A wide range of factors must be taken into account before selecting the most appropriate reforming technology
From the agrochemicals sector to steel production, from petroleum refineries to chemicals production — many sectors of the chemical process industries (CPI) would grind to a halt overnight without one crucial ingredient: syngas. Short for synthesis gas, syngas describes a blend of primarily hydrogen and carbon monoxide. Highly versatile, syngas forms the basis for diverse end products that are deployed in a wide range of industrial scenarios (see box below).
Broadly speaking, syngas is generated by one of two ways: using a methane reforming process, based on a gaseous reaction principle; or applying a gasification technique, centered around a heterogeneous reaction. It cannot be claimed that one method is categorically better than the other; rather, the technology chosen will depend on the availability of feedstock and the intended downstream application. In terms of feedstock, reforming techniques are ideal for gases and light hydrocarbon liquids, while gasification is generally reserved for heavier liquids and solids, such as coal and biomass. In this context, methane reforming technology is growing in popularity as the spread of hydraulic fracturing contributes to a fall in the price of natural gas.
When it comes to the downstream application, on the other hand, the ratio of H2 to CO in the final syngas will vary depending on the process used. The rule of thumb is that reforming techniques yield a higher H2 content, while gasification tips the balance in favor of CO. For example, reforming natural gas can generate an H2-to-CO ratio of up to 5.5, while the corresponding figure for entrained-flow coal gasification hovers between 0.35 and 0.8. Considering that the bulk of syngas manufactured worldwide is used to produce H2, as outlined above, this article focuses on methane-reforming technologies as the most efficient way of generating H2.
Overview of CH4 reforming
The reforming process itself, however, comes in a number of different guises. And the choice of technology is crucial, as it will have implications for all other aspects of the syngas production process.
Regardless of the generation method deployed, the journey from feedstock to syngas comprises a number of basic steps. First, the feedstock is pre-treated to remove sulfur. Depending on downstream processing requirements, it may also undergo a pre-reforming stage. The feedstock is now ready to begin the transformation into syngas, by means of a reforming process — and it is here that significant differences between the various techniques become apparent, as will be discussed below. After reforming, the syngas is conditioned to adjust the ratio of components as required, before being purified in a final step. Again, the choice of reforming process will impact on the options available in these final two stages.
The following section outlines in more detail the four main technologies used in the all-important reforming stage. These can be broken down into two categories: three catalytic models — steam methane reforming (SMR), heat exchange reforming, and autothermal reforming — and the non-catalytic partial oxidation process.
Steam methane reforming. A good place to begin is with the most common syngas generation technology: SMR, also referred to simply as steam reforming. This process is based on an endothermic reaction. After blending the desulfurized feed with steam, the mixture is superheated before being routed to a primary reformer. This unit comprises a number of tubes containing a catalyst. As heat is applied to the tubes externally from the surrounding furnace, the catalyst sets off a reaction between the feedstock and the steam, transforming the methane and water into a syngas comprising H2, CO, CO2, residual CH4, N2 and H2O.
Heat exchange reforming. Closely related to SMR is heat exchange reforming. This term describes technologies such as gas-heated reformers and post-reformers, which recover process heat to catalyst tubes. This energy — which would otherwise contribute to steam production — is used to trigger a further reforming reaction, resulting in greater thermal efficiency. The heat exchange reactor can be arranged in series or parallel to other reforming technologies. Conditions and limits are similar to SMR, and a wide range of reactor designs are available. Many heat-exchange reformers are essentially heat exchangers with a catalyst on the tube or shell side. However, recent innovations include the potential to perform heat exchange inside an SMR tube, reducing equipment cost and making the technology an attractive option for low-steam co-production and zero-steam H2 generation, while simultaneously cutting CO2 emissions.
