on burner design and heater operating conditions. Some promising research shows that new H₂ burners can be designed—with certain burner and heater modifications—to reduce NO_x emissions.

Flame profile determination—H₂ has compact flame patterns approximately 20%–25% smaller than that of natural gas. However, depending on each case, H₂burners may need to be designed to start up with natural gas or with an alternative fuel in an upset scenario if H₂ is unavailable. Testing a burner with natural gas will provide the maximum flame dimensions. The flame dimensions for natural gas can be determined utilizing convectional CO (1,500 ppm–2,000 ppm CO set as flame boundary) probing to determine the flame boundaries for a burner. Computational fluid dynamics (CFD) is another approach that can provide a comprehensive view of the heater flame profile utilizing all H₂fuel.

Fuel gas train and burner modifications—Burner components can be modified to operate on 100% H₂; however, each burner must be evaluated to determine if this method is achievable. The following burner components will be modified:

Burner tips with new drillings and angles must be designed for adequate burner performance. Burner curves will be revised.

Burner tiles will likely be changed to accommodate the revised tips/burner design needs, as convectional tiles may tend to crack. Note: If the existing burner components cannot be modified, a new fully H₂-fueled burner is always an option.

The fuel gas train must be evaluated for pressure drop and control valves, among other items. TABLE 1 shows that the volumetric flowrate of H₂increases by three times that of natural gas. Gasket materials suitable for H₂fuel must be evaluated to reduce any potential leaks.

Burner design for H₂ and other fuel gases—If the burner is to operate on 100% H₂or some other alternative fuel gas, this must be considered in the design.

Noise may be a concern for all H₂burners. Achieving 85-dBA noise guarantees may be a challenge, and this must be discussed early in the project with both the vendor and client(s). There may be a need for double hearing protection around these burners.

Area classification must be checked for all H₂fuel. This can result in instrumentation scope.

SIS trips—Using instrumentation, SIS trips must be evaluated (e.g., a CH₄ analyzer as an identifying trip function). Since H₂is a carbon-free fuel source, identifying the flame loss will be accomplished through UV/IR flame scanners or alternative analyzers/instrumentation.

Pilots have been tested for high H₂fuels (up to 90%–95% H₂). UV/IR flame scanners can be utilized for flame identification.

Metallurgy—With H₂as a fuel and depending on if the burner is being designed for alternative hydrocarbon fuels, ASME B31.3 or ASME B31.12 compliance on piping may need to be discussed upfront in the project. With H₂fuel gas temperatures in burners being less than 400°F, a vast array of metallurgy options are available.

Design considerations for ammonia fuel. Ammonia has gained significant attention as a H₂energy carrier, as it can be liquefied and transported more easily than H₂. As research is being conducted on using ammonia as a fuel for combustion in the power generation sector, studies are being planned for the use of ammonia in fired heaters. The following are design considerations that must be accounted for when considering using ammonia as a direct fuel for fired heaters:

General combustion characteristics—Ammonia has a low velocity (about five times lower than natural gas), which makes it a sluggish fuel to burn. In addition, ammonia has a narrow flammability limit range.

Emissions—Ammonia as a fuel can contribute to a substantial amount of NO_x, which is a major concern. This predicament may require an SCR unit downstream in the fuel gas to reduce NO_x emissions and adhere to environmental emissions regulations. Studies are being planned to understand the burner design and modifications that can reduce ammonia fuel NO_x emissions.

Fuel gas pressure—As summarized in TABLE 1, the ammonia fuel gas flowrate on a mass basis is approximately three times higher when compared to natural gas; on a volumetric basis, it is more than twice as high. Therefore, if a burner is designed to use both natural gas (or other fuels) and ammonia, a much higher ammonia fuel gas pressure will be needed for the burner tip design to achieve a stable control pressure range for natural gas (or other fuels). The viability of all fuel options must be thoroughly evaluated in the early design stages.

Flame profile determination—For ammonia fuel, CFD or other analyzer approaches must be utilized for a comprehensive view of the flame profile.

Fuel gas train—Since the mass flowrate of ammonia is approximately three times that of natural gas and more than twice the volumetric flowrate, the fuel gas train must be evaluated for pressure drop, control valves and gasket design. Considering the health hazards related to ammonia, leakage concerns should be evaluated.

Area classification—Instrumentation must be evaluated for area classification needs. This can result in added instrumentation scope.

SIS trips—Using instrumentation, SIS trips must be evaluated (e.g., a CH₄ analyzer as an identifying trip function). Since ammonia is a carbon-free fuel, identifying flame loss can be conducted via UV/IR flame scanners or ammonia analyzers.

Heater evaluation—Using ammonia fuel results in a lower radiant flux and an overall reduction in heater efficiency when compared to using natural gas. For adequate heater performance, a detailed heater analysis should be conducted for each specific process and heater type for both design and turndown cases.

Metallurgy—Ammonia stress corrosion cracking is a concern that must be evaluated. Applicable specification compliance from the Association for Materials Protection and Performance (AMPP) should be confirmed. Personnel can also reference, “API 571: Damage mechanisms affecting fixed equipment in the refining industry.”

