S. Wattanasoponvanij, W. TANTHAPANICHAKOON, K. LOURVANIJ, SCG Chemicals Co. Ltd., Thailand; and A. SOOTTITANTAWAT, Chulalongkorn University, Bangkok, Thailand
In the petrochemical industry, olefin crackers utilize significant amounts of heat to crack hydrocarbons into essential chemicals, such as olefins and aromatics. The necessary energy is usually supplied by a fuel gas, typically natural gas, or a byproduct gas from the facility. However, this process generates significant amounts of carbon dioxide (CO2), a potent greenhouse gas contributing to climate change. The decarbonization of steam crackers refers to the efforts made to reduce, capture or eliminate CO2 emissions from these units. This can involve several strategies, such as:
Decarbonizing steam crackers, a major source of CO2 emissions in the petrochemical industry, is a critical step toward a more sustainable future. Traditionally, steam crackers use fossil hydrocarbons like natural gas, liquefied petroleum gas (LPG) and/or naphtha as feedstock and heat sources, leading to significant CO2 emissions. However, there is an increasing need for industry to transition toward more sustainable and low-carbon solutions, and green H2 is emerging as an alternative thermal source in this scenario. When used as a fuel in steam crackers, H2 has the potential to eliminate CO2 emissions. H2 combustion does not produce CO2, making it an ideal option for lowering carbon footprints. Furthermore, to be effective, H2 should be green and produced from renewable energy sources.
However, switching to H2 is not without challenges. H2 requires careful considerations related to its storage, transport and handling; the modification of existing infrastructure, and changes in combustion properties; as well as various regulatory aspects. Despite these challenges, the transition to H2 represents an important pathway for decarbonizing steam crackers and achieving a sustainable chemical industry. With ongoing research and development, supportive policies, and industrial collaboration, the role of H2 in decarbonizing steam crackers is anticipated to be increasingly significant.
Understanding combustion characteristics and fuel properties. Natural gas primarily consists of methane and includes smaller quantities of other hydrocarbons like ethane, propane and butane, along with minor amounts of non-hydrocarbon gases. The exact makeup of natural gas can differ significantly. As a result, the safety measures and performance of a natural gas blend enriched with H2 will rely not just on the blend proportion, but also on the original composition of the natural gas. The key properties of methane (as representative of natural gas) and H2 are compared in TABLE 1. H2’s combustion characteristics differ significantly from methane and traditional fuel gases. The following points further elucidate some of the inherent technical challenges.
Diffusivity. H2’s diffusivity is about four times higher than natural gas, which means it mixes more rapidly with air. This leads not only to faster homogeneous air-fuel mixing and combustion, but also to higher risks of unintentional ignition and explosion.
Lower heating value (LHV). Although H2 has a higher LHV of approximately 2.5 times that of natural gas on a weight basis, when measured volumetrically, H2’s LHV is substantially lower, indicating a need to burn more H2 for the same energy output.
Minimum ignition energy (MIE). H2 has a very low MIE, an order of magnitude lower than that of natural gas. This means that it can easily ignite spontaneously from a tiny spark or some other ignition source, thus increasing the safety risks.
Flammability limit. H2 has an extremely wide flammability range (4%–75% by volume) compared to natural gas (5%–15% by volume), so it can ignite over a much wider range of concentrations. Therefore, the control of H2 combustion is more complex than for natural gas. This again raises safety concerns, as it increases the risk of ignition and explosion.
Flame speed, adiabatic flame temperature and flame visibility. Flame speed is crucial for steam cracking design because it directly influences the control and efficiency of the combustion process. H2’s flame speed is about seven times higher than natural gas. The adiabatic flame temperature of H2 is about 500°C higher than natural gas. These two attributes make safe heat transfer management more challenging for H2. Higher flame speed and the temperature of H2 can cause unwanted local hot spots. Additional challenges include managing high temperatures and preventing damage to combustion equipment. Moreover, advanced cooling methods and heat-resistant materials might be necessary due to the high flame temperatures of H2.