Autothermal reforming. Like SMR and heat exchange reforming, authothermal reforming (ATR) is a catalytic process. However, it differs fundamentally from these two methods in terms of how the reforming reaction takes place. The feedstream of hydrocarbon and steam is fed into a refractory-lined pressure vessel, where a top-mounted burner adds oxygen to the mixture. The exothermic reaction of feedstock and reformed gas with O2 triggers partial combustion to begin the transformation to syngas. This is completed by means of an endothermic reforming reaction in the catalyst bed.
The addition of O2 and the higher temperatures involved in ATR mean that the chemical composition of the resulting gas is different from that generated by means of SMR or heat exchange reforming. While an air-blown autothermal reformer is preferred for conventional ammonia production, for other applications (such as syngas for methanol production), a pure O2-blown autothermal reformer is applied. In this article, the term ATR is used to refer to syngas production by ATR using pure O2.
Partial oxidation. The final reforming technique that will be considered is partial oxidation (GasPOX). In marked contrast to the previous three processes, partial oxidation does not require the use of a catalyst. Instead, the reaction is instigated by blending the feedstock directly with O2 and combusting the mixture in a reactor at an extremely high temperature. This exothermic process converts the input material into a syngas with a different composition to that resulting from SMR, heat exchange reforming or ATR.
Each of the reforming technologies described above offers certain benefits for certain applications. As mentioned previously, there is no single best way to generate syngas — the method used will depend on a number of factors. The following section of this article examines a number of key aspects at various stages of the process chain: beginning with feedstock and general process parameters, before moving to end-product characteristics, conditioning and separation options, and cost considerations.
Feedstock. When choosing a generation technology, the availability, price, and properties of the feedstock are key considerations. The hydrogen-to-carbon ratio in the final syngas will vary depending on the feedstock selected, with lighter gases resulting in a higher H2 content and heavier gases tipping the balance toward CO (Table 1).
It is also important to keep in mind that different feedstocks will have different heating values, which has consequences for steam production, utility consumption and system design. Against this background, certain feedstocks are a naturally good fit for specific reforming methods. For all four of the methane reforming technologies discussed here, natural gas is the principle starting point. However, heavier input materials such as liquified petroleum gas (LPG) and naphtha are often used as an alternative in SMR units. Of course, natural gas composition can vary significantly in terms of the proportion of CO2, N2 and heavier hydrocarbons. These differences will directly impact technology selection, depending on the required gas ratio in the end product, as will be discussed in more detail below.
Process parameters. When designing a syngas-generation plant, a number of key parameters must be carefully considered. Although these differ from technology to technology, they are closely related to one another within a single system — with the result that a change in one parameter will often have consequences for the others.
Pressure. Process pressure varies between syngas generation systems, with the most important distinction existing between SMR/heat exchange reforming and ATR/GasPOX. In SMR and heat-exchange reforming units, heat is applied to the feedstock indirectly from outside the reforming tubes, limiting the gas pressure within. With the O2-based processes ATR and GasPOX, on the other hand, the heat comes from an exothermic reaction within a refractory-lined vessel, meaning pressure levels can be much higher. Greater pressure during reforming will translate into lower levels of H2 and higher levels of CH4 in the gas at the reformer outlet.
High pressure can deliver other benefits in terms of the overall process, too. For example, high feed-gas pressure can minimize power requirements for downstream product compression, saving costs. Moreover, it can reduce pipe size in large plants, and makes it possible to supply the end product at higher pressures without the need for an additional compressor. Also, greater pressure provides more options in terms of downstream product separation, as will be discussed later in this article.
Temperature. The temperature at which reforming takes place will directly affect the composition of the syngas generated: the lower the temperature, the greater the proportion of H2; the higher the temperature, the more CO is created and the more CH4 is converted. Once again, the endothermic nature of SMR and heat exchange reforming places limits on how high process temperatures can be — once a certain point is passed, there is a danger of melting the metal reforming tubes. During GasPOX reforming, in contrast, temperatures can soar as high as 1,500°C.
