Process and fuel switching is where decarbonization becomes engineering, not just accounting. It means changing how heat is generated, how energy is delivered to unit operations, and how equipment behaves under constraints such as product quality, uptime, safety, and permitting. These conversions can deliver large Scope 1 reductions, but they carry higher execution risk than efficiency or renewable electricity procurement because they touch the heart of operations.
This chapter provides a practical method to identify where fossil fuels are used, screen the main switching pathways, assemble the minimum data required to make decisions, and run a disciplined redesign program from concept through commissioning. We close with the operational, safety, and regulatory considerations that separate scalable conversions from expensive pilots that never stabilize.
9.1 Identifying Fossil Fuel Use in Industrial Processes and Facilities
The first step is to see the full heat-and-fuel system rather than only the obvious combustion equipment. Many organizations underestimate fossil fuel exposure because fuel is embedded in utilities, backup systems, and small distributed devices that never appear in a consolidated view. That blind spot leads to targets that look achievable on paper but miss the assets that actually drive combustion.
Fuel use typically appears in four places.
Direct process heat: furnaces, ovens, kilns, dryers, thermal oxidizers, and reactors heated by fired equipment. Utilities heat: boilers producing steam or hot water, hot oil systems, and combined heat and power units.
Mechanical and mobile loads: diesel or gasoline vehicles, forklifts, yard equipment, and on-site generators used for resilience or peak management.
Hidden combustion: space heating, domestic hot water, direct-fired make-up air units, temporary construction heaters that became permanent, small point-of-use burners in maintenance shops, and portable generators used outside emergency situations. A useful organizing structure is to build a site-level fuel map that links every fuel input to its end use.
Fuel map: a structured inventory that connects fuel purchases and metered consumption to the specific assets, processes, and services that use that fuel, with enough detail to assign an owner and identify an abatement lever.
Build the fuel map by combining three sources: procurement records (what fuels are purchased, where, and under what contracts), metering and bills (what is actually consumed), and physical walkdowns (what equipment exists and how it is operated). Walkdowns matter because fossil fuel devices are often installed to solve a problem quickly, then remain for years without being captured in central asset registers. Look for bypasses and “temporary” operations, such as keeping a standby boiler hot year-round, running rental generators during peaks, or using LPG forklifts indoors. Record nameplate ratings, typical operating patterns, and who controls the operating decision.
Once the map exists, classify fuel use into categories that match the next planning horizon.
Switchable loads: end uses that can be served by electricity or low-carbon fuels without changing product specifications or core process chemistry.
Constrained loads: end uses tied to high temperatures, strict heat-flux profiles, controlled atmospheres, or qualification regimes that limit near-term options. This classification is an engineering reality check, not a statement about ambition.
The fastest way to focus effort is a Pareto view of consumption and emissions. In many sites, a handful of boilers, furnaces, and CHP units dominate combustion. Those assets often also define the site’s permitting envelope, so changing them can have outsized regulatory implications. Create a “top 10” list by fuel consumption and by CO2e, then confirm with operations leadership that the list matches how the site actually runs. Also identify constraints early.
Constraint driver: an operational requirement that limits switching options, such as maximum downtime, minimum ramp rate, heat uniformity, oxygen control, contamination risk, noise limits, or critical reliability needs. Constraint drivers determine what can change, how quickly, and whether redundancy is required during transition.
Finally, capture non-CO2 impacts that may change with switching. Different fuels can alter NOx formation, particulate emissions, odor, and waste streams such as ash. These impacts are manageable, but they must be surfaced early so the option screen includes emissions controls and disposal requirements rather than discovering them during permitting.
9.2 Fuel Switching Options: Gas to Electricity, Bioenergy, Hydrogen, and Other Alternatives
Fuel switching choices are best understood as energy carriers plus conversion technologies. The same fuel can be used in different equipment, and the same equipment may be adaptable to different fuels with different performance and safety implications. In practice, most pathways fall into four families, and mature programs combine them across loads and over time.
