Cutting carbon in California

Environmental and energy concerns are typically addressed in California first; for a preview of what’s to come regarding decarbonization, look West

By Gas Technology March 26, 2020

A report titled “Pathways for Deep Decarbonization In California,” published in May 2019 by Energy Futures Initiative (EFI), was produced to define the existing California clean energy landscape and recommend steps for accelerating the move to meet the state’s carbon reduction goals by midcentury.

EFI was established in 2017 by former California Secretary of Energy Ernest J. Moniz to address the imperatives of climate change by driving innovation in energy technology, policy and business models to accelerate the creation of clean energy jobs, grow local, regional and national economies and enhance energy security. The members of EFI are fact-based analysts who provide their funders with unbiased, practical real-world energy solutions.

While most of the report deals with the residential market, this article focuses on the industrial sector.

California’s industrial sector

According to the report, California’s industry sector is the second-highest emitting sector in the state’s economy and is one of the most technically and economically difficult to decarbonize. The California Air Resources Board (CARB) divides the industrial sector into 11 subsectors. CARB further divides one of these sectors — manufacturing — into 17 subsectors. Combined, these primary and secondary subsectors provide the framework for the analysis in the EFI report.

Each subsector has energy requirements, emissions sources and process needs. Many subsectors have large-scale, energy-intensive operations with complex supply chains and a low tolerance for operational downtime, the report said. Industrial sector decarbonization strategies looks at emission sources (coal, petroleum, natural gas), the nature of the emissions (combustion versus non-combustion) and the unique characteristics defining each subsector (process heat requirements, electrification potential).

The report details nine potential greenhouse gas (GHG) emission reduction methods that can help decarbonize the industrial sector in California:

  • Carbon capture, utilization and storage (CCUS)
  • Fuel switching (electrification, hydrogen or renewable natural gas)
  • Facility best management practices
  • New technology adoption
  • Biogas collection
  • RNG
  • Reducing fugitive emissions
  • Industrial combined heat and power (CHP)
  • Energy efficiency.

Given the diverse nature of many industrial processes, an effective decarbonization strategy will require tailored solutions that accommodate the unique challenges and opportunities in each subsector, the report said.

Industry is a difficult sector to decarbonize. The level of systems integration, high-temperature process heat requirements and the heterogenous nature of industrial processes remain the primary challenges to decarbonization. However, several opportunities for reducing GHG emissions that may avoid massive system retooling, protracted operational downtime or a complete overhaul in technical expertise include energy efficiency improvements and facility best management practices, new technology adoption and fuel switching, CHP and CCUS. These pathways, especially fuel switching and CCUS, can lead to measurable emissions reductions across the major industrial subsectors in California, according to the report.

Carbon capture, utilization and storage

CCUS is expected to play an important role in sectors and processes that are difficult to decarbonize. At present, CCUS is likely the only option available for decarbonizing several industrial processes such as cement production, oil refining and natural gas processing, in addition to further mitigation opportunities across California’s large industrial base, the report said.

California is also well-positioned to take advantage of its estimated geologic storage potential of 34 to 424 billion metric tons of CO2, making CCUS a viable option for industrial decarbonization, according to the report. There are many industrial facilities clustered near San Francisco and the surrounding area, Los Angeles and the surrounding area, and along the Central Valley. The proximity of these industrial facilities to potential CO2 sequestration sites could offer an opportunity to build new infrastructure that would support the transport and storage of captured CO2 from numerous facilities.

Costs and challenges of CCUS in industry

CCUS presents technical, economic and public policy challenges that must be addressed to ensure viability of this option. From a technical standpoint, capturing CO2 can be a challenging and energy-intensive process. However, numerous industrial processes tend to have higher concentrations of CO2 in their effluent streams, which can result in fewer technical (and economic) challenges for capture compared to less concentrated streams of CO2 such as those found in the power sector (e.g., approximately 5% CO2 concentration for natural gas plants and 15% for coal plants), the report said.

The transport and geologic sequestration of CO2 also presents challenges that include regulatory uncertainty, post-injection site stewardship and liability, and the length of time required to demonstrate permanence. However, the recent CCS Protocol developed for the California LCFS program provides guidelines to help address some of these issues including a 100-year minimum period for post-injection site care and monitoring prior to site closure. The absence of sufficient CO2 pipeline infrastructure in California is another impediment to CCUS project development. Pipelines remain the most cost-effective means of transporting large amounts of CO2 over long distances for the purposes of utilization or geologic sequestration.

