ptq 2014 q3

special features

instrumentation & control

rotating equipment

refininggas processingpetrochemicals

petroleum technology quarterly

ptqQ3 2014

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2014. The entire content of this publication is protected by copyright full details of which are available from the publishers. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means electronic, mechanical, photocopying, recording or otherwise without the prior permission of the copyright owner.The opinions and views expressed by the authors in this publication are not necessarily those of the editor or publisher and while every care has been taken in the preparation of all material included in Petroleum Technology Quarterly and its supplements the publisher cannot be held responsible for any statements, opinions or views or for any inaccuracies.

3 Gas makes the rules Chris Cunningham 5 ptq&a 17 Tail gas catalyst performance: part 1 Michael Huffmaster Consultant Fernando Maldonado Criterion Catalysts 31 Selective control for a total reflux column Niyazi Bozkurt Tpra Kirikkale Refinery

37 Quality control in biofuels production Berthold Otzisk Kurita Europe

41 Revamping advanced process control Stefano Lodolo Aspen Technology Oleg Vedernikov Isab

49 Design developments for construction projects Simon Bennett AVEVA Solutions

55 Overcoming corrosion in heat exchangers Dragon Hao Sandvik Materials Technology

63 Meeting production targets for ultra low sulphur transportation fuels Bob Leliveld Albemarle

69 Improving a compressor protection regime Ben Austin Prognost Systems Inc.

72 Avoiding compressor system downtime Amit Saxena Dresser-Rand

75 Meeting tighter NOx emissions rules Stephen Harrison, Naresh Suchak and Frank Fitch Linde Gases

81 Cloud point and hydrotreating relationships Brian Watkins and Meredith Lansdown ART

89 Failure analysis of burner piping Hyunjin Yoon SK Innovation

97 Microbiological causes of corrosion Jaya Rawat, Neha Sharma and Apoorve Khandelwal Bharat Petroleum Corporate R&D Center

105 Albertas crude oil reserves Mike Priaro Consultant

115 Technology in Action

Suncors Commerce City, Colorado refinery where an upgrade has enabled a wider range of oil sands products to be processed. Photo: Suncor

Q3 (Jul, Aug, Sept) 2014www.eptq.com

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The European Union has arguably been the global leader in biodiesel production and use, with overall

biodiesel production increasing from 1.9 million tonnes in 2004 to nearly 10.3 million tonnes in 2007. Biodiesel production in the US has also increased dramatically in the past few years from 2 million gallons in 2000 to approximately 450 million gallons in 2007. According to the National Biodiesel Board, 171 companies own biodiesel manufacturing plants and are actively marketing biodiesel.1. The global biodiesel market is estimated to reach 37 billion gallons by 2016, with an average annual growth rate of 42%. Europe will continue to be the major biodiesel market for the next decade, followed closely by the US market.

Although high energy prices, increasing global demand, drought and other factors are the primary drivers for higher food prices, food competitive feedstocks have long been and will continue to be a major concern for the development of biofu-els. To compete, the industry has responded by developing methods to increase process efficiency, utilise or upgrade by-products and operate with lower quality lipids as feedstocks.

Feedstocks

Biodiesel refers to a diesel-equivalent fuel consisting of short-chain alkyl (methyl or ethyl) esters, made by the transesterification of triglycerides, commonly known as vegetable oils or animal fats. The most common form uses methanol, the cheapest alcohol available, to produce methyl esters. The molecules in biodiesel are pri-marily fatty acid methyl esters (FAME), usually created by trans-esterification between fats and metha-nol. Currently, biodiesel is produced from various vegetable and plant oils. First-generation food-based feedstocks are straight vegetable oils such as soybean oil and animal fats such as tallow, lard, yellow grease, chicken fat and the by-products of the production of Omega-3 fatty acids from fish oil. Soybean oil and rapeseeds oil are the common source for biodiesel produc-tion in the US and Europe in quanti-ties that can produce enough biodie-sel to be used in a commercial market with currently applicable

PTQ Q3 2014 3

Editor Chris Cunningham [email protected]

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Editorial tel +44 844 5888 773fax +44 844 5888 667

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Crambeth Allen Publishing LtdHopesay, Craven Arms SY7 8HD, UKtel +44 844 5888 776fax +44 844 5888 667

PTQ (Petroleum Technology Quarterly) (ISSN No: 1632-363X, USPS No: 014-781) is published quarterly plus annual Catalysis edition by Crambeth Allen Publishing Ltd and is distributed in the US by SP/Asendia, 17B South Middlesex Avenue, Monroe NJ 08831. Periodicals postage paid at New Brunswick, NJ. Postmaster: send address changes to PTQ (Petroleum Technology Quarterly), 17B South Middlesex Avenue, Monroe NJ 08831.Back numbers available from the Publisher at $30 per copy inc postage.

Vol 19 No 4

Q3 (Jul, Aug, Sept) 2014

Gas makes the rules

The west Asian Gulf region has established a clear economic lead in the petrochemicals industry, with the rest trailing in its wake but the US promising some stiff competition in the near future.

The key to the shape of the industry is cheap gas. Provided natural gas can be produced and delivered at a sufficiently low price, naphtha cracking can-not hope to compete with ethane cracking as the basis of a profitable petro-chemicals business. The rules of oil trading, with its transglobal shipments and benchmarks, determine the price of ethylene from naphtha cracking. Gas costs whatever it costs on a regional basis.

The best current illustration of this is China, where plans by Sinopec and PetroChina to build new ethylene plants are being shelved by the day. The PRCs relative economic downturn is partly to blame, but principally the out-put of its naphtha crackers is unable to compete with cheaper supplies of imported ethylene. China is working overtime to generate supplies of gas and not only for its petrochemicals business. But successful development of Chinese gas supplies, both conventional and from shale measures, would still leave the nation at a disadvantage, taking into account the costs of pro-duction and of infrastructure to connect sources, principally in western China, to centres of production in the east.

Compare and contrast with the IGCC states where conventional and well-developed gas fields including Qatars North Field are, relatively speak-ing, within arms reach. More so, associated gas from the regions oil fields has a minimal production cost in the raw state and an extensive, inter-state network of pipelines for delivery. If there is a problem for the regions petro-chemicals business it is that gas is too cheap. In light of burgeoning demand from fast-growing populations for other applications, producers will expect better incentives in other words, higher prices to step up their rates of output. Setting appropriate prices without punishing a hugely important industry is a balancing act under way in the UAE at present. It seems unlikely, however, that the outcome will weigh too heavily in favour of the gas companies.

So what about that much-touted shale revolution in the US? How will that impact the Middle Eastern petrochemicals business? Contrary to the hype, shale gas is not the giveaway that many believe it to be. Fracking is an expensive activity and the ability of shale gas producers to undercut conven-tional market prices is regionalised in the US. The chief perceived advantage to Americans of the shale revolution both gas and oil is the security of supply afforded by a new wealth of supply. But shale gas can be relatively cheap; this has led to a rash of new ethane crackers in the US, under con-struction and planned, with an eye to eastern export markets. Several of these projects have backing from east Asian sources for just that reason. Within the next two years, with Middle Eastern pricing issues settled and American ethylene on tap, the shape of global competition for petrochemi-cals supply should be clearer.

CHRIS CUNNINGHAM

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Activity, pressure drop, cost... According to Karl Krueger, Criterion research scientist, these among other factors are critical considerations when selecting a tail gas catalyst. He should know. He and his colleagues have helped refi ners all over the world realize lower operating costs and extended cycle lengths through Criterions range of advanced tail-gas treating catalysts: C-234, C-534 and C-734. These uniquely different catalysts account for 80% of the worlds installed capacity, proving the rule that selection success comes from eliminating all but the best.

