Hydrogen production in refinery

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  • Refinery hydrogen network
  • Hydrogen production in refinery

    1. 1. HYDROGEN PRODUCTION<br />
    2. 2. Introduction<br />Hydrogen production has become a priority in current refinery operations and when planning to produce lower sulphur gasoline and diesel fuels. Along with increased H2 consumption for deeper hydrotreating, additional H2 is needed for processing heavier and higher sulphur crude slates. In many refineries, hydroprocessing capacity and the associated H2 network is limiting refinery throughput and operating margins. Furthermore, higher H2 purities within the refinery network are becoming more important to boost hydrotreater capacity, achieve product value improvements and lengthen catalyst life cycles. Improved H2 utilisation and expanded or new sources for refinery H2 and H2 purity optimisation are now required to meet the needs of the future transportation fuel market and the drive towards higher refinery profitability.<br />
    3. 3. Hydrogen Consumption Data for a typical refinery producing 82SCFD<br />Of Hydrogen from Natural gas at a purity of 99.9 vol%<br />
    4. 4.
    5. 5. Hydrogen is usually manufactured by steam reforming process. In some cases partial oxidation has also been used, particularly where heavy oil is available at low cost. However, oxygen is then required and the capital cost of producing oxygen plant makes partial oxidation high in capital cost.<br />
    6. 6.
    7. 7. Steam Reforming (conventional)<br />Steam reforming for hydrogen production is accomplished in four steps :<br />Reforming : This involves the catalytic reaction of methane with steam at temperatures in the range of 1400 to 1500 0F (760-8160 C), according to the following equation :<br /> CH4 + H2O = CO + 3H2 <br /> This reaction is endothermic and is carried out by passing the gas through catalyst-filled tubes in a furnace up to ¾ inch in diameter. It consists of 25 to 40% nickel oxide deposited on a low silica refractory base.<br />Shift Conversion: More steam is added to convert the CO from step 1 to an equivalent amount of hydrogen by the following reaction :<br /> CO + H2O = CO2 + H2<br /> This is an exothermic reaction and is conducted in a fixed-bed catalytic reactor at about 6500F (3430C). multiple catalyst beds in one reactor are commonly employed to prevent the temperature from getting too high, as this would adversely affect the equilibrium conversion. The catalyst used is a mixture of chromium and iron oxide.<br />
    8. 8. Gas Purification : The third step is removal of carbon dioxide by absorption in a circulating amine or hot potassium carbonate solution. Several other treating solutions are in use. The treating solution contacts the hydrogen and carbon dioxide in an absorber containing about 24 trays, or the equivalent amount of packing. Carbon dioxide is absorbed in the solution, which is then sent to a still for regeneration. <br />Methanation : In this step, the remaining small quantities of carbon monoxide and carbon dioxide are converted to methane by the following reactions :<br /> CO + 3H2 = CH4 + H2O<br /> CO2 + 4H2 = CH4 + 2H2O<br /> This step is also conducted in a fixed-bed catalytic reactor at temperatures of about 700 to 8000F (4270C). both reactions are exothermic and, if the feed concentration of CO and CO2 is more than 3%, it is necessary to recycle some of the cooled exit gas to dissipate the heat of reaction. The catalyst contains 10 to 20% on a refractory base.<br />
    9. 9.