Cost estimates for industrial CCUS are more uncertain than those in the power sector and can vary based on the type of industrial facility and capture technology. The costs (and technical difficulties) of industrial CCUS also are affected by the number of emissions sources present at each type of facility. For example, emissions from cement plants stem from the precalciner and kiln, whereas emissions from petroleum refineries come from a much larger number of individual sources. Despite the uncertainty and variability in CCUS costs, industrial facilities tend to form regional clusters. This characteristic can be leveraged for shared CO2 transportation networks and geologic storage opportunities, according to the report.

Fuel switching

The opportunities for reducing GHG emissions in the industrial sector through fuel switching include fuel switching from fossil fuels to electrification or hydrogen, substituting gas (or RNG) for coal and substituting gas (or RNG) for petroleum.

Electrification. Electrification could play a role in decarbonizing certain subsectors of California’s industrial sector (see Figure 1). Process heat currently accounts for about 50% of the energy consumed in the manufacturing subsector, the report said. However, only 5% of process heat applications are electrified. Fossil fuels still account for most of the energy used in conventional boilers and for direct-combustion process heat.

Figure 2: These technologies could be used to promote industrial electrification. Courtesy: NREL, 2017a; NREL, 2017b[/caption]

Electrification costs and challenges. While electrification may appear attractive to some, there are challenges to widespread adoption. According to the report, challenges for industrial subsectors with electrification potential include large capital costs for equipment turnover, higher costs of electricity as a fuel relative to other energy resources and technical hurdles to achieving high temperature process heat.

Industrial segments in subsectors with high-temperature process heat requirements, such as cement production, have low potential for electrification with existing commercial technology and have fewer options for decarbonization. The remaining options remain include CCUS and using RNG or hydrogen as fuels.

In addition, oil refineries present major challenges to electrification. The extent of process integration specific to the petroleum refining and hydrogen production subsector means that any technological disruption such as electrification could require considerable system re-engineering. It is also common practice for oil refineries to self-consume energy resources generated as refining process byproducts. Electrification would eliminate this option, which could result in increased energy costs for oil refineries. CCUS may be one of the readily available options for decarbonizing California’s 17 oil refineries, which have a combined capacity of more than 1.9 million barrels per day, the report said.

Additional challenges to the electrification of the industrial sector include low natural gas prices, aversion to major process redesigns and little current industry momentum for electrification. In California, industrial consumers enjoy relatively low natural gas prices, compared to end users in other sectors of the state’s economy. In 2016, their natural gas prices were the second lowest of all end-use sectors — only utilities in the electric power sector paid less, according to the report. These relatively low natural gas prices, coupled with the high equipment costs of switching, could discourage industrial facilities from electrification of certain end uses.

Industrial facilities can have useful lifespans of 50 years or longer, and any process changes through retrofits or systems re-engineering can be relatively costly. This has the potential to make some commodities such as steel more expensive if it comes from an industrial facility that pursues emissions reduction strategies compared to a facility that does not employ low-carbon strategies, the report said. For example, fuel switching in the industrial sector typically requires a change in manufacturing processes, which can lead to substantial new equipment costs.

Another barrier to industrial sector electrification is the lack of empirical data and information, especially regarding cost, which limits the ability of analysts, modelers and policymakers to determine the efficacy of industrial electrification, according to the report. A 2017 report on industrial electrification opportunities yielded limited available data, especially for the costs of different electrification technologies. Much of the available data was reportedly anecdotal.

Another current barrier to industrial electrification involves the potentially higher cost of energy from fuel switching to electricity. One cost comparison of electric and natural gas-fired boilers indicated that although electric boilers had a lower capital cost and were more energy-efficient, the electricity price was approximately three times more expensive than natural gas on an energy-equivalent basis, making the electric boiler roughly twice as expensive as a natural gas boiler for first-year costs, the report said (see Figure 3).

Hydrogen. In cases where electrification and energy efficiency cannot lead to measurable emissions reductions, hydrogen can offer a clean-burning substitute. Certain processes require combustion-based heat because the fuel meets a specific heating need and provides components important to the chemistry of the process, according to the report. Where industrial end-use systems permit, hydrogen may be blended with natural gas to reduce the emissions intensity of methane.

