M. W. DA SILVA, São José dos Campos, São Paulo, Brazil
The downstream industry is challenged by the increasing demand to reduce its environmental impacts. The leading players are actively called to improve their environmental, social and governance (ESG) policies, seeking to minimize their environmental footprint, as well as their impact on the communities close to their refining and petrochemical assets.
Flare systems are one of the most important assets in a crude oil refinery and can have a significant impact on adjacent communities. These assets are dedicated to operating like a safety system of the refinery, capable of safely burning the gases from safety relief systems of refining processing units, especially when there is operational instability or during planned shutdown events. In other words, the flare system can be considered as safety equipment and is essential for refining and petrochemical assets to ensure stability and the safe shutdown of processing units.
The absence of these systems can lead to severe process accidents with great impact on the environment and people. Tragically, an example is the 1984 Bhopal, India disaster that occurred in a process plant operated by Union Carbide. Approximately 2,300 people died due to the release of a cloud of methyl isocyanate without burn once the flaring system was out of service.
Today, the evolution of processing technologies is leading to reliable and efficient flaring systems; however, the major concern related to this equipment is the reduction of carbon emissions from unnecessary gas flaring. According to the International Energy Agency (IEA), in 2022, global flaring systems were responsible for the emissions of 500,000 t of carbon dioxide equivalent (CO2e).1 This increased the pressure on downstream players to improve their policies related to flaring systems operation to minimize unnecessary gas flares, and led others to commit capital investment (CAPEX) to the installation of systems capable of reducing the flowrate of unnecessary gases to flare.
Crude oil refinery processing units are designed to operate under stable operating conditions or in steady-state regime. Despite this, these assets sometimes face adverse scenarios where operating transients lead to instabilities that demand mass relief to avoid overpressure in the process equipment and process safety accidents. To control the risk of severe process safety accidents related to overpressure of process equipment above their design limits, it is necessary to rely on a process safety relief system that allows the quick and safe depressurization of the contents of the processing units.
Crude oil refinery flaring systems are designed to receive the discharge of process safety valves and relief systems of processing units to ensure process safety during operating transients like power failure and cooling water failure, which tend to cause overpressure due to mass accumulation in the operating systems. A typical flaring system is presented in FIG. 1.
The main role of a flaring system is converting the relieved hydrocarbons and harmful gases into less impactful products through combustion in a controlled and safe manner. Flaring systems can be classified as described in FIG. 2.
Most crude oil refineries utilize elevated flares—in this case, the flare tip is elevated from the ground to reduce the issues related to heat radiation and to contribute to the dispersion of burned gases, helping achieve greater control of odor emanation and noise issues. The most common flaring system in crude oil refineries is the single point elevated flare that presents low pressure drop. This fundamental characteristic and advantage offer low back pressure and, consequently, help to lower gas relief systems of the processing units and improve relief flow.
Despite this advantage, the multipoint elevated flare was developed to achieve a smokeless operation—even in emergency scenarios—and improve burning efficiency. In this flaring system, the relieved gases are distributed throughout multiple burners. The main disadvantage of multipoint flares is the relatively high pressure drop in the flare tip when compared to the single point flare.
Ground flaring systems apply to multiple burners at ground level—compared with an elevated flare, these systems offer advantages like easier access for maintenance and lower flame exposure to adjacent communities, which can be a significant issue in populated areas. Due to their characteristics, ground flares present high pressure drops and demand sufficient relief pressure from the process gases to ensure optimal operation and performance. Ground flares normally demand higher CAPEX for installation than elevated flares for the equivalent burning capacity.
Regarding the design and operation of flaring systems, one of the main challenges is to achieve smokeless operation. Smoke formation is caused by the incomplete combustion of hydrocarbons, leading to the emanation of non-burned carbon (i.e., black smoke). There is a classification of the intensity of black smoke emanation that helps designers determine the burning process’s efficiency.2 The Ringelmann scale is a measure of density and opacity of smoke, and is summarized below:
Ringelmann 0—0% opacity
Ringelmann 1—20% opacity
Ringelmann 2 —40% opacity
Ringelmann 3—60% opacity
Ringelmann 4—80% opacity
Ringelmann 5—100% opacity.