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Q Using lighter feeds with a higher paraffinic content gives us problems with cold flow properties in our middle distillates. Will a dewaxing catalyst help with this?

A Bob Leliveld, Global Director for Applications Technology, Clean Fuels Technology, Albemarle Corporation, [email protected] chain normal paraffins have a negative effect on the cold flow properties of middle distillates. A dewax-ing catalyst can improve cold flow properties by selectively converting these paraffins into branched paraffins or by breaking the longer chains into smaller fragments. Selection of the optimal dewaxing catalyst is dependent on the desired degree of cloud point reduction and the unit conditions and configuration. For a significant reduction in cloud point, a two-stage process is typically applied which is capable of operat-ing in both winter and summer mode. For mild dewaxing applications, the dewaxing catalyst can be included as a functional layer in the loading scheme of the ULSD unit. However, when cracking long chain paraffins, the naphtha make can potentially be a restriction, depending on the capability of the down-stream configuration to handle naphtha. There are various dewaxing catalysts available that can be oper-ated in sour conditions, while others are more suited to sweet operations.

A Sunil Nair, Finished Fuel Additive Director, Dorf Ketal Chemicals, [email protected] understand that you want to use dewaxing catalyst in the hydrotreater reactor, to improve the cold flow properties. Globally, there are two methods to improve the cold flow properties: Using dewaxing catalyst Using cold flow improver additives.

Usage of cold flow improver additives can help refiners in reducing the cold filter plugging point (CFPP) and pour point (PP) of middle distillates. Usage of these additives is cost effective and requires minimal capex. We suggest that the typical middle distillate blend is tested on a variety of additives to screen the most effective additive to meet finished middle distillate specifications.

Q We have problems with precipitation in the desalter arising from blends including opportunity crudes. How do we deal with this?

A Andrea Fina, Process Technological Unit, Chimec, [email protected] Processing heavy crude oils, for example some oppor-tunity crudes, blended with other crudes, can lead to desalter upsets. These upsets are commonly caused by asphaltenes flocculation and subsequent precipitation.

The asphaltenes are actually submicroscopic solids at room temperature dispersed in the oil by the resins. This asphaltene-resin dispersion is dissolved into petroleum by aromatics, which are solvents, but opposed by saturates, which are non-solvents. Thus, asphaltenes are held in petroleum in a delicate balance and this balance can be easily upset by adding satu-rates (such as paraffinic crude oils). Because the blending of heavy oils with lighter oils can greatly change the overall concentrations of these molecular types, it can upset this balance and lead to asphaltenes precipitation.

The blend induced asphaltene instability has mainly three negative effects: Precipitated asphaltenes may cause solids to deposit within the desalting vessel, thus the oil and water resi-dence times decrease over the unit run length and the desalting and dehydration efficiency get worse Agglomerated asphaltenes increase emulsion stabil-ity inside the desalting vessel Agglomerated asphaltenes can trap salts, thus avoid-ing their removal during desalting operation.

There are several strategies to mitigate or avoid asphaltene precipitation in the desalting system:1. Blend the crudes in the correct proportion and order for compatibility. The ratio (saturates + asphaltenes)/(aromatics + resins) (%wt/%wt), calculated through S.A.R.A (Saturates, Aromatics, Resins and Asphaltenes) analysis, gives good indication of the stability of asphaltenes in the oil matrix: A ratio lower than 0.7 usually indicates a stable blend A ratio from 0.7 to 0.9 indicates an uncertain stability A ratio higher than 0.9 indicates an unstable blend.

Also, the blending order of two crudes in a tank can play an important role for asphaltene stability. For instance, even if the final (saturates + asphaltenes)/(aromatics + resins) ratio is lower than 0.7, during the blending procedure asphaltenes precipitation may occur. This phenomenon arises when, for instance, a heavy crude oil is transferred to/into the tank contain-ing a paraffinic crude oil. As a result, although the crudes are blended in the correct proportion for compatibility, this type of blending order can lead to

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local asphaltenes precipitation during the mixing of the two crudes. 2. Add an asphaltenes inhibitor to the crude storage tank. The asphaltene inhibitor, such as the Chimec asphaltene inhibitor, acts as an artificial resin; it prevents aggregation by shifting the onset of the asphaltenes flocculation point and in this way it increases the stability of the asphaltene in the blend.3. Inject an asphaltene dispersant/inhibitor into the CDU feed. The dispersing and inhibiting action of the antifouling technology, for instance Chimec antifou-lant, towards the asphaltenes prevents their precipitation in the desalting vessel.

A Marcello Ferrara, President, ITW, [email protected] of the most common refinery problems is asphaltenes precipitation in the desalter due to insta-bility of crude oil blends. Asphaltene instability can also promote sludge accumulation in the crude storage tanks and cause accelerated fouling phenomena in the preheat exchangers, along with a number of additional problems. Asphaltenes are also well known to stabilise water-in-oil emulsions. For some crude oil blends, asphaltene destabilisation can cause emulsion build-up with subsequent water carry-over and oil carry-under problems.

Sludge build-up in the desalter can cause sludge carry-over into the hot preheat train, thereby becoming an additional source of fouling.

In certain Western Canadian Sedimentary Basin (WCSB) crudes, the instability is enhanced by the addi-tion of paraffinic diluent to meet crude oil pipeline specifications.

ITW can help in solving the above problems by using patented asphaltene stabilisers in the crude blend.

Additionally, when sludge accumulates in the desalter, ITW Online Cleaning can be used to remove precipitated sludge in as little as 24 hours on an oil-to-oil basis, without the need to open the vessel and allow manpower to manually clean it.

A ParagShah,RefineryTechnicalHead,DorfKetalChemicals,[email protected] in a desalter may be due to the presence of filterable solids, asphaltenes and/or calcium naphthen-ate. If the precipitation is caused by filterable solids, solutions include good tankage preparation, providing sufficient settling time and use of good desalting aids. Dorf Ketal has proprietary desalting aids to manage crude solid content in excess of 1500 ppm. Precipitation by asphaltenes basically arises due to incompatibility caused in the crude blending process. This can be over-come by understanding the compatibility of the crude to be blended using oil compatibility studies. Dorf Ketal has the capability to conduct compatibility studies for more than 200 crudes. If a refiner is processing high calcium crude, the precipitation problem may be due to scaling arising out of the poor solubility of calcium salts. Dorf Ketals novel calcium removal approach includes acid based and a near neutral product

(non-acid based) calcium removal additive (CRA) to tackle the calcium naphthenate problems.

Q AretherelimitstoprocessingresidintheFCCimposedbymetalscontentinthefeed?Isthereanadditivetoeasetheproblem?

A Bilge Yilmaz, Global Technology Manager, BASF FCCCatalystDivision,[email protected] feeds typically contain contaminant metals including nickel, vanadium, iron, and others. These metals catalyse a variety of unwanted secondary reac-tions. Being an especially active dehydrogenation catalyst, Ni presents a considerable challenge to refin-ers as it significantly increases H2 and coke yields. In addition to taking part in unwanted dehydrogenation reactions, V comes with other major concerns as it is highly mobile under FCC conditions and its interac-tion with the zeolite destroys its framework structure, which manifests itself as increased H2 and coke yields, as well as lower zeolite surface area retention. Even small amounts of contaminant metals in the feed deposit cumulatively on the catalyst and can result in high H2 and coke make during FCC operation, which is a major concern for the refining industry. Even small increases in the yields of these relative to the yield of gasoline or other valuable products can cause signifi-cant practical problems. Development of FCC catalysts that can withstand the accumulation of contaminant metals and can help mitigate the negative conse-quences is of high industrial significance.

