Nitrogen removal for chemicals production
As natural gas is widely used as feedstock for the manufacture of many chemicals, the current low gas price is a major benefit to chemicals producers in improving their profit margins. It is not surprising that many plant construction projects, based on utilising low cost natural gas feedstock, are in the planning stage or are already in the engineering design phase.
Methane is the starting point for chemical synthesis gas (syngas) production. Steam reforming or catalytic partial oxidation of methane can be used to produce a hydrogen and carbon monoxide rich synthesis gas, which acts as the initial ‘building block’ for downstream chemicals manufacture. Carbon dioxide in the natural gas feed will normally need to be removed to low levels using wellknown acid gas removal technology1 Lighter paraffinic hydrocarbons in the feed gas can be tolerated. If the natural gas proposed as plant feedstock is relatively rich in ethane and heavier hydrocarbons, these can be removed as natural gas liquids (NGL) using well-established process technology2 and fractionated for use as either petrochemical plant feedstock or liquid fuel (propane and butane) or for gasoline production (butane and natural gas condensate).
A significant proportion of worldwide natural gas reserves contains nitrogen. Nitrogen is inert and needs to be removed for natural gas to be used as fuel. With greater use of natural gas for fuel and/or chemicals production, the future development of ‘marginal’ gas fields will often mean relatively high nitrogen content gas being used, if it can be processed profitably.
The need for low nitrogen content gas
The nitrogen content of natural gas is typically reduced to about 5% for the gas to be used as fuel. For use as chemical plant feedstock, the nitrogen content must normally be much less than this, of the order of 1% or less. As nitrogen is inert, it passes through the reaction section and remains in the synthesis gas with hydrogen and carbon monoxide.
For ammonia production, nitrogen does not need to be removed and its presence can be beneficial by reducing the need for partial oxidation with air. However, for most chemicals manufacture, nitrogen leads to dilution of reactants and higher volumes of processed gas, increases equipment size, heat transfer duties, capital and operating costs, and requires purification of products.
Carbon monoxide purity for chemicals production has normally to be well over 99%, to promote high reaction yields and avoid the need for purification of products. Cryogenic distillation is the most economical way to remove nitrogen, but the volatilities of nitrogen and carbon monoxide are very similar (the difference in their respective boiling points is only 4ºC), so to achieve high purity product is energy intensive and expensive.
Failure to fully consider the importance of feed gas nitrogen content can have major ramifications for chemical plant performance and can seriously reduce plant capacity and eventual product quality. Removal of nitrogen from the natural gas feedstock upstream of the chemicals manufacturing plant should therefore be considered as a preferred alternative to downstream processing. If some natural gas is intended for use as fuel (and the balance for chemicals manufacture) then nitrogen removal may be needed in any event to ensure fuel quality natural gas. Well-proven and reliable cryogenic technology is available for nitrogen removal from natural gas. The difference in the boiling points of nitrogen and methane is 34ºC, which leads to a much easier and less energy-intensive separation compared to nitrogen and carbon monoxide distillation.
Process technology selection for nitrogen removal
The typical feed gas capacity of syngas plants using natural gas feedstock is of the order of 30 million standard cubic feet per day (mmscfd), for instance at Clear Lake, La Porte and Texas City syngas plants.3 The capacity of syngas plants is increasing with the use of multiple reactor units. The Bintulu Gas to Liquids (GTL) plant has a feed gas capacity of 100 mmscfd, whilst the world’s largest GTL plant (Pearl) can process in excess of 1000 mmscfd.3
For very small gas processing plants, it may be possible to employ pressure swing adsorption (PSA) or membrane technology for nitrogen removal from natural gas feedstock. However, these processes operate at low pressure and incur high power consumption per unit of gas processed, as they need relatively expensive compression equipment to increase the product gas pressure to the operating pressure required for syngas production. No PSA plant has been built and operated to remove nitrogen at a capacity over about 20 mmscfd and membrane plants are only economical at much smaller capacity.