    10. 10. Hydrogen produced from the SMR process includes small quantities of carbon monoxide, carbon dioxide, and hydrogen sulfide as impurities and, depending on use, may require further purification. The primary steps for purification include:<br /> • Feedstock purification – This process removes poisons, including sulfur (S) and chloride (Cl), to increase the life of the downstream steam reforming and other catalysts.<br /> • Product purification – In a liquid absorption system, CO2 is removed. The product gas undergoes a methanation step to remove residual traces of carbon oxides. Newer SMR plants utilize a pressure swing absorption (PSA) unit instead, producing 99.99% pure product hydrogen. <br />
    11. 11. Advantages<br />Steam reforming of natural gas offers an efficient, economical, and widely used process for hydrogen production, and provides near- and mid-term energy security and environmental benefits. The efficiency of the steam reforming process is about 65% to 75%, among the highest of current commercially available production methods. Natural gas is a convenient, easy to handle, hydrogen feedstock with a high hydrogen-to-carbon ratio. It is also widely available from sources in the U.S. and Canada.<br />The cost of hydrogen produced by SMR is acutely dependant on natural gas prices and is currently the least expensive among all bulk hydrogen production technologies. A well-developed natural gas infrastructure already exists in the U.S., a key factor that makes hydrogen production from natural gas attractive.<br />
    12. 12. Drawbacks<br />During the production of hydrogen, CO2 is also produced. The SMR process in centralized plants emits more than twice the CO2 than hydrogen produced.To avoid emission of CO2 into the atmosphere, CO2 can be concentrated, captured, and sequestered; sequestration concepts and technologies are relatively new and there is no long-term test evidence to prove that these technologies will be successful. Sequestration in oceans is controversial because of the possible adverse impact on the aquatic environment by the reduction of ocean water pH.<br />
    13. 13. Steam Reforming/PSA<br />Plants built since the mid-1980s are generally based on steam reforming followed by pressure-swing adsorption. PSA is a cyclic process which uses beds of solid adsorbent to remove impurities from the gas. The hydrogen itself passes through the adsorbent beds with only a tiny fraction absorbed. The beds are regenerated by depressurization, followed by purging at low pressure. <br />When the beds are depressured, a waste gas (or &quot;tail gas&quot;) stream is produced, consisting of the impurities from the feed (CO2, CO, CH4, N2) plus some hydrogen. This stream is burned in the reformer as fuel. Reformer operating conditions in a PSA-based plant are set so that the tail gas provides no more than about 85 percent of the reformer fuel. This limit is important for good burner control because the tail gas is more difficult to burn than regular fuel gas. The high CO2 content can make it difficult to produce a stable flame. As the reformer operating temperature is increased, the reforming equilibrium shifts, resulting in more hydrogen and less methane in the reformer outlet and hence less methane in the tail gas. Actual operating conditions can be further optimized according to the relative cost of feed, fuel, and export steam.<br />
    14. 14.
    15. 15. <ul><li> In hydrogen production by PSA only a single stage of shift conversion is used, since a very low CO residual is not required. Any CO remaining in the raw hydrogen will be removed and recovered as reformer fuel. After cooling, the gas is purified in the PSA unit. The PSA unit is simpler to operate than a steam reforming, since it has no rotating equipment or circulating solutions.
    16. 16. In addition, the adsorbent will remove methane and nitrogen, which could not be removed by the steam reforming process. Typical hydrogen recoveries in a PSA unit are in the 80 to 90 percent range, with product purity generally 99.9 vol %. Because of the loss of hydrogen to the PSA tail gas, the reformer and front end of a PSA plant are larger than in a wet scrubbing plant. A PSA plant uses less process steam and does not require heat for the reboiler; this leaves additional steam available for export.
    17. 17. Capital cost is generally lower for the design with PSA. The additional export steam can provide a strong utility cost advantage for the PSA plant in addition to its purity and operability advantages.</li></li></ul><li>Composition of Product Hydrogen <br />
    18. 18. Operating Variables<br />
    19. 19. a) Operating Conditions<br />The critical variables for steam reforming are temperature, pressure, and the steam/hydrocarbon ratio. <br />Picking the operating conditions for a particular plant involves an economic trade off among these three factors. Steam reforming is an equilibrium reaction, and conversion of the hydrocarbon feedstock is favored by high temperature, which in turn carries a fuel penalty.<br /> Because of the volume increase in the reaction, conversion is also favored by low pressure, which conflicts with the need to supply the hydrogen at high pressure. In practice, temperature and pressure are limited by the tube materials. The degree of conversion is measured by the remaining methane in the reformer outlet, known as the methane leakage.<br />
    20. 20.
    21. 21. b) Shift Conversion<br />In contrast to reforming, shift conversion is favored by low temperature. The gas from the reformer is reacted over iron oxide catalyst at 600 to 700oP (3 I 5 to 370°C), with the limit set by the low-temperature activity of the catalyst. In conventional steam reforming plants using a methanator, it is necessary to remove CO to a much lower level to avoid excessive temperatures in the methanator. In those plants the gas is cooled again and reacted further over a copper-based catalyst at 400 to500oP (205 to 260°C). <br />
    22. 22.
