Carbon dioxide emissions from fired heaters

Fired heaters emit an estimated 400 to 500 million tons of carbon dioxide (CO2) every year. At least 73% of average refinery CO2 emissions come from combustion [1].

Matthew Martin
XRG Technologies

Article Summary

For refineries and petrochemical plants focused on reducing greenhouse gas emissions, it makes sense to target CO2 from fired heaters. Fired heaters usually have a fuel efficiency of 70-93%, so improvements in fuel efficiency enable CO2 reduction. They are usually fuelled by either carbon-bearing refinery fuel gas or natural gas,  so further CO2 reduction is possible by changing to fuels with less carbon content. 

Project economics for increasing efficiency
Many of the fired heaters that are large emitters of CO2 are already the most efficient. Reduced fuel consumption from a refinery’s highest heat release heaters reduces the operating cost of the refinery. Installation costs do not scale linearly with heater size and so smaller units have been less attractive targets for efficiency increasing projects. Anecdotally, the fuel efficiency of existing heaters varies throughout the world with the regions having the highest fuel cost also have the most efficient heaters. While the high efficiency of the largest CO2 emitting heaters may be beneficial to the existing CO2 footprint of a refinery, it also leaves less room for improvement by increasing heater efficiency.

Figure 1 shows the justifiable total installed cost for fired heater improvements compared to a 70% fuel-efficient heater for various fuel and CO2 cost scenarios labeled with numbers (1-4). The graph can be used to estimate a justifiable 18-month return-on-investment (ROI) project cost when moving between any two points on the horizontal axis and multiplying by the fired duty of the heater. The calculations used to generate the graph assume 340 days of operation per year. To scale the acceptable project cost by a different time frame, multiply the result by the ratio of 18 months to the new time frame. A description of the listed scenarios follows:

1. Fuel cost: 3 USD/MMBtu | CO2 Cost 0 USD/ton CO2: This scenario represents most of the USA at the time of writing.
2. Fuel cost: 5 USD/MMBtu | CO2 Cost 17 USD/ton CO2: This scenario represents California where there is a functioning carbon market at the time of writing.
3. Fuel cost: 6 USD/MMBtu | CO2 Cost 25 USD/ton CO2: This scenario represents much of the EU at the time of writing.
4. Fuel cost: 12 USD/MMBtu | CO2 Cost 50 USD/ton CO2: This scenario represents a likely future state in the EU within the next 10 years.

For example, in scenario 1 using a fuel cost of 3 USD / MMBtu and 0 USD / ton CO2, which would be most regions of the USA, a project to increase a 50 MMBtu/h LHV fired duty heater from 80% efficiency to 90% efficiency would require a total installed cost to break even over 18 months as follows:
Eighteen month break even total installed cost

In scenario 3, which would be like current fuel and CO2 costs in the EU, the same project has a justifiable cost as follows:

Operating expenses for purchased hydrogen
Redirecting hydrogen to the fired heater fuel gas system is a very cost-effective way to reduce carbon dioxide emissions. If one can sell the hydrogen from the fuel gas system, or if the hydrogen must be purchased, the operating expenses vary dramatically depending on both the cost of hydrogen and carbon credits. Hydrogen can come from various sources. ‘Green’ hydrogen is produced from completely renewable sources such as solar. The production of ‘blue’ hydrogen results in carbon dioxide emissions that are sequestered. ‘Gray’ hydrogen is produced in the conventional manner, usually reforming, without sequestration of the resulting carbon dioxide.

Figure 2 shows eight different operating scenarios for the addition of hydrogen to the fuel gas system used to fire heaters. Hydrogen costs were estimated at 2.50-6.80 USD/kg for green hydrogen, blue hydrogen at 1.40-2.40 USD/kg, and grey hydrogen at 1.00-1.80 USD/kg [2]. In scenarios (3), (6), and (8) the break-even price for adding hydrogen is calculated. For those scenarios, it is cost neutral to add any level of hydrogen, up to completely displacing all organic molecules, in the fuel of the heater. A description of the different operating scenarios follows:

1. Fuel Cost: 3 USD/MMBtu | 1.00 USD/kg H2 | 0 USD/ton CO2: This scenario represents the current operating state most of the USA using low-cost grey hydrogen.
2. Fuel Cost: 5 USD/MMBtu | 6.80 USD/kg H2 | 17 USD/ton CO2: This scenario represents using high-cost green hydrogen in California where there is a functioning carbon market.
3. Fuel Cost: 5 USD/MMBtu | 0.65 USD/kg H2 | 17 USD/ton CO2: This scenario represents the required cost of hydrogen in California where there is a functioning carbon market such that there is no increased expense in operating the heater.
4. Fuel Cost: 6 USD/MMBtu | 6.80 USD/kg H2 | 25 USD/ton CO2: This scenario represents using green hydrogen in a European refinery to supply some portion of the fuel to a fired heater.
5. Fuel Cost: 6 USD/MMBtu | 1.40 USD/kg H2 | 25 USD/ton CO2: This scenario represents using high-cost grey hydrogen in a European refinery to supply some portion of the fuel to a fired heater. Note that it is very close in cost to using low-cost grey hydrogen in the USA with no carbon incentive.
6. Fuel Cost: 12 USD/MMBtu | 0.76 USD/kg H2 | 25 USD/ton CO2: This scenario represents using the required cost of hydrogen in a European refinery for cost-neutral use of hydrogen in a fired heater. The required hydrogen cost is 46% less than high-cost grey hydrogen or 24% less than low-cost grey hydrogen. If hydrogen production costs go down or CO2 costs go up this could be an operating scenario soon. However, the production of grey hydrogen still releases CO2 into the atmosphere.
7. Fuel Cost: 6 USD/MMBtu | 0.50 USD/kg H2 | 25 USD/ton CO2: This scenario represents current European operating costs. It also shows that, if hydrogen could be purchased for 0.50 USD/kg that the heater would make additional money for every hour of operation due to the potential sale of the carbon credits generated.
8. Fuel Cost: 12 USD/MMBtu | 1.52 USD/kg H2 | 50 USD/ton CO2: This scenario could represent a European refinery in the next 10 years using blue hydrogen. In this case, the hydrogen that is used to fuel the heater is produced from a source with sequestration. The operation of the heater is also cost-neutral compared to the current operation – no additional cost is required to operate the heater regardless of the amount of hydrogen added to the fuel.

Figure 2 shows the additional operating cost of adding purchased hydrogen to the fuel gas supply of a heater normalised by the heat release.  So, for example, to fire 50% additional green hydrogen in a 50 MMBtu/h heater in California at current prices (Figure 2, scenario 2), it would cost an additional:

Total yearly additional cost =

In the EU with grey hydrogen the cost becomes (Figure 2, scenario 5):

Total yearly additional cost =

Wobbe number and fuel gas interchangeability
Combustion equipment is designed for specific fuels or a range of fuel blends. When the burner or heater uses a fuel composition outside of this design range it may not operate correctly. The combustion characteristics of hydrogen are very different from hydrocarbons that, aside from inert components, make up a typical refinery fuel gas. A well-known measure used to compare fuel gas interchangeability is the Wobbe number (sometimes Wobbe index). If the Wobbe number of two fuels match, then the heat supplied at a given pressure will also match. The  Wobbe number is calculated as follows[3]:

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