Cryogenic distillation is almost always the only technically and commercially feasible process solution for nitrogen removal from natural gas of moderate to high nitrogen content as it consumes far less power per unit of gas processed, requires less costly machinery, can use a relatively simple machinery configuration (based on conventional gas processing compressors), is reliable, ensures specification products even with varying feed composition and, importantly, is environmentally by far the best approach, as discussed below.
Benefits of cryogenic distillation
Distillation is energy efficient and the most economical solution for large scale processing of binary mixtures to give relatively pure products, especially for feeds where both components are present in significant quantities.4 For nitrogen rich natural gas, all these requirements are met with cryogenic distillation, and plants for processing high nitrogen content (over 30%) have been operational for over 30 years.
It is important to appreciate that even though cryogenic distillation is more energy intensive at lower feed gas nitrogen levels, plants based on thermodynamically efficient process designs, with relatively low energy consumption and operating costs, have been operational for well over 20 years.5 High thermodynamic efficiency reduces the power consumption required to provide low level refrigeration and minimises the capital and operating costs of machinery.
Cryogenic nitrogen removal plants (for a moderate nitrogen content of about 5-20%) usually have at least two stages of separation based on distillation (see Figure 1). The first stage (pre-separation) performs a bulk separation of nitrogen and methane. Nitrogen is concentrated in a stream that is further processed in a second separation stage (nitrogen rejection) to produce pure nitrogen and methane. The pre-separation column operates at elevated pressure, allowing about half of the methane in the feed gas to be recovered and then pumped to high pressure so minimising expensive downstream compression.6 Indeed, based on feed gas being available at about 40 bar, the cryogenic nitrogen removal plant can usually produce much of the product methane at a high enough pressure (of the order of 35 bar) for gas reforming, without any further methane compression. The second column system operates at reduced pressure to produce a methane stream with low nitrogen content (for compression) and a pure nitrogen stream, which can be safely vented to atmosphere.
Cryogenic nitrogen removal uses the evaporation of liquid methane process streams at appropriate temperatures to provide the necessary refrigeration for the process, so there is effectively no external refrigeration system (see Figure 1). Liquid methane products are pumped to the required evaporating pressure, which minimises the power required for re-compression. Part of the methane product is delivered at a lower pressure than the feed gas, and a conventional compression system is used for gas pressure boosting and transportation. Energy integration reduces overall product gas compression so that modern plants offer gas processing with low operating cost. The plant design is optimised to minimise overall cost by consideration of the compression system in parallel with design of the cryogenic plant.
If the nitrogen content of the natural gas feedstock is higher than approximately 3%, then nitrogen would probably be best removed upstream of the chemical plant by cryogenic distillation. At lower nitrogen levels in the natural gas feedstock, it may be better to consider separation of carbon monoxide and nitrogen downstream of the syngas production step. Whichever of these two separation approaches is used, cryogenic distillation is required as no other technology can be cost competitive at the feed gas flows (much higher than 20 mmscfd) and product purities required for chemicals production.
A key point in terms of environmental protection and legislation compliance (and not always appreciated) is that the nitrogen removed from natural gas must be disposed of, with the obvious choice being for it to be vented directly to the atmosphere. For this to be acceptable, effective separation is needed and essentially total removal of hydrocarbons from the vented nitrogen is required. Methane has a high global warming potential so emissions to atmosphere should be minimised. Technologies other than distillation have severe limitations in producing almost pure nitrogen for venting at a competitive cost and without being both machinery intensive and complex. This is another key reason why very few non-cryogenic plants have been built, and those plants that have been built rely on the nitrogen rich gas being disposed of in alternative ways to atmospheric venting.
Cryogenic distillation can easily achieve minimal hydrocarbon levels in the nitrogen stream (for instance, less than 1%) so venting to atmosphere is acceptable in terms of environmental compliance. This also ensures minimal methane losses and very high hydrocarbon recovery levels. There are many cryogenic nitrogen removal plants around the world operating reliably to produce specification hydrocarbon product with minimal methane loss to the nitrogen vent, even with fluctuations in feed gas nitrogen content. During start-up, natural gas leaving the cryogenic section is recycled to the plant inlet using the compression system. The separated nitrogen rich stream is recombined and compressed with the recycled gas until normal operating temperatures are reached (indicating the purity of the nitrogen stream will be acceptable for atmospheric venting).