Several successful strategies have been adopted to decrease the deleterious effects of Ni within the FCC unit, including the introduction of antimony, which forms an inactive alloy with Ni. This strategy is usually controlled by the refiner at the FCC unit and is adjusted as needed. Incorporation of reactive trapping materials is a strategy adopted by catalyst manufactur-ers to address the problem within the catalyst particle itself. For example, certain specialty aluminas can be included in the catalyst particle for trapping contami-nant metals. Mobility of vanadium allows other possibilities for its passivation, such as the use of sepa-rate particle V-traps. There are also other novel metal passivation technologies developed as a result of the intense research efforts on this field. All in all, it can be concluded that with the right catalyst even severe residual feedstocks can be profitably processed.

A Carel Pouwels, Global FCC Specialist, Resid, AlbemarleCorporation,[email protected],GlobalFCCSpecialist,Additives,AlbemarleCorporation,[email protected] have a detrimental effect on catalyst perfor-mance in the FCC unit. The metals most commonly referred to are nickel and vanadium, while also sodium, iron and calcium negatively influence FCC operations and performance. Vanadium and sodium are known to increase deactivation of the catalyst (particularly zeolite) and lower catalyst activity. Nickel, and also vanadium, on the other hand catalyse dehy-

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1. Contaminant metals levels2. Amount of high boiling point feed components3. Unit constraints (wet gas compressor, air blower and slurry limits).

Deactivation of a catalyst by contaminant metals will typically occur from zeolite destruction or destruction of the pore structure of the exterior particle surface. Furthermore, these contaminant metals can increase hydrogen, dry gas and coke yields limiting conversion potential.

A Vivek Srinivasan, Senior Engineer, Technical Services, Dorf Ketal Chemicals, [email protected] are often concerns of RFCC catalyst deactivation due to the presence of metals in residue resulting in substantial costs on fresh catalyst. There are no defined limits for metal content and these limits are typically given by a catalyst provider, depending on the catalyst used in the system. Key metals that are present in the residue are calcium, sodium, iron, magnesium, nickel and vanadium. One can reduce the calcium, sodium and magnesium content by incorporating a desalter upstream of the RFCC reactor. In addition to desalting, use of metal removal additives give enhanced metal removal efficiencies. Dorf Ketal has a range of propri-etary metal removal aids which help in reducing the metal content including iron (up to 30%). Nickel gener-ally increases the dehydrogenation reaction resulting in increased hydrogen production in the off-gas and reduced valuable products. Nickel passivator additives are available to reduce the activity of nickel and improve profitability. Similarly vanadium passivators are also available that can reduce similar ill effects of vanadium.

Q What are the principal issues to address in blending and storage when high TAN crudes are included?

A Marcello Ferrara, President, ITW, mferrara@itw technologies.comA high total acid number (TAN) crude has the following properties: high acid value, fewer light components, high density and viscosity, high asphaltene content, high salts and heavy metals content, which give rise to equipment corrosion and severe operating problems.

The main issues for blending and storage a high TAN crude are in general: blending high TAN with low TAN crude, primarily the desired product mix, compatibility between the crudes, and the level of contaminants in the crudes and their asphaltenic contents. Blending is also used to reduce the naph-thenic acid content of the feed and to reduce the corrosion rate. Blending two different feedstocks may lead to incompatibility of the heavy crude constituents (asphaltene) in the more paraffinic light crude oil; for this reason there are many models claimed to predict incompatibility.

High asphaltene content, together with incompatibil-ity, will lead to sludge precipitation in the storage tanks. ITW can help in solving the problem by using

drogenation reactions and consequently increase hydrogen yield and coke to some extent. Finally, iron and calcium can build up on the catalyst surface and when present in higher amounts form nodules and block active sites and pores, thereby reducing conver-sion and increasing slurry yields, and also negatively influencing flow behaviour. The effect and magnitude of each metal is different and depends on the FCC unit where it occurs. Although Albemarle catalysts have proven to be effective with highly contaminated feed-stocks, encountering nickel concentrations in excess of 20 000 ppm and iron content greater than 1 wt%, the unit limitations, process conditions and economics also determine the absolute metals limit for a specific unit.

Regarding additive usage, the answer is again a mixed bag. The best known and proven additive solu-tion is the use of antimony to reduce the detrimental effects of nickel. The effect of antimony depends on the base catalyst that is used. An example is Coral SMR, which has exceptional nickel passivation (trapping) power with its ADM-60 matrix. Antimony, when used in conjunction with ADM-60, has less of an effect. The above mentioned record of more than 20 000 ppm was achieved with Coral SMR and without the use of Sb. Regarding vanadium and sodium, the most effective metal traps are highly active matrices such as ADM-20, which are built into our resid catalysts such as our Upgrader, Upgrader R+ and AFX series. While these matrices are predominantly applied for bottoms conversion, their vanadium tolerance is a welcome secondary benefit. Some suppliers promote separate additives to trap vanadium and other elements, but we have not detected any benefit in a commercial FCC unit. Albemarle executes continual R&D on metal trap additives and finds great benefits only in laboratory testing; thus, refiners that make their catalyst selection by laboratory testing are the principal users of such metal traps. This often adds costs to the catalyst, with minimal or no performance effects. Furthermore, these are often not even the best catalysts for the unit.

Finally we can address the use of additives for iron and calcium. The use of additives is typically not neces-sary when the catalyst is already designed for feedstocks with high amounts of these metals. Albemarle catalysts feature high accessibility, which allows a high amount of iron and calcium to build up before it has any detrimental effect. Catalysts like Upgrader and AFX have proven to function perfectly well under those conditions. However, if a refiner is using a catalyst with a high zeolite-to-matrix ratio, which often has low accessibility, the effect of iron and calcium is strong. In such cases an additive with high accessibility and high matrix activity, such as BCMT has proven to be a strong remedy. The use of such additive is the most effective solution for a quick recovery of the poor bottoms conversion of the poisoned host catalyst.

A Stuart Kipnis, Marketing Manager, Grace Catalysts, [email protected] of resid feeds requires an appropriate cata-lyst which will be influenced by a number of factors:

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patented asphaltene stabilisers in the crude blend. Additionally, when sludge accumulates in the tanks, patented ITW Online Cleaning can be used to remove precipitated sludge, without the need for opening the tank and manually cleaning it. This will avoid or dramatically reduce downtime and concerns related to conventional tank cleaning techniques.

The sludge is transformed into a fully reusable prod-uct and the recovered sludge can be reprocessed without any concern.

A Vivek Srinivasan, Senior Engineer, Technical Services, Dorf Ketal Chemicals, [email protected] that the general practice of blending is followed (no incompatibility issues), high TAN crudes do not have any issues in blending and storage. The constraint faced in blending high TAN crude is the precision required to achieve the desired TAN values of the overall blend.

Q We use delayed coking for diesel make at present. Is there a process option for raising conversion levels, and with what sort of payback time?

A Avishek Sengupta, Senior Engineer, Technical Services, Dorf Ketal Chemicals, [email protected] yield in a delayed coker is mainly driven by operational parameters like temperature, pressure, recy-cle rate and the nature of the feedstock. With feedstock constraints and limited process operating handling, further improvement in the liquid yield is a big chal-lenge. However, with advancement in technology, Dorf Ketal has introduced a proprietary additive range under the CokerMax brand which helps to improve the liquid yield by greater than 1%. Based on internal studies and commercial experience, the CokerMax range does not affect coke morphology and most of the liquid yield gain happens in the middle distillate products.

Q What type of compressor design would you say is the most reliable with least loss of gas for hydrogen supply to a hydrocracker or HDS unit?

A Paul Peyer, Marketing Communications Manager, Hoerbiger Ventilwerke, [email protected] compressors are often the best, most reli-able and most economic solution for compression of hydrogen to supply a hydrocracker or HDS unit. They are flexible, energy efficient and suitable for high pres-sure applications.