Catalyst. Another important consideration is whether or not the reforming process requires a catalyst. Of the four main technologies discussed here, GasPOX is the only one where a catalyst is not necessary. As catalysts are easily damaged by impurities in the feed material, GasPOX systems are therefore capable of handling heavier, lower-grade materials. Nevertheless, it is essential to track any unwanted trace components: it should be evaluated whether these will have a negative impact on downstream units, and such impurities must be eliminated during gas separation to ensure they do not appear in the final product. Without a catalyst, the temperature must be higher for the reaction to take place, resulting in greater levels of CO in the final syngas.
Oxygen. As ATR and GasPOX reforming both revolve around reactions that require O2, the availability and price of this element will play a role when considering these technologies. Oxygen impacts on the reforming process in a number of ways. By adjusting the amount of O2 added, it is possible to directly control the reforming temperature. And the more steam admixed or the higher the inert content in the feed, the more oxygen will be necessary to reach the required temperature. Indirectly, these higher O2 levels will lead to increased formation of CO2 in the output gas — something that is important to keep in mind in terms of downstream processing and costs. It is perhaps interesting to note, however, that the syngas generated by a GasPOX system will contain less CO2 than that produced by ATR — despite the fact that GasPOX requires more O2 in the feedstream. This is because the temperatures involved in this process are so much higher that much of the CO2 is shifted to CO during the reaction, cancelling out the effects of the increased O2 levels.
Steam. Process steam is another important parameter that can affect the generation process in a number of ways. First of all, the more steam admixed during reforming, the higher the H2-to-CO ratio in the final syngas and the lower the level of export steam co-produced. However, as the volume of steam added increases, an ever-smaller proportion of the steam fraction actually reacts with the hydrogen in the feedstock. A point is reached where the additional steam is no longer adding value — it is simply being heated up only to be cooled down again later in the process, impacting negatively on the overall thermal efficiency of the plant. At the same time, this unconverted steam will require greater heat input, a larger reformer and a larger heat recovery section, all of which have cost implications.
The steam-to-carbon ratio will differ for each reforming technology, depending on the amount of steam required in the process. This ratio ranges from up to 3.0 mol/mol for SMR to just 0.1 mol/mol for GasPOX. In many cases, minimizing the steam-to-carbon ratio can improve the overall thermal efficiency of the plant, lowering costs. For example, by applying pre-reforming in an adiabatic reactor at low temperature upstream of an SMR unit, it is possible to convert higher hydrocarbons in the feed to natural gas, lowering steam-to-carbon ratios.
A minimum steam-to-carbon ratio exists for each reforming method, determined by the reaction kinetics of hydrocarbon cracking during heating and reforming. It is essential not to exceed these limits if carbon formation is to be avoided in the reforming process. Of the four reforming technologies discussed here, the steam-to-carbon ratio limit is lowest for the GasPOX method. As a result, trace amounts of soot are formed during generation; this impurity must subsequently be washed out of the syngas and will also limit the options for re-using process condensate.
It is important to note that a minimum steam flow may be required for downstream units, for example if an iron-based catalyst is used. However, these limits have been relaxed by the introduction of new catalyst products for high- and medium-temperature CO shift.
A final consideration is that increasing co-production of steam can enhance efficiency: depending on plant design, a higher flow of steam, boiler feedwater and demineralized water can be used to capture and reuse more heat energy.
Of course, the most important consideration when generating syngas is the downstream application: what will the final gas be used for? Depending on requirements, producers will look to create a mixture with a specific ratio of H2 to CO, and each technology will produce a different result (Table 2). In general, SMR is the most flexible in this regard. It can yield the highest H2 content, but also enables different ratios for applications in the chemicals and metallurgy sectors. ATR and GasPOX, on the other hand, result in a syngas with a larger CO content, due to the higher temperatures and the O2 used in the process.
The following section discusses in more detail the important points to consider when designing a system to generate the following products: H2, CO and synfuels.
