Evaluating hydrogen rich fuel gas firing
A sudden shift to hydrogen rich fuel gas firing may not be prudent if a fired heater is not designed for it.
RUPAM MUKHERJEE and SHILPA SINGH
Engineers India Limited (EIL)
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Fired heaters are designed to combust refinery fuel gas which may contain a wide array of components including hydrogen. Generally, hydrogen content in refinery fuel gas is limited to 10-30 vol% depending on the refinery configuration and hydrogen recovery technologies employed. Hydrogen, being a fuel with appreciably higher heating value and low energy per unit volume, has to be treated differently. In general, maximum recovery of hydrogen is attempted across the refinery complex due to its high commercial value. However, there can be instances when a gas stream rich in hydrogen has to be routed to the fuel gas header. This article addresses the impact on thermal design and performance evaluation of a fired heater for hydrogen rich fuel gas firing (hydrogen content up to 90 vol%). As a sample case, a natural draft furnace of moderate heat duty in hydrotreating service has been selected for the study.
The study shows that shifting from conventional refinery fuel gas to hydrogen rich fuel gas may affect the thermal design and performance parameters of the furnace only marginally, unless the furnace is fired near to metallurgical limits or designed with too little margin to manoeuvre.
There are enough reasons, explained in the following sections, for the need for a detailed study. It is seen that hydrogen rich gas firing helps the environmental cause by reducing carbon dioxide emissions significantly, thereby helping the refinery with carbon credits. Thus, hydrogen rich fuel gas firing may be an alternative to carbon capture and sequestration for installations struggling with their carbon footprints and may become a way of keeping greenhouse gas emissions at bay. However, there are various other factors which should be kept in mind when planning to shift to hydrogen rich fuel gas firing.
Why worry about high hydrogen in fuel gas?
Petroleum refineries burn a wide array of fuel gas mixtures depending on the group of units operating or under shutdown. Accordingly, the fuel gas composition can vary to a large extent. In general, refineries have a complex hydrogen balance across the complex to ensure that minimal hydrogen is routed to flare or for other non-process uses. Hydrogen being a valuable utility, its recovery and re-use is maximised to the extent that it is economically feasible.
However, there can be certain instances due to operational upsets of certain units or failure of critical equipment which may end in dumping precious hydrogen into the fuel gas header. To add to this concern, operational upsets may last for days while the fuel for a fired heater has a rich composition of hydrogen across the refinery. When designing fired heaters, the gamut of fuel compositions expected to be fired in the furnace is well defined. Burners are a specialised item requiring intricate know-how, and should be suited to a wide range of fuel gases. Dumping hydrogen into the fuel gas header may lead to the fuel gas composition breaching the range for which the burners were initially designed. Such excursions, if they persist for a long time, will impact the performance and operation of process fired heaters. Thus it is imperative that a detailed study of process furnaces is undertaken to evaluate the impact of changing fuel gas composition. Hydrogen concentration in fuel gas plays a prominent role as it sharply alters the molecular weight of the fuel gas mix. Methane, the other main component, should also be considered in conjunction with hydrogen to work out various scenarios.
Basis of case study: parameters and considerations
In order to evaluate the impact of hydrogen burning in the fired heater, there are a few aspects to consider, like the suitability of the fired heater design for hydrogen rich fuel gas, the suitability of the burner design, and the suitability of fuel piping, control valves and other equipment. The suitability of the fired heater design for hydrogen rich fuel gas firing demands thorough evaluation; this article focuses on this aspect through a case study.
The generic combustion parameters of methane and hydrogen are shown in Table 1. Several of the parameters shown in Table 1 are critical when applied to fired heaters. For example, hydrogen has a much higher heating value than methane. Hence, for the same fired duty the mass of hydrogen to be fired is far lower. However, the density of hydrogen is appreciably lower than that of methane. Hence, the volumetric flow of hydrogen required to attain the same heat input as for methane is much higher. Accordingly, fuel supply piping, fittings, and valves need to be adequately designed to handle this additional volume.
Probably the most critical point to note is the difference in flame speed, a measure of the rate at which the fuel burns. Hydrogen has a flame speed 10 times that of methane, which means the chances of flashback of hydrogen at lower loads is high. This needs to be taken care of during the burner design to avoid flashback of burner flame at lower loads, leading to extinguishing of the flame and release of unburnt hydrocarbons into the firebox, a severe safety hazard.
To address such concerns, a detailed study was undertaken. For the purpose of the study, a natural draft gasoil heater with the configuration shown in Table 2 was selected.
The study was carried out using in-house software programs and FRNC 5PC software for the fired heater simulation.
Three ratios of methane to hydrogen were considered for analysis:
• Case 1: 90% Methane + 10 vol% hydrogen
• Case 2: 50% Methane + 50 vol% hydrogen
• Case 3: 10% Methane + 90 vol% hydrogen
Case 1 represents a common refinery fuel gas composition where hydrogen recovery is maximised through refinery off-gas pressure swing absorption (ROG PSA). In general, refiners maximise extraction of hydrogen to the extent that this is economically beneficial and provides enough energy content for the fuel gas header.
Case 2 is a common refinery ratio when any or a group of units which are heavy contributors to the fuel gas balance are under shutdown for maintenance or upset. For example, units such as the FCC or DCU contribute to the fuel gas mix; if they are shut down, this may drive the refinery fuel gas composition towards the lighter end. Similarly, if the ROG PSA is taken off for maintenance, or in the event of an equipment level upset, the hydrogen rich fuel gas from the respective unit is bypassed around the ROG PSA and routed directly to the header, which can drive the fuel gas mix to the lighter side. If ROG PSA is not used in a refinery, Case 2 effectively becomes the normal fuel gas scenario.
Case 3 is an extreme case taking into account all of the scenarios described for Case 2. Hence, the shutdown of any fuel gas contributing units bypassing the ROG PSA for maintenance often results in a fuel gas mix as high as 80 vol% hydrogen. In the current study, Case 3’s hydrogen content was chosen to check the extremes of thermal design and to test the metallurgical limits. The results of Case 3 can be extended to the more practical scenario of 80 vol% hydrogen.
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