Normally, flaring systems are designed to reach smokeless operation and score lower than 1 on the Ringelmann scale. To achieve this goal, promoting the mixture in the flare tip is essential. Smoke or incomplete combustion is due to a poor mixture between the gases and oxygen.
To overcome a poor mixture of oxygen and gases, it is necessary to promote turbulence and ensure adequate air supply to the flare tip. The following strategies can be used:
Steam-assisted flares: Steam is supplied to the flare tip to promote turbulence and drag air to the flame.
Air-assisted flare: Normally applied in refineries without the availability of steam in sufficient quantity.
Gas-assisted flares: Applied in specific cases, mainly when the availability of steam in the refinery is limited. In this case, a gas (normally natural gas) is supplied to multiple points in the flare to drag air to the flame and help achieve clean and stable combustion. The gas-assisted flare can be an attractive strategy to burn low calorific value gases like ammonia and hydrogen sulfide (H2S) once the gas raises the calorific value of the mixture and helps it to reach efficient combustion.
Pressure-assisted flares: In this case, the energy of the relived gases is used to promoted turbulence and maximize the mixture with the air leading to an improved combustion process.
Steam-assisted flares are most commonly used within crude oil refineries due to the higher availability, reliability and low cost of steam when compared to other assisting systems.
Another significant factor that impacts the smokeless operation of a flaring system is the composition of the burning gases. Heavy hydrocarbons, olefins and aromatics molecules present a higher carbon/hydrogen (H2) ratio and tend to produce more smoke during the burning process, demanding a higher flowrate of steam to achieve smokeless operation. It is important to know the makeup of those gases produced by deep conversion processes like fluidized catalytic cracking (FCC) and delayed coking units, which tend to be composed of high concentrations of aromatics and olefins. Based on this, it is expected that an emergency in an FCC unit (FCCU) and delayed coker will demand a higher steam flowrate to the flare to reach smokeless operation (e.g., an emergency scenario in a distillation processing unit).
Conventional flares have two points of steam injection: an upper injection and an inferior injection, shown in FIG. 3.
Inferior injection points are positioned in the center of the flare tubulation and further assist the combustion process, helping to cool the flare tip and minimizing flare degradation due to metallurgic damages produced by high temperatures. Metallurgic damage is even more relevant if the flare tip operates burning gases with high concentrations of hydrogen (H2), which can induce stepwise cracking and H2 embrittlement.
One of the main operating issues of conventional flares is the poor distribution of the burning mixture in the flare tip for diameters > 36 in. due to the poor air access to the center region of the flare tip, leading to smoke production. To overcome this, some flaring licensors have developed new design concepts considering new points of steam injection in the inferior region of the flare tip, as presented in FIG. 4.
Flare tips applying the lower steam injection points, as presented in FIG. 4 and described as high-efficiency flares, minimize the effect of rich mixture formation in the center of the flare tubulation, reducing black smoke formation.
Controlling steam flowrate to the flare tip is fundamental to reliable and efficient operation of the flaring system. Excess steam in the upper region of the flare tip can lead to the steam capping phenomenon where excess steam creates a kind of seal in the flare tip, forcing the flaring gases to reduce and causing a flashback effect. This phenomenon causes overheating of the flare tip and reduces the operating lifecycle of the flare system—in extreme cases, the result can be an extinguished flare or a flame-out effect.
The ideal steam flowrate to the flare tip should consider the flame aspect and ensure an adequate balance between the gas velocity in the flare tip and the flame velocity—if the velocity in the flare tip is low, the flashback effect can occur, leading to overheating of the flare tip. If the velocity is high, it is possible to get a flame out; however, the flame will be extinguished with the additional risk of explosion of the flare stack due to the explosive mixture. The flare tip exit speed must be such that the flame forms immediately at the burner exit to produce an attached stable flame, because high velocity can lead to a flame-out effect and blow off the flare tip.