The higher flame temperature also increases the likelihood of higher nitrogen oxide (NOx) generation. It is possible to reduce NOx production from H2 combustion by modifications to the combustion process, such as adjusting the air and fuel ratio, eliminating flame hotspots, and enhancing emission treatments in the exhaust stack (e.g., using selective catalytic reduction systems). To optimize heat transfer when burning H2, it is beneficial to use the lean-burn mode, which lowers combustion temperatures.
In terms of flame visibility, H2 flames emit a weak blue light and are nearly invisible in daylight due to their low emissivity of visible light, making the main part of an H2 flame appear colorless to the naked eye. This low visibility can pose a safety risk, as it could lead to an undetected fire. Additionally, H2 flames emit low radiant heat, making it difficult to feel an H2 fire before it is too late. Therefore, using special flame indicators is necessary when working with H2 in certain conditions. Conversely, natural gas flames are more visible, producing a bright blue flame in an oxygen-rich environment. This visibility is beneficial from a safety perspective, as it allows for the immediate detection of a fire due to a leak. However, in a poorly ventilated or oxygen-deficient environment, the natural gas flame turns yellow or orange, indicating incomplete combustion and the possible production of dangerous byproducts like carbon monoxide.
Autoignition temperature. The autoignition temperature of a gas is the minimum temperature at which it can spontaneously ignite in the air without the need for a spark or an ignition source. H2 has a relatively lower autoignition temperature vs. natural gas, so an H2 leak can ignite more easily, even without a spark or flame present. H2 diffuses and rises quickly in the air, thereby reducing the risk of a localized explosive mixture. In fact, H2 weighs only 0.07% relative to air, whereas natural gas, propane and gasoline vapor weigh 0.55%, 1.52% and 4%, respectively. Leaked H2 will accumulate at the ceiling of enclosed spaces, potentially leading to an explosion if ignited.
Appropriate safety measures must be taken when working with both H2 and natural gas—including the careful control of temperatures and proper ventilation to avoid the buildup of gases, regular checks and maintenance of equipment, and the installation of gas detection systems to quickly identify any gas leaks.
Stoichiometric air/fuel mass ratio. The stoichiometric air/fuel ratio is the theoretical minimum proportion of the air and fuel required for complete combustion. In practice, this ratio should be approached as closely as possible to enhance the efficiency, performance and emissions control of combustion processes. For natural gas primarily composed of methane, the stoichiometric air/fuel ratio is roughly 17.2:1 by weight, requiring at least 17.2 kg of air to fully burn 1 kg of natural gas (which ranges in flammability between 5% and 15% by volume). Considering this, natural gas engines often operate in lean conditions for improved efficiency and reduced emissions.
H2’s stoichiometric air/fuel ratio is about 34:1 by weight, requiring at least 34 kg of air to burn 1 kg of H2 completely. H2’s flammability is 4%–75% by volume, which is both an advantage and a disadvantage. While this allows H2 burners to run with a lean mixture to improve fuel efficiency and reduce NOx emissions, H2 can still ignite unintentionally under certain conditions.
To maximize thermal efficiency and minimize emissions, burners should operate in a lean-burn mode, where the actual air/fuel mixture contains only slightly more air than required by the stoichiometric ratio, while accomplishing complete combustion and lowering combustion temperatures to reduce the associated formation of certain pollutants such as NOx. However, operating in lean conditions may decrease burner capacity. Therefore, it often requires a control system to dynamically adjust the air/fuel ratio based on various operating conditions, such as heat load and temperature.
Infrastructure modification. It is highly likely that existing equipment may not be satisfactory for H2 fuel due to differences in its physical and chemical properties. The required significant infrastructure upgrade may include a change of burners, piping and safety systems.1 The following are equipment to consider.