    23. 23. Catalysts<br />
    24. 24. Hydrogen plants are one of the most extensive users of catalysts in the refinery. Catalytic operations include hydrogenation, steam reforming, shift conversion, and methanation.<br />
    25. 25. Reforming<br />Because of the high temperatures and heat load of the reforming reaction, reforming catalyst is used inside the radiant tubes of a reforming furnace. The catalyst is subject to severe operating conditions: up to 1600oF (870°C), with typical pressure drops of 2.8 bar. To withstand these conditions, the carrier is generally an alumina ceramic, although some older formulations use calcium aluminate. The active agent in reforming catalyst is nickel, and normally the reaction is controlled by both diffusion and heat transfer.<br />
    26. 26. Shift Conversion<br />The second important reaction in a steam reforming plant is the shift conversion reaction<br /> CO + H2O -> CO2 + H2<br />The equilibrium is dependent on temperature, with low temperatures favoring high conversions.<br />Two basic types of shift catalyst are used in steam reforming plants: iron/chrome high temperature shift catalysts and copper/zinc low-temperature shift catalysts.<br />
    27. 27. High-Temperature Shift<br />High-temperature shift catalyst operates in the range of 600 to 800oF (315 to 430°C). It consists primarily of magnetite, Fe3O4, with chrome oxide, CrO3, added as a stabilizer. The catalyst is supplied in the form of Fe2O3, and CrO3 and must be reduced. This can be done by the hydrogen and carbon monoxide in the shift feed gas. and occurs naturally as part of the start-up procedure.<br />
    28. 28. Low-Temperature Shift<br />Low-temperature (LT) shift catalyst operates with a typical inlet temperature of 400 to 450oP (205 to 230°C). Because of the lower temperature, the reaction equilibrium is better and outlet CO is lower.<br />The catalyst is supplied as copper oxide on a zinc oxide carrier, and the copper must be reduced by heating it in a stream of inert gas with measured quantities of hydrogen. Reduction is strongly exothermic and must he closely monitored.<br />PSA-based plants do not use LT shift, since any unconverted CO will be recovered as reformer fuel.<br />
    29. 29. Methanation<br />The active agent is nickel, on an aluminium carrier.<br />
    30. 30. Feedstocks<br />The best feedstocks for steam reforming are light, saturated, and low in sulfur; this includes natural gas, refinery gas, LPG, and light naphtha. These feeds can be converted to hydrogen at high thermal efficiency and low capital cost.<br />
    31. 31. Natural Gas: Natural gas is the most common hydrogen plant feed, since it meets all the requirements for reformer feed and is low in cost.<br />Typical natural gas composition is given on the next slide.<br />
    32. 32.
    33. 33. Refinery Gas: Light refinery gas, containing a substantial am6unt of hydrogen, can be an attractive steam reformer feedstock. Since it is produced as a by-product, it may be available at low cost. Processing of refinery gas will depend on its composition, particularly the levels of olefins and of propane and heavier hydrocarbons. Olefins can cause problems by forming coke in the reformer. They are converted to saturated compounds in the hydrogenator<br />
    34. 34. Typical Catalytic Reformer Offgas Composition<br />
    35. 35. Feed Handling and Purification using multiple Feedstock<br />
    36. 36. Liquid Feeds: Liquid feeds, either LPG or naphtha, can be attractive feedstocks where prices are favorable. Naphtha is typically high valued as low-octane motor gasoline, but at some locations there is an excess of light straight-run naphtha, and is available cheaply. Liquid feeds can also be provide backup feed, if there is a risk of natural gas curtailments.<br />
    37. 37. Alternate Process: Partial Oxidation<br />
    38. 38. Partial oxidation (POX) reacts hydrocarbon feed with oxygen at high temperatures to produce a mixture of hydrogen and carbon monoxide. <br />Since the high temperature takes the place of a catalyst, POX is not limited to the light, clean feedstocks required for steam reforming. Partial oxidation is high in capital cost, and for light feeds it has been generally replaced by steam reforming. However, For heavier feedstocks it remains the only feasible method.<br /> In the past, POX was considered for hydrogen production because of expected shortages of light feeds. It can also be attractive as a disposal method for heavy, high-sulfur streams, such as asphalt or petroleum coke, which sometimes are difficult to dispose of. <br />Consuming all a refinery&apos;s asphalt or coke by POX would produce more hydrogen than is likely to be required. Because of this and the economies of scale required to make POX economic, hydrogen may be more attractive if produced as a by-product, with electricity as the primary product.<br />
    39. 39. Asphalt Composition – Partial Oxidation Feedstock<br />
    40. 40.