Electrification: replacing combustion with electricity-based heat or mechanical energy. Common technologies include electric boilers for steam, industrial heat pumps for low- and medium-temperature heat, resistance and infrared heating for drying and ovens, induction heating for metals, electric arc heating, and direct electric heaters for hot air or hot oil loops. Electrification is most attractive where the grid is relatively clean or where the company can procure low-carbon electricity. It also becomes more attractive when paired with demand management, because electrified loads can otherwise increase peaks and tariff exposure.
Electrification is not universally feasible. Very high-temperature processes may require technologies that are still maturing, and some operations depend on combustion characteristics such as radiant heat distribution or controlled atmospheres. Even when feasible, electrification can be constrained by interconnection queues, transformer and switchgear capacity, power quality requirements, and tariff economics. The practical rule is to design electrification with the electrical system, not against it: start with an electrical one-line review, quantify incremental capacity needs, and sequence conversions with interconnection milestones and peak management.
Bioenergy and renewable gas: substituting fossil fuels with biogenic fuels such as biogas, biomass, or renewable natural gas. Bioenergy can be pragmatic where electrical capacity is limited or where high-temperature heat is needed and electrification is constrained. It can also serve as a transitional fuel for assets that cannot be replaced quickly. The tradeoffs are real: supply availability, storage and handling, fuel variability that can affect combustion stability, and air permitting for particulates, NOx, and other pollutants. Biomass fuels may add ash handling and housekeeping requirements that affect operations.
Hydrogen and hydrogen-derived fuels: using hydrogen as a fuel for heat and, in some sectors, as a feedstock. Hydrogen can address high-temperature heat needs and can be used in some existing combustion systems with modifications, including burner upgrades and controls changes. Constraints include supply availability, cost, infrastructure for delivery and storage, and safety requirements. Hydrogen combustion can increase NOx if not controlled, so burner design and emissions controls matter. Many sites also face practical constraints on hydrogen purity, blending limits in existing pipelines, and the space and permitting required for storage and compression.
Other alternatives and hybrid strategies: in some operations, the best solution is a hybrid system rather than a single fuel. Examples include electrifying base-load heat while retaining a low-carbon combustible fuel for peaks, using thermal storage to shift electric load away from demand-charge periods, or pairing fuel switching with process redesign that reduces heat duty and enables lower-temperature operation. In specific circumstances, carbon capture on combustion may be evaluated when switching is constrained; treat it as a distinct pathway with its own infrastructure and permitting dependencies.
A practical screening approach is to evaluate options against criteria that reflect operating reality rather than only cost per ton.
Heat requirement: temperature, heat flux, and uniformity needed.
Duty cycle: steady-state versus cycling, peak-to-base ratios, and ramp rates.
Integration complexity: how much upstream and downstream equipment must change.
Infrastructure dependency: grid capacity, fuel delivery, storage, and permitting.
Non-CO2 impacts: NOx, particulate emissions, safety hazards, and by-products that may change with the fuel.
To keep decisions fast, write each candidate as an option brief before launching detailed engineering.
Option brief: a concise description of the fuel and technology choice, prerequisites (capacity, storage, permits), expected emissions impact, cost drivers, lead time, implications, and risks with mitigations. Treat the brief as a decision artifact: it should be clear enough that an operations leader can say yes, no, or not yet based on constraints, not hopes or slogans.
One additional lens matters for sequencing: reversibility. Electrification of building heat is often modular and can be deployed in packages. A core furnace conversion may not be. The more irreversible the change, the more you should invest up front in feasibility, operator engagement, and qualification planning.
9.3 Data Required: Process Maps, Fuel Consumption, Technical Constraints
Fuel switching decisions require more than fuel bills. You need a clear view of where heat is added, what performance is required, and what constraints cannot be violated. Teams that skip this foundation often choose options that look attractive in aggregate but fail in detailed engineering or during product qualification.