Cracking furnaces and burners. A steam cracker has two main sections: the radiant section, where the preheated and premixed-steam feedstock (e.g., naphtha) is heated and cracked to yield low olefins and paraffins (including methane), and aromatics—and the convection section, where preheating of the feedstock and post-cooling of the residual feedstock, olefin products and byproducts via steam generation occur. Utilizing an unconventional fuel like H2 can result in alterations to the radiative and convective heat transfer performance within the cracking furnace. This can potentially affect the rate of steam generation and its temperature, as well as the feedstock preheating level due to the distinct combustion properties of H2. In a typical case, the byproduct methane (or natural gas) will be separated from the olefin products and then recycled as fuel gas for the cracker by blending with the H2 fuel. As a result, the combustion characteristics of this mixed fuel will depend on the blending ratio. Although its flame temperature is significantly higher than that of natural gas, its emissivity becomes significantly lower. Since the rate of radiant heat transfer is proportional to the emissivity and the fourth power of flame temperature, the radiant section’s heat transfer efficiency is likely to increase,2 thereby overheating the tube walls (possibly beyond the limits of tube metal temperature) and increasing the rate of coke formation, as well as increasing NOx formation in the flue gas. Another major impact of H2 fuel is the absence of CO2 generation and the reduction of the flue gas mass flow rate, which reduces the steam generation rate in the convection section.
Due to the different combustion characteristics of H2, the existing burners may not be suitable. Natural gas has a higher energy density than H2. Therefore, for the same volume of fuel, natural gas can produce more heat. To deliver the same amount of energy, an H2 firing furnace and its burners must be larger and/or designed to operate at a higher volumetric flow rate. H2 has a lower viscosity and higher specific volume than natural gas, which makes it flow faster. The increased flow rate means that an H2 burner must be designed to handle a higher volume and speed. Moreover, H2 has a higher flame speed and a lower ignition temperature, so its flame moves faster and positions itself differently, potentially leading to a phenomenon called “flashback” where the flame travels back into the burner. This could be prevented by adjusting the burner’s design to ensure proper fuel and air mixing. Due to the higher flame temperature of H2, the burner and adjacent materials should be designed to withstand higher temperatures, possibly requiring the use of heat-resistant materials. Given the wide flammability range and nearly invisible flame of H2, safety measures might necessitate design alterations that could influence the size of the H2 burner.
Piping. When considering the replacement of fuel from natural gas to H2, it is imperative to review the design and conditions of the existing natural gas pipelines and infrastructure. H2 has a significantly lower energy density by volume than natural gas. Therefore, to maintain cracking capacity, it may be necessary to switch to larger pipes, install additional pipes in parallel or raise the operating pressures to deliver the same amount of energy as natural gas. If the existing pipeline is used without increasing the pressure, H2 velocities could be more than three times that of natural gas, leading to erosional and seal-retention risks in valves. The resulting pressure drop will also be several times higher,3 and many control valves will require revamping or replacement.
Introducing H2 directly into the existing cracking furnace system may be unwise and impractical because it could shorten the longevity of the system due to various unfavorable factors such as higher pressures and temperatures, increased stress and corrosion (because of H2 attack), incompatible material composition, shortened age of the pipelines and coking issues. For example, H2 molecules are much smaller than methane molecules, potentially leading to higher leakage rates through the walls and joints of the pipes, thus posing financial and safety risks. H2’s ability to easily diffuse through metal walls could also be a problem. Some natural gas transport metal pipes may degrade if exposed to H2, especially under high temperatures and pressures, resulting in cracking or embrittlement of the pipeline. Similarly, pipe fittings made of polymers (e.g., mechanical coupling seals, flange seals, valve seats), which are designed for natural gas, might leak when exposed to H2. As for welding and heat treatment, natural gas pipelines generally do not undergo heat treatment after welding. Therefore, adding H2 into these pipelines might cause cracks to form in high-stress areas around the welds.4,5,6
Safety systems. Safety considerations for H2 and natural gas systems have some similarities and differences. H2 can ignite and explode more easily, and it can be more difficult to detect leakage through seals and joints, and to observe these leaks even in daylight. H2 also tends to rise and disperse quickly (larger flammable clouds may result). There are indications that a blend of methane and H2, with H2 constituting less than 30% of the volume, may have characteristics akin to natural gas. Conversely, for blends where H2 comprises 40% or higher, there is a notable hazard of creating destructive overpressures and a possibility of a transition from deflagration to detonation. When stored as compressed gas or liquid, the storage system must be designed to withstand very high pressures or very low temperatures, respectively. The exact safety devices and measures needed will depend on the specific use case and local regulations, and a thorough risk assessment should always be conducted when designing and operating an H2 system.