In the past, reciprocating compressors were often considered unreliable with difficulties in achieving precise control of their output capacity, and electric power was wasted because the compressor capacity was typically controlled by recycle valves (often referred to as bypass or spillback valves). With todays advanced control systems (for example, reverse flow control), this energy waste is a thing of the past and high flexibility in the variation of gas supply can be achieved.

The same applies for leakages. In the old days, one of the main leakages in reciprocating compressors was over the main pressure packing, but with todays tech-nology (new packing ring design, and so on) leakages could be reduced to a minimum and in the best case zeroed out.

Q The CO2 content of our sour water stripper gases results

in a high reagent turnover in the caustic scrubber. Solutions please.

A Marcello Ferrara, President, ITW, mferrara@itw technologies.comReagent turnover depends basically on stoichiometry and scrubber efficiency. While stoichiometry is related to gas composition only, operational scrubber effi-ciency is affected by fouling. Fouling of caustic scrubbers is quite common, as the composition of treated gases normally contains unsaturated compounds. ITW can help to solve the fouling prob-lems of caustic scrubbers by implementing Online Cleaning and cleaning the equipment in as little as 24 hours on a process-out/process-in basis.

Q The exchangers cooling output from our visbreaker have particular problems with fouling. Can we resolve this upstream or through exchanger design?

A Eva Andersson, Market Manager Refinery, Alfa Laval, [email protected] mitigation of visbroken residue heat exchangersVisbroken residue foulingVisbroken residue is one of the most fouling fluids among refinery processes. Even with a properly designed quench, some thermal cracking will still continue when the fluid enters the heat exchangers and the resulting cracking products have a special affinity for metal surfaces, something that is even further aggravated due to precipitation of asphaltenes.

With high efficiency cooling and short exchanger residence time, the above two fouling parameters can be minimised but still not completely avoided.

In order to further reduce or even eliminate fouling problems, high and uniform heat transfer channel velocity is required and dead zones with low or no flow must be avoided as much as possible.

Such heat exchanger design is impossible to achieve in traditional shell-and-tube heat exchangers, where several long, bulky exchangers are required to carry out the heat recovery service (visbroken residue versus feed, crude preheating or even steam generation). Maldistribution in heat transfer channels is a common problem and dead areas are present in turning cham-bers or behind baffles.

Due to this, refineries operating this heat recovery service with traditional shell-and-tube heat exchangers all suffer from heavy fouling problems, and run lengths of those exchangers in between cleaning are normally short, maybe just a few months.

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such procedure is very easily carried out by means of HP water-jet, as both heat transfer channels are fully accessible once the bolted end covers are removed.

Experience with spiral heat exchangers in visbroken serviceThe first SHEs operating in visbroken residue/feed interchanging service were commissioned in 2001 in order to solve a very high fouling situation in a European refinery.

Cleaning of the visbroken/tube side of the hot end shell-and-tube heat exchangers, out of the total 12 exchangers installed for this service, was required every month and the procedure took almost 30 days, including drilling of tubes.

The additional firing of the furnace meant the process cycle length was only around 12 months in between plant shutdown and decoking of the furnace.

After the shell-and-tube heat exchangers were replaced by eight SHEs, no cleaning of exchangers was required in between plant shutdowns and the cycle length was increased to 18-24 months.

HP water-jet cleaning is only required of the hot end visbroken residue channel and total time for cleaning of the exchangers is only five days.

In addition, SHEs are designed for better heat recov-ery than the original shell-and-tube heat exchangers so, when in operation, the energy efficiency of the plant is further improved.

The pay-back time for replacing the original shell-and-tube heat exchangers was around two years, based on higher plant availability, reduced process energy consumption and fewer maintenance and replacement costs.

Based on the performance of SHEs in this plant and service, today there are almost 50 units operating in visbroken residue service in nine different plants around the world. In total, there are more than 200 SHEs operating in various high fouling refinery services.

A Marco Roncato, Process Technological Unit, Chimec, [email protected] Running visbreaking plants at the maximum possible severity unavoidably leads to fouling formation: the more severe the reaction is, the more prone the system to fouling becomes.

The cause of fouling in process equipment is partly organic (polymerisation products, destabilisation of asphaltenes and coke) and partly inorganic (sediment deposits, sand, corrosion products, salts and sulphide compounds).

Asphaltene fouling is caused by their destabilisation in the hydrocarbon matrix and it depends on: Reduction in resin content Reduction in the H/C ratio Agglomeration of asphaltenic micelles.

These being the root causes of fouling, to improve HEX performance (or, generally speaking, the plants performance) while running the plant at the maximum severity, we suggest adopting the following measures:1. Improvement of the desalters efficiency: the lower

Negative aspects of heat exchanger foulingCleaning of the visbroken residue heat exchangers can be a very time-consuming effort. Most of the time, those exchangers must be flushed with diesel (or simi-lar hydrocarbon fraction), steam purged and then the tube bundle must be removed for HP cleaning and sometimes even drilling. It is not uncommon to have the exchangers out of service for 10-20 days and some-times high grade material is needed to make sure the tube bundles can withstand the severe handling.

Frequent cleaning of those exchangers does not only lead to high maintenance and replacement cost, but might also affect the operational cost of the process if the energy recovered is used to preheat the feed.

With a high fouling rate, giving rise to low heat transfer efficiency, or when having exchangers out of service for cleaning, the feed inlet temperature to the furnace is reduced, and more fuel is needed to preheat the feed to required temperature before the cracking.

This might lead to too high heat flux in the furnace, something that will shorten the run length of the plant, as furnace decoking will be required more frequently.

In the worst case scenario, if the furnace capacity is limited, throughput might even have to be reduced.

So, fouling in visbroken residue heat exchangers for sure is a very costly problem!

Use of spiral heat exchangersMany refiners have already recognised the anti-fouling properties of spiral heat exchangers (SHEs) in high fouling services, such as desalter effluent/feed inter-changing, (R)FCC main fractionator slurry/feed interchanging or cooling and of course visbroken resi-due/feed interchanging.

The spiral channel of the exchanger gives around three times higher heat transfer efficiency than tradi-tional shell-and-tube heat exchangers, meaning that the cooling of the residue is quicker and the thermal crack-ing will stop faster. In addition, due to its fully counter-current flow, fewer heat exchangers and a shorter heat transfer channel are required, hence the hold-up time in the exchangers is minimised.

However, the most important anti-fouling feature of the SHE is its single channel flow design. There is only one heat transfer channel for the hot fluid and only one heat transfer channel for the cold fluid. It means there is no possibility for maldistribution of flow in the heat exchangers, the channel velocity is easily controlled and a certain self-cleaning effect is achieved. If particles start to settle in the heat transfer channel, the cross-section in that area is reduced and the local velocity increased until the particles are scrubbed away.

The connections, inlets and outlets of those two heat transfer channels are also designed to avoid dead zones where fouling could partly or fully plug the heat transfer channels.

Combined together, all these features give a heat exchanger with very low or almost eliminated fouling tendency.