Hydrogen. To generate H2, the feedstock chosen will ideally exhibit an inherently high hydrogen-to-carbon ratio, such as natural gas. It is also possible to produce H2 from more carbon-heavy fuels like naphtha; in this case, the heating value of the feed helps to extract H2 from the steam during the reforming process. However, the overall levels of H2 will be lower and the additional steam must be taken into account in plant design.
For each of the four reforming technologies discussed here, the syngas generated will contain differing levels of H2. With SMR, the resultant gas exhibits the highest H2-to-CO ratio (up to 5.5). At the other end of the scale, the ratio with GasPOX is in the range of 1.5–2.0. Of course, it is possible to change this balance by adding a CO shift unit downstream of the reforming process.
Carbon monoxide. Where the required end product is CO or oxogas, GasPOX can deliver the highest CO levels. CO can, however, also be generated using SMR: in this case, almost all the carbon in the feed is converted to CO, by taking the CO2 and unconverted CH4 remaining in the reformed gas and recycling it back to the feedstream, thereby lowering the H2-to-CO ratio from around 4.5 to 3.0. Moreover, if CO2 is available from an external source, and more than 50% of the CH4 feed molar flow is replaced with CO2, then it is possible to produce H2 and CO in the reformed gas at a ratio of 1. However, it is important to observe the thermodynamic limit in order to avoid carbon formation in the reforming stage.
Synfuels. When manufacturing synthetic fuels, CO2 in the syngas will also be converted to fuel. As such, the optimum syngas composition is expressed in terms of a stoichiometric number, which describes how much CO and CO2 will react with H2 to form methanol or Fischer-Tropsch products. The optimum stoichiometric number can be achieved by deploying more than one technology simultaneously. A combination of SMR and ATR — a process known as combined reforming — is often chosen to produce methanol and synthetic fuels. When using the combined method, the steam reformer is operated at higher pressure (~40 bars) and lower temperature (~750°C). The lower level of methane conversion in the SMR stage (primary reforming) is then compensated by the downstream ATR system (secondary reforming). The required stoichiometric number can be achieved by adjusting the SMR and ATR feed flow ratio, and by separating H2 from the purge gas following methanol synthesis and recycling it back to the upstream syngas generation system.
Combining syngas streams. Another option for large-scale syngas production is to combine syngas streams from different sources — for example, from entrained-flow coal gasification and from a methane reforming unit — to achieve the required product flowrates. This scenario allows the individual syngas production units to run at maximum efficiency, while the mixing process ensures the optimum product-ratio adjustment.
Conditioning and purification
Syngas generation does not end with the reforming process, as the gas created will always contain several unwanted components. First of all, even where a CO shift unit has been deployed, it is never possible to achieve complete conversion to H2 due to the chemical equilibrium at the necessary reaction temperature. Moreover, methane is not fully converted during reforming, and all nitrogen in the feed and in the oxygen stream will end up as N2 in the reformed gas. And of course, the CO2 created as a byproduct will need to be removed in the majority of cases. A number of downstream gas-conditioning and product-separation systems can be used to produce pure gases or gas mixtures. The methods chosen will vary depending on the required end product.
The cost and effort of CO2 extraction will depend on the level of CO2 present and the syngas flow, and the CO2 fraction in the reformed gas will vary in line with the generation technology deployed (Table 3). There are two main reasons for this: differences in the carbon-to-hydrogen ratio for individual feedstocks, and variances in the outlet temperature of the reforming unit in question.
When it comes to product separation, there are three main options downstream of methane reforming: a cryogenic or cold box unit, polymer membranes, or pressure swing adsorption (PSA). The choice of one technology over the other will be influenced by a number of factors. For cryogenic processes, for example, it is important to keep in mind that a higher reforming temperature — as in a GasPOX plant — will contribute to higher methane conversion and lower methane slip. As a result, when separating CO from a syngas with a methane component of 1 mol% or lower following GasPOX reforming, a partial-condensation cold box must be chosen rather than a methane-wash cold box, as the latter requires that the feed gas have a CH4 content of greater than 1.5 mol%. However, the choice of cold box will also depend on the required end product. For example, oxogas can be made readily available from the first column of a partial condensation cold box, while a methane-wash cold box can provide H2-rich gas at high pressure.