Operating temperatures in cryogenic nitrogen removal plants (possibly below -180ºC) are well below the freezing temperature of carbon dioxide (-56.6ºC). For this reason, carbon dioxide in the natural gas feedstock must be removed, to as low as 0.5% or lower depending on the process flowsheet, to avoid the risk of solids formation and potential blockages. This can be achieved by acid gas removal upstream of the nitrogen removal plant.1 For natural gas that will be used as fuel, this acid gas removal can be a cost burden as the maximum carbon dioxide content allowed in the feed gas to the cryogenic nitrogen removal plant is much lower than the maximum carbon dioxide content for use of the gas as fuel (typically around 5%). However, for chemicals production the carbon dioxide content of the natural gas feedstock normally needs to be reduced to low levels anyway so the additional cost to provide gas suitable for cryogenic nitrogen removal is minimal.
Cryogenic nitrogen removal by distillation benefits from economies of scale (unlike the other technologies noted), so costs per unit of gas processed are lower for larger plant capacities. The maximum single train feed gas capacity is about 300 mmscfd for most processing scenarios. The maximum plant size is generally dictated by the maximum feasible diameter of distillation columns due to fabrication and transport constraints. The gas processing cost savings with increased plant capacity are large enough to possibly encourage co-operation between companies to build jointly owned nitrogen removal plants to minimise nitrogen removal costs where the individual chemical feedstock needs are much less than about 100 mmscfd. Alternatively, gas producers could install cryogenic nitrogen removal facilities and sell the nitrogen depleted gas at a premium as this would be cost-effective for downstream gas users compared to each of them installing a relatively small nitrogen removal plant for their individual needs. Understanding of these economies of scale, and that they only apply to cryogenic distillation, could influence strategic decisions at national energy companies and other major gas producers to ensure an optimal nitrogen removal strategy and minimum gas costs for consumers.
Nitrogen removal experience
Design and construction of cryogenic distillation units is well understood and ample experience is available in the safe design, supply and operation of plants.
Costain has designed and built major cryogenic nitrogen removal plants in the United Kingdom, Pakistan, Mexico and Tunisia, with Costain process technology being used on other large scale nitrogen removal plants.7 Each plant is customised to minimise processing cost, considering the specific feed gas conditions and possible fluctuations, acceptable nitrogen level in the product hydrocarbon stream, optimisation of nitrogen vent conditions, gas pre-treatment requirements and choice of gas compression type and configuration. These plants have proven to be highly stable in operation and very reliable, thus meeting the investment criteria used in first selecting the process technology.
A typical nitrogen removal plant is shown in Figure 2. This plant was designed to process the surplus gas received at an onshore terminal that was not used by a local power plant. Whilst the nitrogen content (8-11%) was acceptable for use as fuel gas in power generation, nitrogen removal was required to meet the national transmission system specifications. The plant was designed for a normal feed gas flow of 70 mmscfd, with capacity to process an increased feed gas flow of up to 200 mmscfd when the power station was operated at reduced capacity.5 Therefore, the plant was designed with a large degree of flexibility to allow rapid operator response to demand variation.
Natural gas liquids
In an NGL recovery plant, the removal of propane and heavier hydrocarbon components will require operating temperatures of typically -40°C, with ethane extraction needing temperatures below -70°C. If extraction of NGL is needed as well as the removal of nitrogen from the natural gas feedstock, the two separation duties can be combined in a single cryogenic plant. This minimises energy requirements by making the best use of cold evaporating process streams to provide refrigeration to cool and condense warmer streams. By reducing plant energy requirements, the need for methane evaporation at low pressure and thus gas compression, such process integration can reduce capital cost and gas processing costs as compared to having separate processing plants for NGL extraction and nitrogen removal. Modern plant designs and plant control systems offer very good performance, simplicity, operability and reliability for such integrated plants.