Start with process mapping. At minimum, build a process flow view that shows unit operations, utility interfaces, and where heat enters and exits. For complex sites, add a simple mass-and-energy balance around the highest-emitting units to quantify heat duty, losses, and waste heat.
Process map: a structured representation of unit operations, utility connections, and energy flows that enables identification of heat demands, recovery opportunities, and conversion points.
Collect consumption data at the granularity that matches decisions. For major fired assets, capture fuel use and operating hours to understand duty cycles and peaks. For steam systems, capture boiler efficiency, steam production, header pressures, condensate return, and blowdown. For hot oil systems, capture supply and return temperatures and flow. For furnaces and ovens, capture setpoints, load factors, residence times, and quality constraints. For mobile sources, capture fuel use by vehicle class, routes, payload, idle time, and charging availability if electrification is planned.
Make constraints explicit and owned. Common constraints include maximum downtime, product qualification requirements, heat uniformity, ramp rate limits, moisture or impurity tolerances, oxygen control needs, explosive atmosphere classifications, and space constraints for new equipment. Electrical constraints require a one-line understanding of service entrance capacity, transformer headroom, switchgear ratings, protection coordination, and backup requirements. On the fuel side, constraints include delivery access, onsite storage limits, and any requirements for redundancy to protect critical operations.
Also gather permitting and infrastructure context. Electrification depends on interconnection timelines and upgrade responsibilities, and tariff structure can materially change economics. Bioenergy and hydrogen depend on local rules for fuel storage, fire protection, and air permits, and permit modifications can require dispersion modeling, public consultation, and new emissions controls. If permitting is on the critical path, treat it as such in the program plan with explicit milestones and owners.
Finally, define measurement requirements up front. If the program will claim emissions reductions, you need a baseline definition, emissions factors, and a metering plan that can prove reductions and explain variances.
Verification plan: a documented method to quantify emissions reductions using defined baselines, metering, normalization rules, and sign-off authority.
9.4 Step-by-Step: Designing a Fuel Switching and Process Redesign Program
Fuel switching succeeds when it is run as a structured program with clear decision gates. It should not be treated as a single project, because different assets move at different speeds and require different pathways. The steps below are designed to be repeatable across a portfolio of sites and systems.
- Step 1: Set scope and governance: Define which emissions are in scope (usually Scope 1, with explicit Scope 2 implications for electrification), select the program boundary, and establish decision rights. Assign a program owner and site owners who can coordinate operations, engineering, finance, and safety.
- Step 2: Build the fuel map and hotspot list: Inventory combustion and fuel use, quantify emissions by asset and system, and identify the top sources. Include backup generation, small heaters, and rented equipment where material. Validate the list through site reviews.
- Step 3: Segment loads by archetype: Group end uses into archetypes such as space heat, low-temperature process heat, steam generation, medium-temperature ovens and dryers, high-temperature furnaces, and mobile equipment. Archetypes allow standardized screening and reduce reinvention.
- Step 4: Screen options using constraint drivers: For each archetype, identify plausible options and eliminate those that violate non-negotiable constraints. Capture dependencies such as grid upgrades, fuel supply, storage, and permitting. Use ranges for cost and abatement until feasibility studies refine assumptions.
- Step 5: Run feasibility studies for priority assets: For the largest sources, answer four questions: can it work technically, can it be operated safely, can it be delivered within downtime windows, and can it be permitted. Treat failed options as useful learning, not as wasted effort.
- Step 6: Build business cases and portfolio sequencing: Quantify capex, opex, downtime impacts, maintenance changes, and emissions reductions with consistent methods. Include tariff impacts for electrification and supply contract terms for bioenergy or hydrogen. Sequence projects based on readiness and capital cycles, not only $/tCO2e.
- Step 7: Pilot and qualify where needed: For options that affect product quality, safety, or regulatory limits, run pilots or trials with defined success criteria: quality metrics, controllability, uptime, and maintenance burden. Ensure pilots reflect realistic operating conditions, not ideal test windows.