Should fouling still occur and cleaning is needed,

Q&A copy 15.indd 5 09/06/2014 12:12

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and 2) Can we effectively maximise propylene for both feeds. Whether we can run both types of feed in the same process set-up can in general be answered posi-tively. But unit limitations such as regenerator temperature or wet gas compressor can determine how much of each of the feeds can be processed. The total fresh feed rate can be different or, in the case of constant fresh feed rate, the blend ratio of either feeds with VGO can be different. The difference in both feeds in terms of metals content, hydrogen content, Conradson carbon and other properties will determine the crackability and slurry yield on one hand or the tendency of coke make (such as feed coke or metals coke) on the other hand. Consequently the yield struc-ture in both cases will be different. The more refractive feed will typically lead to lower conversion, more slurry and more coke. The question now is if propyl-ene yield can be maximised effectively in both cases. The typical answer in FCC is It depends. In principle the propylene yield can be maximised for both cases. But again unit limitations determine how far the C3= yield can be pushed. The case of hydrotreated resid for instance is expected to lead to higher conversion with the potential to higher propylene yields. But if the gas section is strongly limited, the refiner can not take the full benefit and needs to suppress LPG production and thus C3=

Important for both feed cases is the choice of the optimal catalyst. The optimal catalysts for both cases are not expected to be the same. Your catalyst supplier can help you further to work out both cases and deter-mine which is the optimal catalyst design for each feed. Albemarle has a wealth of experience in process-ing resid as well as in maximum propylene applications. For the typical max C3= applications of 10 wt% and more, AFX has proven to be very success-ful in a wide range of feedstocks, including but not limited to both 100% untreated AR cases 1 as well as treated resid 2. In the case of lower propylene yields, Albemarle recommends several resid catalysts ranging from most coke selective to best bottom conversion: Coral SMR, Upgrader R+ and Upgrader and which will be combined with Durazoom for the generation of the desired level of propylene.

What all these products have in common is the prop-erty of high or highest accessibility. This physical property is not only of high importance for resid processing and leading to the lowest slurry yields, but is also key for propylene maximisation as it minimises the unwanted hydrogen transfer reaction. With the application of this high accessibility, Albemarle has maximised C3= yields, within unit limitations, of FCC units processing hydrotreated VGO, hydrotreated resi-due and straight-run residue.

References

1 AmanoT,Wilcox J, PouwelsA C,MatsuuraT, Process and catalysis

factorstomaximisepropyleneoutput,PTQQ32012,17-27.

2 PouwelsAC,Liftingthepropyleneplateau,Hydrocarbon Engineering,

Jan2012,23-29.

the BS&W and the lower the caustic injection in the desalted crude are, the lower the role of foulings inor-ganic component in reducing HEX performance will be2. Close management of the cracking reaction, in order to avoid fouling peaks: Chimec has developed a computerised instrument, the Chimec Analyzer, which allows one to analyse the quantity and quality of the coke particles in the residue and feed in an optical way.

The Chimec Value analysis takes only a few minutes and gives the residue stability value.

The unit reaction severity can be optimised rapidly according to the Chimec Value analysis and allows a secure and optimal management of the visbreaking3. Injection of a suitable chemical in the main fraction-ator bottom line in front of the exchangers: to face the above described very complex phenomenon, it is necessary to use a multifunctional product, providing different kinds of protection: Stabilizer for reactive olefins being formed during the cracking reaction Dispersing agent for asphaltenes (potential coke precursors) and inorganics.

During the last three decades Chimec has developed a specific line of tailor-made products aimed at manag-ing and controlling the above mentioned reactions.

A Parag Shah, Refinery Technical Head, Dorf Ketal Chemicals, [email protected] problem with fouling in the cooling exchangers is very common in visbreakers across the globe. One option to control fouling is by increasing the velocity. Another option is the use of antifoulants which not only extends the run length but also helps sustain the conversion since the furnace inlet temperature is main-tained close to the start of run range with effective fouling control. Dorf Ketals new generation antifoulants help in enhancing the visbreaker units profitability.

A Marcello Ferrara, President, ITW, [email protected] Online Cleaning can clean the equipment in as little as 24 hours on an oil-to-oil basis without extract-ing the bundles. Additionally, the fractionator lines and filters will all benefit from Online Cleaning.

By applying ITW Online Cleaning, there is no need to redesign the exchangers or to revamp the unit (as far as fouling is concerned) because its regular applica-tion will allow a run under clean conditions. This is a mind shift versus the normal run to death mode of running a unit.

Q Can we effectively maximise propylene from the FCC with either hydrotreated resid or straight run resid using the same process set-up?

A Carel Pouwels, Global FCC Specialist, [email protected] question can be split up into two questions: 1) Can we use the same process set-up in an FCC unit with either hydrotreated resid or straight-run resid;

Q&A copy 15.indd 6 09/06/2014 12:12

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Tail gas catalyst performance: part 1

The tail gas unit (TGU) process has been developed to remove sulphur compounds from

Claus tail gas in order to comply with stringent emission regulations. From the early 1970s to today, TGUs have been improved to meet higher levels of performance for ever tighter environmental require-ments and to reduce capital or operating cost. Reactor performance is a critical parameter in achieving a TGUs environmental performance. Conversion of sulphur species to H2S is a function of catalyst activity, reactor space velocity and tempera-ture. Assessment of the impact of these principal variables on both catalyst bed design and perfor-mance is the subject of this article which is presented in two parts. In the first part, an introduction to the ClausTGU sulphur recovery complex provides a framework for examining the impact of operating and design parameters, process development history, equipment line-up evolution, catalyst develop-ments, and reactor chemistry. The first part also provides an introduc-tion to reactor modelling, describes the reactor pilot plant system, and examines chemical equilibria which affect TGU performance. The second part develops reactor model-ling and examines the effects of space velocity and temperature.

Reducing sulphur emissionsTGUs are built for a specific purpose increasing the overall sulphur recovery of the Claus-TGU sulphur recovery complex to about 99.9% from about 96% achieved on a Claus plant alone (see Figure 1). Their sole purpose and economic

The first part of a two-part account of time and temperature effects on tail gas catalyst performance provides a background to reaction modelling and pilot studies

MICHAEL HUFFMASTER Consultant FERNANDO MALDONADO Criterion Catalysts

justification is reducing sulphur emissions, which improves overall environmental quality. In the reductive tail gas process addressed herein, achieving good performance requires high conversion of sulphur compounds to H2S in the reactor. Achieving good performance there-fore requires setting reactor operating conditions based upon understanding the influence of key operating variables affecting the catalyst bed.

The key parameters affecting performance of the catalyst bed are catalyst kinetic properties, tempera-ture, and tail gas loading/space velocity: A catalysts kinetic properties are determined by its manufacture, activation and aging Temperature affects catalytic activity and thermodynamic equi-librium, limiting conversion Reactor loading directly impacts space velocity, which controls conversion.

Tail gas reactor loading and temperature effects are represented in first order reaction mechanics and thermodynamic equilibrium. These relationships provide a good

model for understanding the influ-ence of these operating variables and show higher gas loading results in lower conversion. Data from catalyst testing in Criterions pilot unit are presented to illustrate these kinetic effects.

Application and interpretation of information for assessment of reac-tor performance and catalyst activity will be discussed, including: Temperature profile observed in the reactor bed Changes in conversion, indicated by increased incinerator emissions (SO2 and CO) Activity evaluation from reactor inlet and outlet stream composition and determination of aging, usually by unit testing and analyti-cal evaluation results Measuring physical properties and/or activity testing for actual catalyst sample.

This article is intended to help TGU operators and designers improve environmental perfor-mance by understanding these effects and applying principles to designs or improving performance of existing units.


Acid gas

Claus unit94-98% recovery

Tail gas unit99.8%+

recoveryThermal

incinerator

H2SCOS

SO2H2S

Recycle H2S Trace SO2

Molten sulphur

Figure 1 Sulphur recovery complex

criterion.indd 1 11/06/2014 10:51


2% to 6%, polluted the environment as SO2.

Reductive tail gas processesSeveral types of TGUs were devel-oped to further mitigate the pollution released into the environ-ment by Claus units. The best performing TGUs utilise a cobalt molybdenum (CoMo) on alumina catalyst. These processes, when properly operated, convert nearly all of the sulphur species to H2S. The H2S is then captured in an amine circuit and recycled to the Claus unit. Overall, this achieves a recovery of 99.9% or more of the sulphur fed to the Claus unit, achieving the environ-mental performance required of virtually all regulatory settings. Less than 0.1% of the sulphur in the Claus feed is released into the environment.