Storage and transportation. Large-scale H2 storage is challenging and necessary, primarily due to H2’s low energy density by volume. The two common methods are to store it under high pressure in tanks as compressed H2 (usually 350 bar–700 bar) or to cool and condense it as liquid H2. Either method is energy-intensive and requires large capital investments.
For transportation, H2 should be delivered through pipelines, especially when delivering large amounts over short to medium distances. Although it can be transported as compressed gas in high-pressure tank trucks, or as a cryogenic liquid in specially insulated tankers, either method is very expensive for both large quantities and long distances.
TABLE 2 summarizes the key parameters to consider when planning the transition from natural gas to H2. Note: They are interconnected, and a change in one can affect numerous others. Therefore, a systematic approach should be taken. Consultation with experts in the field is also highly recommended.
Regulations and standards. While regulations and standards for natural gas burners are well established, this has not been the case for H2. It is necessary to deal with an uncertain regulatory environment where standards may be either more stringent or less well-defined. The directly and indirectly relevant standards for H2 storage and transportation are listed in TABLE 3.7,8
Takeaway. The transition from natural gas to H2 fuel in steam crackers is a crucial step toward achieving industrial decarbonization of olefin plants. However, this transition is not without its technical challenges. While the task is challenging and complex, it is certainly not impossible. Ongoing developments in this area are key to overcoming these technical challenges and realizing the potential benefits of H2 in steam crackers. The successful transition to H2 not only represents a significant stride in reducing industrial emissions, but it also positions steam cracking as part of a sustainable and carbon-neutral future. HP
LITERATURE CITED
Smith Wattanasoponvanij is a Process Technology Engineer for Olefins and Operations Technology at SCG Chemicals Co. Ltd., Thailand, where he has worked in process design, and in research and development. He has been working more than 8 yr in technology development in various fields involving business and market studies, technology research, research and process design, and feasibility studies, among others. He has been trustful in scaling up and down with many successfully implemented cases.
Wiwut Tanthapanichakoon is a Technology Adviser for Olefins and Operations Technology at SCG Chemicals, a Fellow of the Academy of Science, the Royal Institute of Thailand, and an Emeritus Professor at the Tokyo Institute of Technology, Japan, and Chulalongkorn University, Thailand. Dr. Tanthapanichakoon has 40 yr of teaching and research experience in heat and mass transfer operations, particle technology, aerosol engineering, and process analysis and simulation. He was the founding Executive Director of the National Nanotechnology Center (NANOTEC) under the National Science and Technology Development Agency (NSTDA). He earned a BEng (ChE) degree from Kyoto University in Japan, and a PhD (ChE) from the University of Texas at Austin (U.S.).
Khavinet Lourvanij is the Chief Process Technologist for Olefins and Operations Technology at SCG Chemicals. He is responsible for leading new process technology scale-up and applications toward business interests. Dr. Lourvanij has more than 20 yr of experience in the petroleum and petrochemical industries, covering technology and operations, process development and execution, and the deployment of advanced technologies. He earned a BS degree in chemical technology from Chulalongkorn University in Thailand, an MS degree and PhD (ChE) from Oregon State University (U.S.).
Apinan Soottitantawat has worked as an instructor for 15 yr in the chemical engineering department at Chulalongkorn University, Thailand. He has experience teaching various chemical engineering subjects, including mass/momentum/heat transfer operations, particle technology, advanced reaction kinetics and reactor design, thermodynamics and chemical process design, among others. His research interests include the encapsulation process, process development and scale-up. He is an advisor for more than 50 graduated Master’s students and five graduated doctoral students, and has authored more than 70 articles.