- Step 8: Engineer, procure, and integrate: Complete detailed design, update P&IDs, integrate controls, and define commissioning plans. Procure long-lead equipment early and lock in fuel supply agreements where required. Align interconnection and electrical upgrades to project milestones.
- Step 9: Commission and stabilize: Treat commissioning as a stabilization period. Train operators, tune controls, and establish new standard operating windows. Track performance against baseline and correct issues quickly so early underperformance does not become permanent skepticism.
- Step 10: Verify and institutionalize: Execute the verification plan, reconcile fuel and electricity data, document results, and update the baseline to reflect the new operating reality. Feed lessons learned into the next wave and standardize what worked.
To keep execution consistent, teams often describe each conversion
using a structured summary that makes assumptions explicit and comparable. Initiative card: a concise description of a fuel-switching initiative that includes asset scope, option chosen, constraints, dependencies, economics, emissions impact, schedule, and operational owner.
Across a portfolio, enabling work must be managed intentionally. Metering upgrades, electrical capacity studies, interconnection applications, burner management system upgrades, and permitting pathways may not reduce many tons immediately, but they unlock conversions that deliver the bulk of reductions. Assign owners and milestones to enablers and track them as first-class workstreams.
9.5 Operational, Safety, and Regulatory Considerations
Fuel switching changes hazard profiles and regulatory obligations. Programs that treat safety and permitting as later steps often stall after spending money on engineering that cannot be approved or safely operated. Integrate safety and regulatory work from the beginning and treat it as a design constraint, not an afterthought.
Operational safety: Begin with hazard identification and process safety management for each conversion. Update operating procedures, emergency response plans, and maintenance routines. Combustion-to-electric conversions can introduce new electrical hazards, including arc flash and higher fault currents. Hydrogen introduces flammability, leak detection, ventilation, ignition control, and safe purging practices, along with materials compatibility for seals, valves, and piping. Bioenergy can introduce dust explosion risk, fuel variability, additional housekeeping, and different failure modes in handling and storage.
Use structured safety reviews and close findings before start-up. For major process changes, apply formal hazard studies, verify instrumented protections, and ensure alarms and interlocks are tested and maintainable.
Management of change: a controlled process to assess and approve changes to equipment, processes, and operating conditions, ensuring safety, reliability, and compliance are maintained.
Operational reliability: Many conversions fail in the first months not because the technology cannot work, but because controllability and reliability were underestimated. Define reliability requirements explicitly and test under realistic operating conditions. Provide redundancy where needed, especially for critical utilities such as steam and hot water, and ensure operators have clear fallback procedures during stabilization.
Regulatory and permitting: Switching fuels can change regulated emissions profiles. Electrification may reduce combustion emissions but can trigger electrical permitting and building code requirements. Bioenergy can affect particulate emissions and may require additional controls. Hydrogen combustion can affect NOx and may require burner redesign and control upgrades. Engage environmental, legal, and permitting teams early to understand modification pathways, modeling needs, timelines, monitoring requirements, and reporting obligations.
Fuel quality and sustainability: For bioenergy and renewable gas, credibility depends on feedstock and chain-of-custody rules in your reporting regime. Establish procurement standards that define acceptable feedstocks, sustainability criteria, and documentation requirements, and ensure claims governance matches procurement practice.
- Safety closure: Are hazard review actions closed, tested, and embedded in operating procedures?
- Permit readiness: Are modeling, controls, and monitoring requirements defined and funded?
- Supply assurance: Do contracts and onsite arrangements protect reliability and claims integrity?
- Operator capability: Are training, drills, and maintenance routines updated for the new system?
Fuel switching is one of the highest-impact levers for Scope 1 emissions, but it demands rigor. Organizations that succeed map fuel use comprehensively, choose options that fit constraints, build the data spine to verify impact, and run conversions through a repeatable program that integrates safety and permitting from day one.