CCS (flue gas treatment). Carbon capture from flue gas commonly utilizes an amine treating unit to absorb and strip out the CO₂ from the flue gases. The CO₂is extracted from the amine solution (with heat) and is then compressed and stored in a safe location. More research is being conducted to optimize and improve efficiency. However, carbon capture from flue gases can have its own limitations. The following are design considerations to capture flue gases:

Fired heater operating range—Fired heater flue gas exit temperatures can vary significantly depending on the current process load and the design efficiency of the furnace. The design and turndown of flue gas temperatures of the heater must be considered in the design of the amine unit. This can involve cooling flue gases for optimum amine absorption.

Plot space constraints—A plant can have multiple fired equipment spread throughout the facility. This can require multiple flue gas ducts that may have to run long distances to a centralized location for amine treating or carbon capture. Long duct runs can result in additional heat loss. The practicality of the design and duct work layout must be considered. Additional area must be accounted for to house blowers or fans for the amine unit.

Heater modifications and duct supports—Existing flue gas stacks may potentially need to be modified with the addition of tight sealing dampers and guillotines (as needed for maintenance). However, this could be specific to the final design. Additional ductworks will require adequate structural support. Both the heater and added ductwork must be structurally evaluated to current codes.

Environmental and flex options—Any downtime of the carbon capture unit (e.g., maintenance, upset conditions) must be accounted for in the design. For heaters to stay in operation, environmental permits must account for heater operation downtime, which may result in the heater operating in its original pre-carbon-capture design mode.

Cost and economics—Carbon capture unit costs can be high due to complex duct layout and equipment. Government incentives (such as tax credits) should be factored into the overall project cost.

Oxy-firing. Oxy-firing is the concept of combustion with oxygen instead of air. Utilizing oxygen instead of air eliminates nitrogen in combustion. This results in two primary components in the flue gas: water vapor and CO₂ (with some excess oxygen). The CO₂-rich stream can be extracted by cooling the flue gases and condensing out the water. Some studies have been done on oxy-firing in the past, with a potential for future development and better understanding. The following are design considerations for oxy-firing:

Flame temperatures—Utilizing pure oxygen for combustion will result in extremely high flame temperatures, which is not practical. Flue gas recirculation or some other burner technology must be utilized to bring flame temperatures down. Personnel should work with the burner supplier to manage the long-term, reliable operation of burners.

Radiant flux and process—The radiant flux of the heater will increase significantly if pure oxygen is used (without any flue gas recirculation). Radiant fluxes can increase more than 30%–40%, potentially approaching process tube metal and film temperature limitations. This process limitation could dictate the amount of flue gas recirculation needed for the burner design to achieve a working design. This is a case-by-case scenario and must be examined with the burner supplier for a viable solution.

Flue gas flowrates—Flue gas flowrates are reduced by nearly 75%, resulting in downsized equipment for flue gas handling. This will result in lower carbon capture costs, as well.

Air leakage—A real concern is air leakage since tramp air can add nitrogen into the system, which can diminish the ability to obtain a desirable CO₂-rich flue gas stream.

Cost—Higher capital costs due to associated air separation equipment could be another concern. One approach could be to utilize the electrolysis of water, which could provide both H₂ and oxygen. H₂ could be used as a carbon-free fuel, while oxygen could be used for oxy-firing. Government incentives and tax credits for using clean H₂ and reducing GHG emissions should be factored into the overall project cost.

Electric heaters could be a viable option in select applications; however, the lack of existing architecture can escalate costs and make it economically unviable.Since a decarbonization solution can be specific to a facility’s existing infrastructure and/or future expansion plans, no single concept provides a universal solution to decarbonize fired heaters. A combination of approaches can be beneficial, depending on the availability of resources and costs. HPFirst Author Rule LineAuthor pic MalhotraKapil Malhotra is a Heat Transfer Engineer at S&B Engineers and Constructors. He has more than 20 yr of experience in the design, engineering and troubleshooting of fired heaters, combustion systems and thermal equipment. Malhotra has also authored several technical papers on heat transfer. He earned an MS degree in mechanical engineering from Oklahoma State University.CoverAd—Merichem THIOLEXContentsAd—APIMastheadAd—Total EnergiesEditorial CommentAd—Honeywell UOPInnovationsAd—Koch Engineered SolutionsSF Opening pageSPECIAL FOCUS—Nelluri (KBR)Ad—FIPISPECIAL FOCUS—Arbulu (Project Production Institute)Ad—Atlas CopcoSPECIAL FOCUS—Abid (Antonoil Service)SPECIAL FOCUS—Goyal (Black & Veatch)Ad—AIChEHeat Transfer—Malhotra (S&B Engineers and Constructors)Heat Transfer—Russell (Blasch Precision Ceramics)Ad—GEI MappingProcess Optimization—Da Silva (Petrobras)Process Optimization—Akhtar (TAI Engineers)Ad—HPI Market Data 2024Digital Technologies—Rice (Control Station)BAR—Prusha (Emerson)Ad—HV H2Tech CircCarbon Capture—Hopkins (Burns & McDonnell)Ad—GEISales OfficeAd—HP Circ (Back Cover)