    41. 41. The asphalt is first gasified with oxygen in an empty refractory-lined chamber to produce a mixture of CO, CO2 and H2. Because of the high temperature, methane production is minimal. Gas leaving the gasifier is first quenched in water to remove solids, which include metals (as ash) and soot. Metals are removed by settling and filtration, and the soot is recycled to the gasifier. The gas is further cooled and H2S is removed by scrubbing with a selective solvent. Sulfur removal is complicated by the fact that a significant amount of carbonyl sulfide (COS) is formed in the gasifier. This must be hydrolyzed to H2S, or a solvent that can remove COS must be used. <br />Hydrogen processing in this system depends on how much of the gas is to be recovered as hydrogen and how much is to be used as fuel. Where hydrogen production is a relatively small part of the total gas stream, a membrane unit can be used to withdraw a hydrogen rich stream, This is then purified in a PSA unit. In the case where maximum hydrogen is required, the entire gas stream may be shifted to convert CO to H2, and a PSA unit used on the total stream.<br />
    42. 42. Catalytic Partial Oxidation<br />Also known as autothermal reforming, catalytic partial reacts oxygen with a light feedstock, passing the resulting hot mixture over a reforming catalyst. Since a catalyst is used, temperatures can be lower than in noncatalytic partial oxidation, which reduces the oxygen demand. Feedstock composition requirements are similar to those for steam reforming: light hydrocarbons from refinery gas to naphtha may be used. The oxygen substitutes for much of the steam in preventing coking, so a lower steam/carbon ratio can be used. Since a large excess of steam is not required, catalytic POX produces more CO and less hydrogen than steam reforming. Because of this it is suited to processes where CO is desired, for example, as synthesis gas for chemical feedstocks. Partial oxidation requires an oxygen plant, which increases costs. In hydrogen plants, it is therefore used mainly in special cases such as debottlenecking steam reforming plants, or where oxygen is already available on-site.<br />
    43. 43. Economics<br />Capital costs for hydrogen production are illustrated on next slide, which compares costs for purification, steam reforming, and partial oxidation. Where hydrogen is already available in sufficient quantity, it is cheapest to merely purify it as required. In most cases this is not sufficient, and it is necessary to manufacture it. <br />Figure illustrates why steam reforming is favored over partial oxidation. For light feedstocks, capital costs for the inside battery limit (ISBL) plants are similar for steam reforming or partial oxidation. However. when the cost of oxygen is included, the cost for partial oxidation (POX) rises substantially. Naphtha reforming is slightly higher in capital cost than reforming of natural gas. Feedstock cost will depend on the value of the naphtha; where the naphtha is valued as motor gasoline, it cannot compete with natural gas. Where there is a surplus of low-octane naphtha, it may be valued at fuel cost or even below; in this case steam reforming of naphtha can &apos;be attractive. <br />
    44. 44. For partial oxidation of residual fuel, a substantial amount of equipment is required to handle the soot, ash, and sulfur. The cost for this additional equipment, as well as the additional oxygen required, means that heavy oil must be much cheaper than natural gas to justify partial oxidation. Alternatively, partial oxidation may be used as a way to dispose of a stream such as petroleum coke or asphalt, which is considered a waste product.<br />CAPITAL COST : Where capacity, feedstock, and method of heat recovery are known for a steam reforming plant, a reasonable estimate may be made of capital cost, typically to an accuracy of +- 30percent. For a 50 million SCFD[56,OOO (N) m%] hydrogen plant, based on natural gas feed and using steam generation for heat recovery, capital cost is approximately $30 million.<br />

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