Another effect of the over steaming is the production of poor mixture and inefficient combustion, which can produce smoke. Furthermore, the over steaming waste energy increases OPEX. The operating concept of the flare should consider the minimum steam flow rated necessary to ensure flare tip cooling and protection, as well as the additional amount capable of allowing a stable flame without black smoke formation. Furthermore, the over steaming produces excessive aeration of the flame, leading to poor flame quality due to the dilution of the combustion zone. The over steaming process is easily identified through the steam condensation in the base of the flare tip (white plume formation) as well as the transparent and light yellow color of the flame.
Conversely, the low steam flowrates to the flare tip cause under-aeration of the combustion zone, leading to black smoke formation and the presence of an orange to red flame.
MAIN COMPONENTS OF FLARING SYSTEMS
Typical flaring systems are composed of a series of essential process equipment and instruments aiming to ensure the maximum performance and safety to the refinery. The main components of typical flaring systems are presented in the sections below.
Stack sealing system. The main objective of the stack sealing system is to prevent air from entering the flare stack. The air can lead to the formation of a potentially explosive mixture inside the flare stack. To prevent this risk, the flare stack operates under positive pressure through the injection of purge gas (normally natural gas), avoiding any oxygen due to wind and thermal contraction effects.
To reduce the consumption of purge gas, modern flaring systems rely on a flashback-preventing system that can apply two seal technologies (buoyancy and velocity seals), as shown in FIG. 5.3
The buoyancy seal principle is based on the difference between the density of air and purge gas. The most common buoyancy seal for an elevated flare is an inverted can device, which is assembled upstream of the flare tip, as presented in Figure 6.6 from the source.3
The dynamic or velocity seal is sized so that it forces air to move away from the burner walls. This air meets the ascending purge gas and is drawn out of the tip.
The buoyancy seal tends to lead to lower purge gas consumption than the velocity seal but presents higher installation cost and higher pressure drop. Another key question to consider in the choice between the buoyancy and velocity seal is the higher risk of blocking in the buoyancy seals due to the draining line blocking, especially in refineries without chemical flaring systems.
Ignition system. This system is responsible for igniting the flaring gases in the flare tip—the system keeps a group of pilots ignited that operate continuously. Considering the pilots are responsible for keeping the flare lit, the gas supply for this system should be the most reliable, including redundancy, as recommended by 521 API.4
Two pilots ignition systems are commonly applied in refinery flaring systems:
Flame front generator: A flammable mixture of gas and air is produced in a tubulation that is conducted to an ignition panel and then feeds the pilots.
Electronic ignition: The ignition is made in the pilot body through a spark generation.
Considering that this system is critical to the process safety of the refinery, the flaring system’s design normally considers both systems as redundant in the flare system. Another key factor in the pilot ignition system is the pilot flame detection. The system should be able to distinguish the pilot flame of the flare tip flame, and each pilot must have an individual flame detection instrument.
The most common way applied to pilot flame detection is to use thermocouples; however, it is possible to use acoustic and radiant flame detectors.
Liquid separation system. The flaring system is designed to burn gases, and the liquid relieved by the processing units should be separated and recovered to the process aiming to avoid damage and poor efficiency of the flare tip.
The presence of liquid in the flare can lead to flame extinguishing, flaming rain phenomena (liquid projection in the flare tip), flame instability, black smoke due to rich mixture formation and higher pressure drop in the flare system.
To remove the liquid from the relived gases, the flaring systems rely on a knockout or a blowdown vessel. The vessel is dimensioned to ensure adequate residence time to allow the maximum liquid recovery from the waste gases even due to the vapor condensation from the process gases.
According to the refining scheme, some processing units can use internal blowdown vessels to minimize the presence of the liquid in the flaring system—this is the case with delayed coking and solvent deasphalting units. The process arrangement of a flaring system blowdown vessel is presented in FIG. 1.
The liquid accumulated in the blowdown vessel is pumped to a residue recovery tank for recovery in the hydrocarbon phase, normally in deep conversion units like an FCCU, while the water phase is directed to sour water stripping units.
The draining operations to the flaring systems demand specific risk analysis, especially related to the liquified gases draining operations like liquefied petroleum gas (LPG) and propylene to the flaring header. Some refineries rely on closed draining systems in their liquified gas storage tank farms. To remove the water accumulated in the bottom of the spheres, these draining operations should be monitored, and the draining rate should be controlled to avoid a quick blowdown refrigeration process that could raise the liquified gas solubility in the liquid, leading to cavitation of the blowdown pumps and causing process safety accidents in case of emergency relief of the processing units. During the draining operations of liquified gases, it is necessary to monitor the temperature in the blowdown vessel to avoid cavitation of the blowdown pumps.