Alternatively, certain pieces of equipment can be retrofitted to run on hydrogen. For example, ethylene crackers have seen retrofits to support hydrogen use (and hydrogen is already a byproduct in refineries); and in cement production, hydrogen can be combined with waste-derived fuels. Clean hydrogen could replace natural gas or coal in refining and ironmaking as a substitute for fossil-based feedstocks and/or reducing agents, the report said.

Hydrogen costs. The two most common methods to produce hydrogen include steam-methane reforming (SMR) of natural gas and electrolysis. SMR is currently the cheapest method for producing hydrogen and has a high-volume production cost of less than $2 per gallon of gasoline equivalent. Large-scale SMRs (central station reformers) are a mature technology that have an initial investment cost of $400 to $600 per kilowatt. Hydrogen also can be produced using smaller, distributed SMR units that can be scaled according to the desired production level.

Aside from the cost per kilogram of produced hydrogen, other production cost estimates include a total plant capital cost of approximately $190 to $350 million depending on use and type of carbon-capture equipment; hydrogen pipeline infrastructure ($1 million per mile for dedicated hydrogen pipelines); hydrogen compression, storage and dispensing costs ($2 per kilogram of hydrogen); and CO2 transport and sequestration (roughly $2 per metric ton of CO2 for transport and $13 per metric ton of CO2 for storage), according to the report. Electrolysis is currently expensive and is considered a longer-term option.

Facility best management practices

Facility best management practices were benchmarked to the U.S. Environmental Protection Agency (EPA) ENERGY STAR Challenge for Industry, which seeks to reduce the energy intensity of industrial sites by 10% in five years.

New technology adoption

New technology adoption, according to the study, included the combined emissions savings from three technologies: higher-efficiency kilns in the cement subsector (30% lower thermal fuel use), smart systems for manufacturing automation to reduce energy intensity by 20% and a 25% reduction in energy use through additive manufacturing in select manufacturing subsectors.

This means that new technology adoption is possible within the manufacturing subsector and includes additive manufacturing and smart systems. Estimates suggest that additive manufacturing could reduce energy use in manufacturing operations by 25%, the report said. It may be most relevant in the construction, electric and electronic equipment, food products, textiles, transportation equipment, and wood and furniture subsectors. Implementing additive manufacturing in these subsectors could potentially reduce emissions by 1.0 MMTCO2e. Smart systems could assist process automation in the manufacturing subsector, with the potential to achieve a reduction in energy intensity of 20%. For California’s manufacturing subsector, a 20% reduction in energy consumption could potentially result in an emissions savings of nearly 3.8 MMTCO2e, according to the report.

Biogas capture

Biogas is waste methane that is passively emitted in many sectors. Within the industrial sector, biogas sources are found in the landfills, wastewater treatment, and solid waste treatment subsectors. In 2016, these subsectors emitted 8.83 MMTCO2e in biogas. By capturing and diverting these sources of methane for upgrading to RNG, the industrial sector could receive a double benefit in terms of methane emissions savings plus displacement of fossil natural gas.

Biogas capture costs and challenges

The typical capital cost for a 40-acre landfill gas (LFG) collection system (designed for 600 cubic feet per minute) is approximately $1.1 million with additional annual operation and maintenance costs of $191,000, the report said. Biogas collection systems generally include the processing infrastructure needed to purify the LFG for different end uses, which occurs through primary treatment (e.g., removal of water, moisture and particulates) and, if necessary, more involved processing stages including secondary treatment (removal of sulfur compounds) for power generation or medium-Btu applications and advanced treatment (removal of impurities such as CO2) for high-Btu applications such as vehicle fuels or pipeline-quality gas.

Two of the key factors that make RNG more expensive than conventional natural gas are the special requirements for processing and upgrading RNG and pipeline interconnection fees. Prior to injection into a local distribution network through an interconnection, RNG must undergo testing and verification to ensure that it meets pipeline-quality standards. The infrastructure required to upgrade and inject RNG into a local distribution pipeline system typically makes up two-thirds of capital equipment costs for an RNG project, with the remaining one-third of the cost attributed to the actual biogas collection system (for anaerobic digestion). According to the report, these capital costs also vary by project site, with the lowest costs associated with landfill gas, and then progressively higher costs for RNG from wastewater treatment, municipal solid waste, dairy manure and forestry and agricultural residues, respectively.