Polymer membranes can be an effective means of product separation if quality specifications are lower, or where byproducts are to be recycled. Membrane technology is particularly advantageous in scenarios where the process pressure is high, as is the case in GasPOX plants, for example.
Where the aim is to achieve as pure a H2 stream as possible, PSA is the separation method of choice — enabling H2 recovery of up to 90%. Recently, a new technology has been launched that compresses the remaining tailgas from the PSA process, removes CO2 using cryogenic technology, and recycles the hydrogen back to the PSA via membranes. In addition to lowering CO2-capture costs, this method can increase H2 recovery to over 98%. If using partial oxidation, it can be advantageous to perform conventional CO2 removal followed by methanation to achieve a H2 recovery close to one. This can be the case in instances where the H2 product-quality specification allows for it and the upstream reforming technology requires a syngas cleaning unit for H2S and CO2 anyway.
A note on CO2 emissions
When generating H2, every carbon atom in the feed will be converted into CO2. As such, the more natural gas consumed, the larger the volume of CO2 produced. Any calculation of total CO2 emissions, however, must also take into account the indirect emissions from power production or air separation.
If CO2 removal has been integrated into the technology chain, the capture rate of CO2 from syngas will be higher for those technologies that consume less carbon-containing fuel. Where opportunities exist to recycle CO2 — as in the CO process chain — it is also possible to reduce CO2 emissions. The fuel for the SMR or fired heater will, in this case, primarily comprise H2 extracted from the syngas during product separation.
Needless to say the cost factor will loom large when making decisions on which syngas technology to choose. A number of aspects are of relevance: thermal efficiency, the potential for economies of scale, reliability of the equipment chosen, and plant design.
Thermal efficiency. For all methane-reforming technologies, thermal efficiency is determined by the limitations that exist on the use of low-temperature heat in flue and process gas. Losses can be minimized by optimizing process parameters to reduce fluegas flow and by maximizing the use of internal process heat, for instance, by deploying a pre-reformer or heat exchange reformer. Moreover, technologies designed to use low-temperature heat in reforming plants are becoming more attractive, as they have become more advanced and less expensive in recent years.
The point at which improvements in thermal efficiency outweigh the advantages of higher hydrogen conversion will depend on utility cost factors, particularly steam value and the ratio of feed to fuel cost. This can be calculated by means of an overall utility cost assessment. To take an example, minimizing the steam-to-carbon ratio and lowering methane conversion will not be an attractive option if feed is more expensive than fuel.
In contrast to coal gasification, where high up-front expenditure (capex) is required, the bulk of the total cost breakdown for gas-reforming plants is for operating expenses (opex) — attributable to feed, fuel, oxygen, steam, power and other utilities. This is particularly true of large gas reforming plants, where economies of scale can shift the opex-to-capex ratio to as high as 80:20.
For the four technologies discussed here, it should be noted that they differ in terms of the economies of scale that can be achieved. In the case of steam methane reforming, for example, the relationship of cost to capacity for the system’s tubes and burners is almost linear. However, the SMR furnace and header system scales at a rate of less than one. For ATR and GasPOX reactors, the overall cost-scaling exponent is also below one. This is one of the main reasons why ATR and combined reforming are often chosen for large-scale methanol and synfuel production.
For large-scale synfuels projects, the capital cost of the air separation unit (ASU) must be taken into account, whereas for smaller GasPOX or ATR projects, the price of the O2 will add to operating expense.