Principal reactions in the tail gas reactor are hydrogenation and hydrolysis of sulphur species (SO2, COS, CS2, Sx) and water gas shift for CO. Catalysts with high activity and good selectivity are needed to accomplish these reactions at reasonable space velocities and at moderate temperatures.

The majority of the sulphur compounds in Claus tail gas are converted to hydrogen sulphide, but not completely. Most reactions are equilibrium limited, causing several sulphur compounds to survive at the ppm level. The most critical is COS because equilibrium limitations are the most significant for COS, as well as kinetics. These limit ultimate outlet concen-tration by equilibrium as well as limitations for the kinetic reac-tion function, which result in conversion around 80-90%. This means typical residual COS is in the 10-40 ppm range. The residual COS is not removed by amine in the absorber. In some instances, combinations of high CS2 feed concentrations and lower tempera-ture TGU operation produce mercaptan compounds. The resid-ual COS and mercaptan compounds, in combination with the H2S slip from the removal step in the absorber, dictate overall sulphur recovery performance.

The Claus processThe Claus process is the most significant gas desulphurising process, recovering elemental sulphur from gaseous hydrogen sulphide. The multi-step Claus process recovers sulphur from the gaseous hydrogen sulphide found in raw natural gas and from the by-product gases containing hydro-gen sulphide derived from refining crude oil and other industrial processes. The Claus process utilised in a sulphur recovery unit (SRU) recovers 94-98% of the sulphur in the feed. Used in conjunction with a reductive tail gas process, the Claus process further increases the recovery achieved in the sulphur recovery complex to 99.9%.

In the Claus process, a concen-trated stream of H2S is partially burned to form SO2. The SO2 reacts, first thermally and then in subse-quent steps, catalytically, with H2S to form elemental sulphur. The produced sulphur is transported as a melt or as a solid.

H2S + 3/2 O

2 SO

2 + H

2O + Heat

2H2S + SO

2 3S + 2H

2O + Heat

These reactions to form sulphur are in equilibrium; therefore, conversion to sulphur is increased by condensing the product sulphur from each stage, reheating the mixture and taking subsequent steps to lower reaction tempera-tures. Higher temperatures limit sulphur recovery by shifting the equilibrium towards the reactants. Increased pressure in the Claus process requires higher reaction temperatures in the second and third stages to maintain margin above the capillary condensation temperature of elemental sulphur. The increased temperatures also then limit sulphur recovery via this process.

When the Claus effluent gases exit the final condenser, the major-ity of the incoming H2S gas stream has been recovered as elemental sulphur and only residual amounts of unreacted sulphur dioxide and hydrogen sulphide and uncon-densed elemental sulphur remain.

The gas exiting the Claus unit also contains large volumes of water vapour, a co-product of H2S conver-sion; hydrogen from H2S cracking and sub-stoichiometric combustion; and large volumes of nitrogen, if air is used in the combustion of the hydrogen sulphide. Additionally, carbon compounds that enter the process or form through combus-tion (CO, CO2, hydrocarbons) react with sulphur species in the reaction furnace to form carbonyl sulphide (COS) and carbon disulphide (CS2) some of which remain unconverted.

The COS and CS2 in tail gas result from the quality of acid gas feed to the Claus unit and are converted in the first Claus reactor. In this reac-tor, it is possible to utilise alumina catalyst, which can have fairly rapidly aging or more robust titania catalyst. Conditions of temperature,

residence time and concentration influences how much of these compounds reach the TGU and, in concert with environmental perfor-mance criteria, the degree of conversion required.

The concentration of these compounds is governed by complex equilibrium. This mixture of dilute sulphur and carbon compounds in the steam and nitro-gen stream is labelled as tail gas. The sulphur species included in the tail gas comprise 2-6% of the total sulphur entering the Claus process. Initially, Claus process operators were allowed to incinerate the tail gas mixture to sulphur dioxide, a less odoriferous compound, and discharge it to the atmosphere. Under this scenario, the recovered sulphur comprised only about 94% to 98% of the sulphur entering the process. The balance of the sulphur,

The Claus process is the most significant gas desulphurising process, recovering elemental sulphur from gaseous H

2S

criterion.indd 2 11/06/2014 10:51

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UOP delivers complete modular process units for the petroleum refining, petrochemicalsand gas industries. Modular delivery minimizes overall project schedule, cost and risk bymaximizing prefabrication of complex process units under quality controlled conditions andunder the watchful eye of the process licensor. UOP has delivered more than 1,200 fully engineered and fabricated UOP process units to the global oil and gas industries.

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TGU equipment line-upThe reductive tail gas process preheats tail gas feed to the TGU reactor, where sulphur compounds are reduced to H2S. A quench step removes water formed in Claus and combustion; the gas is cooled to an acceptable temperature for amine use. An amine absorption step removes H2S from the process gas, and the H2S is recycled to the Claus process. The off-gas is vented or incinerated. The amine system is selective toward H2S, slip-ping most of the CO2. Amine can be supplied from a dedicated regenerator or integrated with an


amine stripper servicing several systems. Generally, units with a dedicated stripper achieve lower H2S slip and higher overall sulphur recovery. A simplified diagram of a conventional TGU is shown in Figure 2.

Equipment in a TGU includes: In-line heater or reducing gas regenerator (RGG) Reactor with CoMo catalyst HRU (optional) Quench column and water cool-ing circuit Recycle (Start-up) blower or ejector Booster blower (optional)

Amine absorber/regeneration circuit.

For a low temperature TGU, an indirect heater can be utilised, typi-cally a steam heat exchanger in place of a fired heater, which is a major advantage. This line-up offers simpler, easier operation, lower operating cost and fewer upsets or trips. The remaining portion of a low temperature TGU is mechani-cally similar to a conventional TGU. A simplified diagram of a low temperature TGU is shown in Figure 3. There are several advantages with respect to low temperature TGU operation, including:

Fuel gas

SRU tail gas

Air

Steam

Steam

Condensate to SWS

Off-gas to incinerator

Heater

Reactor

Quench column

Absorber

Stripper

HRU

Recycle gas to CLAUS SRU

Figure 2 Simplified diagram for a conventional tail gas unit

HP saturated steam

SRU tail gas

Steam

Condensate to SWS

Off-gas to incinerator

Heater

Reactor

Quench column

Absorber

Stripper

Recycle gas to CLAUS SRU

Figure 3 Simplified diagram for low temperature tail gas unit

criterion.indd 3 11/06/2014 10:52

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amount of non-H2S sulphur atoms in the tail gas stream, typically 80%, and they must be converted to H2S. Also, elemental sulphur must be converted to prevent accumulation in catalyst pores and inhibiting catalyst function. These reactions are so favourable and strongly driven by the catalyst that the reac-tions are not considered equilibrium limited; that is, the equilibrium residual is in the parts per billion range. It is critical, however, that ample reducing gas be available for these reactions:

SO2 + 3 H

2 H

2S + 2 H

2O (1)

SO2 + 2 H

2 S + 2 H

2O (2)

Sx + x H

2 x H

2S (3)

Secondly, the most significant reaction is water with carbonyl sulphide (COS) and carbon disul-phide (CS2) by hydrolysis. Carbon disulphide is converted to COS (Equation 5), followed by subse-quent hydrolysis of COS (Equation 4). For these reactions, the role of equilibrium is essential because the presence of CO2 and H2S estab-lish a limit for the concentration of COS.