In cases where not all of the available gas needs processing to remove nitrogen, there may be a need to remove heavier hydrocarbons to meet a gas transmission hydrocarbon dew point specification. This will require chilling of the gas to maybe -20 to -30°C and this duty can be easily and effectively incorporated into the cryogenic nitrogen removal plant.
Cryogenic nitrogen removal may also include helium production where the helium content of the feed gas is sufficiently high, typically in excess of 0.2%. Helium concentrates in the cryogenic distillation system to a level of up to 90% in a crude helium stream prior to purification and liquefaction. Helium is produced commercially in this way in the United States, Qatar, Russia, Poland, Australia and Algeria, though in recent years a lower cost source of helium has been to process nitrogen rich flash gas from large scale liquefied natural gas (LNG) production. This helium rich stream is available at -150°C. This process route has been exploited on LNG plants, in Qatar in particular, to produce pure helium at relatively low cost.
Enhanced oil recovery
Production of a pure nitrogen stream by cryogenic distillation means the nitrogen can potentially be used for enhanced oil recovery (EOR). Nitrogen is normally produced from a cryogenic nitrogen removal facility at low pressure (for venting), whereas EOR requires high pressure nitrogen. In this situation, nitrogen compression costs can dictate the nitrogen removal plant design and promote flowsheet options, which reliably and cost-effectively produce nitrogen at elevated pressure.
Cryogenic nitrogen removal technology has been successfully used for many years. As new gas fields with increasing content of nitrogen need to be profitably exploited, the need for efficient cryogenic nitrogen removal plants will increase. Historically, nitrogen removal from natural gas has been applied to achieve sales gas specifications. This technology can also be applied to remove nitrogen to lower levels upstream of chemical plants to ensure product quality specifications can be met economically.
The authors thank Terry Tomlinson for his valuable comments in the preparation of this article.
- Hydrocarbon Treating, Section 21 of GPSA Engineering Data Book, 13th Ed, Gas Processors and Suppliers Association (GPSA), Tulsa, OK, 2012.
- Hydrocarbon Recovery, Section 16 of GPSA Engineering Data Book, 13th Ed, Gas Processors and Suppliers Association (GPSA), Tulsa, OK, 2012.
- World Gasification Database, Gasification & Syngas Technologies Council (GSTC) Arlington, VA, 2016. www.gasification-syngas.org/whatis- gasification/world-database
- King C J, Separation Processes, 2nd Ed, McGraw-Hill, New York, 1980.
- Healy M J, Finn A J, Halford L, UK nitrogenremoval plant starts up, Oil & Gas Journal, 1 Feb 1999, 36.
- Wilkinson D, Johnson G L, An Abu Dhabi case study, Hydrocarbon Engineering, Feb 2012, 22.
- Finn AJ, Rejection strategies, Hydrocarbon Engineering, Oct 2007, 49.
About the authors
Jorge Arizmendi-Sánchez is a Principal Process Engineer with Costain, Manchester, UK, with process consultancy and engineering design experience in the oil and gas industry. He has worked in conceptual design, FEED and EPC projects in natural gas processing and liquefaction and holds a MSc from the University of Ferrara, Italy, and a PhD in chemical engineering from the University of Manchester, UK.
Email: [email protected]
Adrian Finn is Process Technology Manager with Costain, Manchester, UK, with responsibility for process technology selection, development and commercialisation, proposal management and supervision of feasibility studies, pre-FEEDs and FEEDs. He has 33 years with Costain, focused mainly on cryogenic gas processing. He holds a bachelor’s degree in chemical engineering and fuel technology, a master’s degree in integrated design of chemical plant, has authored 50 technical papers and holds nearly 20 granted patents.
Email: adrian.f[email protected]
This article was first published in Petroleum Technology Quarterly Gas Supplement, April 2016.