Reliability. When calculating the total cost of operating a reforming site, it is essential to take into account the reliability of the plant. What will the price of unforeseen downtime be and what impact will this have on subsequent interruption to product flow? These costs can vary from technology to technology, largely due to the differing effect of downtime on individual downstream production systems. In a petroleum refinery, for example, an interruption to H2 supply can almost lead to a complete shutdown. The same is true of downstream chemical conversion in a CO-production-process chain. A back-up product buffer or a pipeline network connecting several production units and consumers is essential in such cases.
Catalysts and tubes. The critical components in terms of reliability and availability will vary for each reforming technology. For catalytic processes, the catalyst volumes of reactors must be sized in line with planned turnaround periods. Ensuring a well designed plant front-end and steam system will be money well spent, as these measures will prevent catalyst poison traces entering from internal or external sources. In an SMR unit, the steam reformer tubes are the critical component. These are typically designed for a lifetime of 100,000 hours, based on the creep of the centrifugally cast material as it is exposed to high temperatures. A number of steps can be taken to maximize tube lifetime at a competitive cost: for example, by opting for state-of-the-art control systems, over-firing protective functions, automatic SMR start-up sequences and load change functions, proper heat distribution, and advanced design tools.
Burners. For O2-based processes, on the other hand, the main priority is to ensure that the burner is well designed and exceptionally safe. To ensure a long burner lifetime, it is important to first pay close attention to how the feedstock, steam and O2 are fed and mixed at the burner nozzle; second, to minimize the exposure of the burner front to radiation from the high flame temperatures that result from the O2 combustion reaction; and third, to choose carefully the cooling principle of the burner during operation and after plant shutdown.
Whichever generation technology is used, it is imperative to eliminate single points of failure in the control and plant emergency shutdown system. Plant vulnerability studies can define compressor redundancy and identify critical components that require the implementation of online maintenance functionality. Based on this analysis and the required turnaround cycle, a decision can be made on how many redundant reactors are required in a partial oxidation unit, for example, or what number of capital spares (for example, burner and rotor of induced or forced draft fans for the furnace or heater) are necessary for an SMR, ATR or gasPOX system.
Outsourcing. Of course for many manufacturers working with syngas, the cost and effort of operating a plant to generate the gas themselves might be too high. In such cases, sourcing syngas from a third-party operator can be an attractive option. By working with syngas specialists in this way, it is also possible to benefit from a global industrial management system and extensive practical expertise. Moreover, by integrating a feedback loop, some providers are in a position to ensure that lessons learned on the ground are immediately communicated to the engineering design team for implementation.
Ultimately, the choice of technology chain for a specific project is made on the basis of a total cost evaluation that takes into account capital expenditure, feed, fuel, oxygen and other utilities, steam value, and additional opex, such as the cost of catalysts. The development engineers tasked with design have the important job of systematically comparing the modules available and narrowing down the process-chain options using the criteria discussed above. Teams with extensive experience can feed this knowledge into the decision-making process, helping them to find the most cost-effective solution.
To master this challenging task, providers nowadays offer end-to-end portfolios to address the entire process chain. And some even go a step further. For example, innovative planning solutions are available that enable a process simulation to calculate and optimize utility costs, and automatically prepare piping and instrumentation diagrams (PIDs), providing reliable estimates of capital expenditure. These kinds of services can help save costs before any construction work has even begun.
As outlined in the box below, the majority of syngas produced worldwide is currently used to generate H2 for the petroleum-refining and fertilizer industries. The suitability of SMR units for producing H2 means that this is the most widely used of the methane reforming technologies. However, it is worth noting that as the synfuels market continues to expand, combined reforming methods are set to grow in importance. Moreover, the abundant availability of coal is leading to a rise in the popularity of coal gasification units for MTP, MTO and SNG processes — in China and India, in particular. If this trend continues, such methods of syngas production could soon catch up with those based on natural gas. ■
Edited by Gerald Ondrey
Dieter Ulber is director of technology, HyCO Product Line at Air Liquide Global E&C Solutions Germany GmbH (Olof-Palme-Straße 35 60439 Frankfurt am Main, Germany; Phone: +49- 69-5808-0; Fax: +49-69-5808-1109; Email: [email protected]; URL: www.engineering-solutions.airliquide.com/). Since joining the company in 2002, Ulber has been a process engineer for a number of the companys projects in Malaysia and China. He holds a bachelor of engineering degree from the Thayer School of Engineering, Dartmouth College (Hanover, N.H.) and a doctoral degree in mechanical engineering from RWTH (Rheinisch-Westfälische Technische Hochschule) Aachen (Germany).