Pipeline-quality renewable natural gas

Fuel switching from coal and petroleum to natural gas blended with RNG also could provide emissions reductions. RNG is biogas that has been upgraded to pipeline quality and is chemically equivalent to fossil natural gas. RNG also diverts gaseous waste streams that would otherwise emit methane. For this reason, RNG is considered a lower carbon source because the methane emissions it prevents have a higher global warming potential than the CO2 that results from RNG combustion, the report said.

The use of RNG for decarbonizing pipeline gas is particularly well-suited to helping the industrial sector reduce its GHG emissions, since natural gas plays a prominent role in numerous industrial applications as a resource for process heat, as a fuel for CHP systems and as a feedstock for products such as chemicals and fertilizers. These industrial needs — currently met by conventional natural gas — also could be met by RNG. In addition, fuel switching to RNG could require little-to-no infrastructure turnover and therefore lower infrastructure-associated costs relative to other fuel switching options.

RNG costs and challenges

RNG is considerably more expensive to produce than natural gas (between 2-3 times the cost), according to the report. It is important to note that these costs vary based on the type of feedstock. RNG qualifies as an advanced biofuel under the federal Renewable Fuel Standard (RFS) and is eligible to generate offsets under California’s LCFS and cap-and-trade programs.

Reduce fugitive emissions

According to the report, the transmission and distribution subsector was responsible for approximately 5.1 MMTCO2e of California’s GHG emissions in 2016, of which 80% was from non-combustion sources. Non-combustion emissions are largely fugitive emissions from natural gas pipelines, with a marginal amount of fugitive emissions from natural gas storage. Fuel combustion emissions are from natural gas.

A possible mitigation opportunity is to reduce or eliminate fugitive emissions from gas pipeline infrastructure. A second mitigation opportunity that could address fuel combustion-related emissions from natural gas is by fuel switching to hydrogen or electrification (with subsequent elimination of natural gas storage). For this analysis, reducing or eliminating fugitive emissions from gas storage and pipelines was pursued in this subsector at a 50% capture rate, the report said. Based on the illustrative mitigation portfolio, the transmission and distribution subsector could achieve an emissions reduction of 2.0 MMTCO2e by 2030 through reducing fugitive emissions.

Combined heat and power

CHP can be used in industrial facilities to generate electrical and thermal energy from a single fuel source and lead to reduced energy consumption, lower fuel costs and decreased GHG emissions. According to an analysis by the DOE CHP Deployment Program, California had the second-highest total technical potential for new CHP projects in the U.S., behind only Texas.

In 2016, California had a total CHP installed capacity of 8,590 megawatts across 1,220 installations, of which 4,097 MW (48%) are in the industrial sector with just 189 installations (15%), the report said. Estimates suggest that California has 3,633 MW of new topping-cycle CHP technical potential across 4,253 sites. It also has 729 MW of new technical potential available through bottoming-cycle CHP across 62 sites. In total, the industrial subsectors with the highest technical CHP potential in California (in terms of capacity) were petroleum refining and hydrogen production (1,427 MW); chemicals and allied products (1,111 mw); food products (776 mw); stone, clay, glass, and cement (204 mw); and transportation equipment (147 MW).

CHP costs and challenges

CHP is a mature technology currently used in both the buildings and industrial sectors. The project economics for CHP are generally based on the net benefit of displacing purchased electricity and boiler fuel with self-generated power and thermal energy. CHP systems face several challenges involving different subnational laws and regulations, grid interconnection issues and accessing different fuel sources, according to the report. Challenges at the state level can have a major impact on CHP project deployment. Industrial CHP systems can range in cost depending on factors such as technology type and size of the system. An analysis of CHP opportunities in California identified reciprocating engines as the most economic CHP technology for smaller projects less than 5 MW, while gas turbines were more economic for larger projects above 5 MW.

Energy efficiency

For energy efficiency, the California Energy Commission (CEC) has estimated that compliance with SB 350 could help the industrial sector realize a potential GHG savings of 0.06 MMTCO2e, the report said. Similarly, the EPA ENERGY STAR Challenge for industry aims to improve energy efficiency at any industrial site by reducing its energy intensity by 10% within five years. Achieving this target across California’s industrial sector could potentially reduce fuel combustion emissions by 6.6 MMTCO2e.

– This article appeared in the Gas Technology supplement.

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