COS + H2O H

2S + CO

2 (4)

CS2 + H

2O H

2S + COS (5)

Another important reaction is conversion of CO by water, referred to as the water gas shift. This reac-tion also is equilibrium limited:

CO + H2O CO

2 + H

2 (6)

Although the conversion of CO does not directly impact sulphur emissions, it is a useful reaction

(WABT) of 570F (300C), although this has been extended to as low as 450F (230C) RIT and 480F (250C) WABT with second genera-tion catalyst improvements. Low temperature TGU operation is typi-cally defined as operation at a RIT less than 430F (220C) and WABT less than 465F (240C), and there is the expectation of seeing a RIT as low as 390F (200C). A low temperature TGU operation requires a high activity catalyst.

Tail gas reactor chemistryThe purpose of the TGU catalyst reactor is to convert as much of the various sulphur compounds as possible into H2S so that the amine absorber can recover sulphur species in the form of H2S. The catalysts utilised promote hydroly-sis reactions and hydrogenation reactions as well as a water gas shift reaction.

The TGU reactor catalyst has two types of catalytically active sites hydrolysis sites driven mainly by basic support like alumina, and hydrogenation sites and CO reac-tion sites driven by the presence of sulphide compounds of transition metals like cobalt and molybde-num. The most important specification relevant to the TGU catalyst reactor design is the organic sulphur outlet. This total organic sulphur outlet, a measure of how much COS and CS2 is left unconverted and also how much CH3SH is formed in the TGU reac-tor, largely impacts sulphur emissions.

The most important reaction that occur in the TGU reactor are the reactions of hydrogen with SO2 and elemental sulphur for conversion to H2S by hydrogenation. These two species constitute the greatest

Lower costs (capital and operating) Reduced TGU tail gas volume Higher reliability and operating simplicity Units with indirect heating require no combustion controls Elimination of risk of catalyst damage by RGG misoperation Longer catalyst life Lower production of greenhouse gases.

TGU catalystCatalysts for TGU reactors utilise alumina base with cobalt and molybdenum sulphides, which have active sites for hydrolysis, hydrogenation and water gas shift. Catalytic activity is a function of a catalysts kinetic properties, activa-tion and operating temperature. At the low end of the temperature range, equilibrium related to reac-tion pathways is not a limitation but catalysts are challenged to have sufficient activity. At the upper range of temperature, catalytic activity is strong but equilibrium back pressure increases to become significant. These offsetting trends impact the selection of an appropri-ate operating point and ultimate degree of H2S conversion that can be achieved for sulphur species.

Tail gas catalysts have evolved. First generation catalysts were re-purposed hydrotreating cata-lysts. Second generation catalysts were specifically developed as high activity, high porosity, long-life catalysts. Third generation catalysts are contemporary, low temperature catalysts. The activity of catalysts has improved, allowing operation at even lower temperatures. Now, units are designed with low temperature catalysts without a burner for pre-heat. Additional properties to note are mechanical strength, bulk density, pressure drop and resistance to aging. The general design requirement for acceptable conversion performance across this development track is outlined in Table 1.

Conventional TGU operation is typically defined as operation at a reactor inlet temperature (RIT) greater than 520F (270C) and weighted average bed temperature

RIT WABT aGHSV (1/hr)First generation catalysts 545F 572 625F 1000-1500 285C 300330C Second generation 445-535F 480-572F 2000-2500 230-280C 250-300C Third generation 410-430F 445 to 465F 1500-2000(low temperature) 210-220C 230-240C

Catalyst development for tail gas units

Table 1

criterion.indd 4 09/06/2014 12:45


is to determine the ability of a cata-lyst sample to perform: Conversion of SO2 and elemental sulphur to H2S, hydrogenation function Conversion of COS and CS2 to H2S and CO2, hydrolysis function Conversion of CO to H2, water gas shift function Minimisation of formation of COS (sour shift) or mercaptan (partial hydrogenation). Additional applications which the unit design will accommodate with little to moderate revision are: SCOT catalyst degradation and aging SCOT catalyst passivation or regeneration Incineration catalysts for off-gas Gas phase hydrogenation (up to 300 psig pressure) Claus catalyst.

The gas metering section is equipped with 15 Brooks 5280 mass flow controllers for each reactor; these regulate flows and blend gases to prescribed experimental conditions. Gases are supplied by cylinder (H2S, SO2, COS, CS2, RSH, CO, CO2, CH4) or from house systems (air, N2, H2); inlet pressure to the unit is 60-100 psig (4-6 barg). The pressure of the outlet gas is typically 1 psig (~1.0135 bara), although back pressure up to 15 psig (~1 barg) can be applied.

Reactor modellingIn order to predict the performance of TGU reactor systems, a basic framework of chemical equilibrium, reaction chemistry and catalyst activity is used. This, in turn, provides a tool to evaluate the effects of space velocity and temperature on reactor performance.

The requisites for good reactor design and operation must be met to achieve good performance. The assumption in modelling and predicting performance is that all the other things are done correctly.

Process selection and design must include a good design for reactor hardware including gas distribu-tion and catalyst support; ample catalyst (space velocity) to achieve conversion required for feed conditions and environmental

via hydrolysis (Equation 5) also is more strongly competing against hydrogenation (Equation 8).

SCOT micro-reactor catalyst testing system R0111The SCOT (Shell Claus Offgas Treater) micro-reactor system is built for analysis and evaluation of catalysts used in industrial sulphur recovery applications like SCOT units or Claus TGU, which repre-sent most gas plant and refinery applications. Typically, these cata-lysts are cobalt-molybdenum on an alumina carrier, but may contain other components. The experimen-tal rig consists of two reactors sets, with related supply gas flow controllers, safety system PLC and HTE control software. This equip-ment is located in Shell Technical Center Houston and operated by CRI/Criterion staff.

The SCOT micro-reactor system

is a bench scale test unit, and each reactor system is equipped with the following: gas metering, mixing manifold, vaporiser for water, nitrogen saturator for elemental sulphur, reactor feed pre-heat, and a reactor with a four heat zone furnace followed by a cooler, sulphur/SO2 indicator and cold trap. An analysis section with a gas chromatograph (GC) plus CO by IR and SO2 by UV support both reac-tor trains. All materials exposed to process gases are 304L or 316L stainless steel. The two reactor trains are parallel, independent systems set inside a negative pres-sure, ventilated enclosure.

The testing protocol for this unit

that provides hydrogen needed for hydrogenation. The significant reduction of CO concentration is important for what may otherwise be a regulated emission or require high temperature incineration for control. As more jurisdictions around the world adopt CO emis-sion specifications, CO conversion in the TGU reactor becomes more important.

These six reactions represent the general chemistry that occurs in the TGU reactor. There are other reac-tions that must be considered when making performance predictions, particularly when considering a low-temperature TGU operation. First is the reaction of CO with H2S, the sour shift. This reaction plays an important role for CO and COS conversion, via inter-conversion of CO and COS. The reaction is strongly equilibrium regulated, and as reactor temperature is lowered, levels of CO increase due to kinetic limitation of the water gas shift:

CO + H2S COS + H

2 (7)

Secondly, the formation of methyl mercaptan by hydrogenation of CS2 is important in low temperature TGU operation. Methyl mercaptan is an intermediate product of CS2 hydrogenation to CH4. Between the two expressions (Equations 8 and 9), the latter reaction of hydrogena-tion of CH3SH to methane (Equation 9) is assumed to be rate determining:

CS2 + 3 H

2 CH

3SH + H

2S (8)

CH3SH + H

2 H

2S + CH

4 (9)

This pathway is in competition with hydrolysis, which becomes weak at low temperatures. For low-temperature TGU operation, it is generally advised to keep CS2 feed content to the TGU below 250 ppm. This may be accomplished in the upstream SRU by a combina-tion of operational and catalytic approaches. For conventional TGU operation, mercaptan formation is typically of little importance. At higher temperatures, conversion of CH3SH to methane is a strong func-tion. In addition, CS2 conversion

In order to predict the performance of TGU reactor systems, a basic framework of chemical equilibrium, reaction chemistry and catalyst activity is used

criterion.indd 5 09/06/2014 12:46

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Chemical equilibrium reactionmodel parametersThe equilibrium point for a chemi-cal reaction determines the ultimate extent to which a reaction will proceed, the point at which the forward reaction rate equals the reverse reaction rate. The process chemical equilibrium constant, Kp, is an expression of that relation-ship, the ratio of concentration of reaction products to concentration of reaction feeds:

[Products] Kp = --------------- [Reactants]

For the water gas shift reaction, the expression is:

[Products] [H2] * [CO

2]

Kp wgs = --------------- = ---------------- [Reactants] [CO] * [H

2O]

and for COS hydrolysis: [H

2S] * [CO

2]

Kp cos = --------------- [COS] * [ H

2O]

The concentration of individual components is tied to the equilib-rium constant; when one component changes, others adjust to keep the product/reactant ratio the Kp constant. When the Kp is available, the expression can be solved for the concentration of a reactant if other component concen-trations are known. For equimolar reactions there is no pressure sensitivity.