The need for syngas
Over two-thirds of the synthesis gas (syngas) generated worldwide is used to produce hydrogen, which in turn is used to synthesize ammonia for the fertilizer industry, or put to work in petroleum refineries, where it plays an important role in processes such as hydrotreating and desulfurization. The second-largest market segment is syngas used for the production of methanol (CH3OH), including dimethyl ether (DME). A valuable resource in the chemicals industry, methanol is also deployed as a synthetic fuel, and can be converted to olefins, such as propylene via methanol-to-propylene (MTP) technology as an alternative to propylene production from crude oil. A smaller fraction of global syngas output — less than 5% — contributes to chemical products or Fischer-Tropsch synthetic fuels, while only a small fraction of all syngas produced is used as a substitute for natural gas (SNG) or in integrated gasification combined cycles (IGCC) for power production.
Demand for syngas is rising across the board, in large part driven by a growing need for H2 in many sectors. For example, H2 plays an essential role in petroleum refineries and the broader petrochemical industry. Against the background of ever-more-stringent environmental legislation, it is a key ingredient in desulfurization and in the hydrocracking methods used to convert crude oil into ultra-clean diesel fuel. Moreover, the general trend toward processing heavier, lower-grade oil is leading producers to turn to new refining schemes that require large volumes of hydrogen. Plus, H2 is fast gaining prominence as a transportation fuel, deployed in fuel cells for electric vehicles. ❏
Technology choice in practice
This case study illustrates many of the points discussed in the main text, by outlining how a technical solution was chosen to meet a more complex set of requirements. The plant in question specializes in large-scale production of carbon monoxide for the chemicals industry [toluene diisocyanate (TDI) and diphenylmethane diisocyanate (MDI)]. At the same time, the operator wishes to generate hydrogen as an additional source to feed an existing pipeline network, for over-the-fence gas supply to several customers. The required product ratio of CO to H2 is 2.5:1, and a variety of natural gas sources are available as feed and fuel. As the plant serves multiple customers with fluctuating requirements, a decision is made to implement a flexible system that allows the ratio of H2 to CO in the syngas to vary between three and six. In addition, co-produced superheated steam at 53 barg can be exported as required at almost steam fuel value.
The technologies implemented along the process chain are as follows: pre-reforming, steam methane reforming, and amine wash CO2 removal — with a downstream serial arrangement of a methane-wash cold box, pressure swing adsorption, and CO2 and methane recycle compression. For this system design and the given product ratio, it is not necessary to operate a parallel CO shift train downstream of the reforming unit. In the PSA unit, the purity of the H2-rich gas from the cold box is increased from 97.8 to 99.99%. The H2 is compressed from 23 barg to the specified product pressure of 44 barg. And by deploying a feed ejector driven by process steam, feed compression can be avoided. The remaining H2-rich tailgas from the PSA stage is used as fuel in the reformer. Moreover, the plant design can facilitate the import of CO2, should a suitable source become available in the future — providing scope to reduce natural gas consumption.
The solution is implemented using a tailor-made combination of proven, standardized technology units, and the construction of the plant is based on pre-fabricated modules. As a result, it is possible to not only overcome the challenge of selecting the right methane reforming technology, but also to combine the technologies and adjust the parameters of each individual unit in such a ways as to maximize overall plant performance. ❏