Some refineries install cyclone separation vessels downstream of the blowdown vessels to maximize the efficiency of liquid separation from the flaring gases through the condensation of liquid droplets using centrifugal forces. The side effect of the cyclone separation vessel is additional pressure drop in the flare header.
Liquid seal vessel. The liquid seal vessel is positioned between the blowdown vessel and the flare stack. The objective of the liquid seal is to promote a kind of barrier between the relived gases and the gases in the stack to avoid air entering the system and the formation of an explosive mixture inside the flare system. Sudden cooling or gas condensation can create negative pressures, and the role of the liquid vessel is to make the gases bubble inside the liquid, avoiding the flashback occurrence.
The liquid seal is responsible to keep a positive pressure in the flaring system, avoiding the air entering even in non-emergency operations. It is important to control the liquid seal level to ensure a stable and safe operation. Lower levels can lead to air access to the system and the explosive formation inside the flare system, and high levels can produce high back pressure to the relief system as well as pulsation of the flame. The level of the liquid seal vessel is controlled through the addition or draining of industrial water to the vessel.
Flare header. The flare header is the tubulation responsible to receive the relief of the processing units or process facilities and conduct these gases and liquids to the blowdown and flare tip to burn. The design of the flare header should avoid low points capable of accumulating liquid, which can accelerate the corrosion process as well as produce hydraulic transients during emergency discharges of the processing units.
The dimensions and, consequently, the cost of the flare header installation can be significantly reduced through actions to reduce the gas flowrate to the flare system in emergency scenarios. Some refineries use water injection over the heat exchangers of the main contributing systems—like the top of the main fractionating tower in FCCUs, and distillation and delayed coking units to reduce the gas flowrate to the flare system and reduce the dimensions of the system, maintaining the hydraulic capacity.
Flare gas recovery system. The increasing need to reduce the carbon footprint of the refining business as well as implement more efficient operations impels refiners to reduce gas flaring to minimize carbon emissions and reduce OPEX, considering that a large portion of the flared gases can be recovered.
A critical issue to flare systems is the constant relief of waste gas with high concentrations of H2. As mentioned previously, H2 can cause severe damage to the flare tip by reducing the operating lifecycle of the equipment. Other reasons to avoid H2 relief to the flare system are economic and environmental impact. H2 generation is an energy intensive process that produces high amounts of carbon dioxide (CO2), and H2 waste is a serious concern to the modern refining industry. The conventional H2 production route adopted by most refiners is steam methane reforming (SMR). This route still presents high emissions of greenhouse gases (11 t of CO2/t of H2) and an average production cost of $1/kg H2 to $2.1/kg of H2.5
H2 demand increased strongly in the last decades following the necessity of hydrotreatment unit installations in refineries to comply with the pressure to reduce the content of contaminants like sulfur and nitrogen in the petroleum derivates and consequently minimizing the environmental impact caused by fuels burn. H2 became a fundamental production input to modern crude oil refineries, and its adequate management is a key factor to ensure controlled operating costs and competitiveness in the market, as well as allowing the production of marketable crude oil derivatives. H2 management actions start with a mass balance involving the H2 network that is composed of H2 sources, H2 purification systems and H2 consumers (FIG. 6).
H2 generation relies on the adopted refining configuration. Normally, refineries that rely on catalytic reforming units apply the H2 produced in this process unit to compose a relevant part of the H2 network becoming an important internal source of H2.
H2 purifying technologies are another important part of the H2 network. Modern refineries normally apply pressure swing adsorption (PSA) technologies to purify the H2, reaching purity > 99%. However, some refiners still use treatments based on amine treatment, despite the lower CAPEX requirement compared to PSA technologies. Amine treating units produce H2 with low purity and this represents a great disadvantage, especially to refiners with deep conversion hydroprocessing units. Another H2 purifying technology that is commercially available is membrane separation that can reach purity levels of 98%, or 96% with cryogenic processes.6,7
H2 purifiers play a key role in H2 management once the H2 recovery in off-gases is controlled. One of the main sources of H2 losses in refineries is the burn as fuel gas during poor recovery capacity.
The adequate balance between production and consumption of H2 is a key factor to minimize H2 flaring. It is possible to apply optimization techniques like a pinch strategy to reach balance between producers and consumers of H2 in the refinery (FIG. 7).
The flaring gas recovery system applies to a compressor to suction the gas phase of the blowdown vessel and send it to the fuel gas system of the refinery or, for H2-rich gas, for a PSA capable of promoting the H2 recovery to reuse in the refining processes. A typical flare gas recovery system is presented in FIG. 8.
Takeaways. As described above, refiners are under pressure to reduce carbon emissions, and the competitive environment of the downstream industry demands increasing operational efficiency from downstream players. Under this scenario, the flare gas recovery system is essential to a refinery’s operation in the short term.
The greater issue related to the operation of a flare recovery gas system is the poor control and reliability of the compressor due to the constant variations in flowrate and composition of the gas. Among the strategies available to overcome this issue is to apply liquid-ring compressors to this service, or even eductors using amines as drive fluid.
Another alternative strategy to a central flare recovery gas unit is using lower capacity-dedicated systems installed in the battery limits of each contributor. This strategy will allow improved control of the gas composition and better operating performance to the flare gas recovery compressors.8
The decision to install a flare recovery system should be followed by an adequate revision of the risk analysis of the flare system. Operation of the flare recovery system will demand higher levels and better control of the hydraulic seal liquid of the flare stack to avoid air access to the flare stack, leading to risk of explosion. HP
Part 2 of this article will cover the main operating issues of flaring systems and insights on how to manage and solve these issues to maximize performance of the refinery flaring systems.
LITERATURE CITED
International Energy Agency (IEA), “Global Methane Tracker 2023: Overview—Methane emissions from the global energy sector rose to nearly 135 Mt in 2022,” 2023, online: Overview – Global Methane Tracker 2023 – Analysis - IEA
American Petroleum Institute (API ) Standard 537, “Flare details for general refinery and petrochemical service,” 3rd Ed., September 2001.
Yoon, B. H., “Optimizing flare operation through proper design,” Chemical Engineering Magazine, October 2015.
American Petroleum Institute (API) Recommended Practice 521, “Guide for pressure-relieving and depressing systems,” 6th Ed., January 2014.
Energy Transitions Commission (ETC), “Making the hydrogen economy possible: Accelerating clean hydrogen in an electrified economy,” April 2021, online: https://www.energy-transitions.org/publications/making-clean-hydrogen-possible/
Fahim, M. A., T. A. Al-Sahhaf and A. S. Elkilani, Fundamentals of Petroleum Refining, 1st Ed. Elsevier Press, 2010.
John Zink Co., The John Zink Hamworthy Combustion Handbook, Vol. 3, “Applications, Chapter 11: Flares,” CRC Press LLC, 2001.
Myers, R. A., Handbook of Petroleum Refining Processes, 3rd Ed., McGraw-Hill, 2004.
Marcio Wagner da Silva is Process Engineering Manager at a crude oil refinery based in São José dos Campos, Brazil. He earned a BS degree in chemical engineering from the University of Maringa (UEM), Brazil and a PhD in chemical engineering from the University of Campinas (UNICAMP), Brazil. He has extensive experience in research, design and construction in the oil and gas industry, including developing and coordinating projects for operational improvements and debottlenecking to bottom barrel units. Dr. Wagner also earned an MBA in project management from the Federal University of Rio de Janeiro (UFRJ), an MS degree in operations and production management at the University of Sao Paulo (USP), and an MS degree in digital transformation at Pontifical Catholic University of Rio Grande do Sul (PUC/RS), and is certified in Business from Getulio Vargas Foundation (FGV). Dr. Wagner is also author of two books: Crude Oil Refining: Crude Oil Refining - A Simplified Approach, published in 2023, and Transfer & Stockpiling Operations in the Crude Oil Refining Industry, published in 2025.