The equilibrium expressions can be arranged to provide the compo-nent equilibrium concentration value, that is, back pressure or minimum value, which can be reached for the component in the system: [H

2] * [CO

2]

[CO] equilibrium = -------------------- Kp wgs * [H

2O]

The process equilibrium constant relates to the driving force for the reaction, the difference between the Gibbs free energies of the products minus reactants at the reaction

Equilibrium considerations will be addressed first, then kinetics.

Conversion is a term of frequent reference in this article. Conversion for CO (or COS) is expressed as disappearance across the reactor and is adjusted for the equilibrium back pressure of the reacting component:

COout CO

equilibrium

Conversion = 1 - ---------------------- CO

in CO

equilibrium

Tail gas reactor temperature operation has historically ranged between 200C and 325C. This fits within the region of active catalyst functions and meets the required minimum temperature for catalytic activity function, about 200C for low temperature catalyst and 240-300C for conventional tail gas catalysts. The maximum tempera-ture is generally limited to 345C (650F) to avoid sulphide corrosion of process equipment and acceler-ated decline in catalyst activity and surface area by hydrothermal aging.

The process operates near atmos-pheric pressure, and most of these reactions are equimolar. Therefore, pressure has no-to-small influence on equilibrium.

requirements; and quality catalyst selected, with suitable activity for intended operating conditions. The catalyst must be properly loaded, activated with appropriate proce-dures, and damaging conditions avoided. It is critical to have adequate reducing gas (provided from Claus, RGG or supplemental hydrogen) to avoid SO2 break-through and severe process consequences (low quench pH, sulphur formation in quench water, amine degradation). With good gas distribution across the catalyst bed, acceptable pressure drop for the process line-up and inlet concentra-tions within the design boundary, one can move forward to the impact of gas rate and time and temperature on performance.

The influence of temperature on performance has competing effects in kinetics and equilibrium, impact-ing conversion. The kinetics for reactions of importance are favour-ably influenced by higher temperature, proceeding to higher conversion at a given space veloc-ity. Equilibrium effects from higher temperature usually result in higher equilibrium concentrations for the species, which the system is designed to destroy, limiting lower value for outlet concentration.

Temp,C Temp, F COS hydro COS sgs CO wgs 200 392 4697 0.050 236 220 428 3297 0.047 156 240 464 2378 0.045 107 260 500 1757 0.043 75.5 280 536 1326 0.041 54.7 300 572 1020 0.040 40.6 320 608 898 0.039 30.8

Process equilibrium constants, Kp

Table 2

Temperature 390F 480F 570F (200C) (250C) (300C) Reaction SO

2 + 3 H

2 -> H

2S + 2 H

2O 3 E19 3 E17 1 E15

S + H2 -> H

2S 4.4 E4 2.1 E 4 1 E4

CS2 + H

2O -> H

2S + COS 6 E5 2 E5 5 E4

2 H2S + SO

2 -> 3/8 S

8+ 2 H

2O (Claus) 3 E5 4 E4 5 E3

Equilibrium constants, Kp for non-equilibrium limited reactions

Table 3

criterion.indd 6 09/06/2014 12:46

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PTQ_Issue Q2.indd 1 03/03/2014 17:50:54biflinger.indd 1 04/03/2014 10:57

water gas shift; intermediate values can be interpolated.

Note: Kp values for COS hydrol-ysis derived from JANAF/NIST/DIPPR are about factor two higher than historical values of Kp of Terres and Wesemann, as published in Kohl and Riesenfeld, and Kp values for sour gas shift from NIST/DIPPR are about factor 2 lower. Water gas shift Kp values are within 5% for the various sources.

For reference, Table 3 provides Kp with respect to other, non- equilibrium limited reactions: SO2 equilibrium is very strongly favoured at TGU reactor operating conditions, with SO2 equilibrium at 1E-11 ppm for 300C and 1E-17 ppm for 250C; residual SO2 is negligible in either case Elemental sulphur hydrogenation is also strongly favoured, although kinetically limited CS2 equilibrium is also strongly favoured by hydrolysis (forming H2S and COS), making equilibrium back pressure below 1E-6 ppm for typical outlet conditions Claus is favoured, especially at lower temperatures, and can help convert SO2. At higher temperature TGU conditions, only a small frac-tion of SO2 will react via Claus before equilibrium limits are reached.

Equilibrium concentration values for various components in the reac-tor outlet are shown in Table 4 under conditions representative of TGU feeds and outlet conditions.

The COS equilibrium chart (see Figure 4) shows the concentration of COS in ppm (wet basis) in equilib-rium with a tail gas outlet composition; total carbon refers to CO plus CO2 and COS, and assumes they are in equilibrium. As total carbon increases, CO2 increases, and so does COS since this is hydrolysis.

The CO equilibrium chart (see Figure 5) shows the concentration of CO in ppm (wet basis) in equilib-rium with a tail gas outlet composition; total carbon refers to CO plus CO2 and COS, and assumes they are in equilibrium. As total carbon increases, CO2 increases and so does CO because this is the

modynamic values for free energies and Gibbs energies of formation, entropies and heat capacities of the components. Higher temperatures are less favourable as Kp for (exothermic) reactions decreases. Table 2 provides Kp values for COS hydrolysis and sour shift and CO

temperature. The Kp is given by the Nernst equation (or Gibbs relationship): GT = -RT ln Kp

Published data, from JANAF, NIST and DIPPR, are used for ther-

6

10

9

8

7

5

4

3

2

1

CO

S w

et,

ppm

0200 220 240 260 280 300 320 340

Temperature, C

10% carbon20% carbon

5% carbon

Figure 4 COS equilibrium hydrolysis 34% H2O, 1% H

2S

750

1250

1000

500

250

CO

wet,

pp

m

0200 220 240 260 280 300 320 340

Temperature, C

10% carbon20% carbon20% carbon, 4% H2

5% carbon

Figure 5 CO Concentration at equilibrium water gas shift 34% H2O, 2% H

2

Component Feed 200C 250C 300C H

2 2.0000 1.7976 1.7937 1.7864

CO2 7.0000 8.0475 8.0425 8.0360

H2S 0.8000 1.2749 1.2748 1.2746

CO 1.0000 0.0024 0.0063 0.0132 COS 0.0250 0.0001 0.0002 0.0004 SO

2 0.4000 0.0000 0.0000 0.0000 LT ppb

CH3SH 0.0000 0.0000 0.0000 0.0000 Kinetically limited

CS2 0.0250 0.0000 0.0000 0.0000 LT ppb

CH4 0.0000 0.0000 0.0000 0.0000 Kinetically limited

H2O 26.0000 25.7275 25.7315 25.7386

N2 62.7500 63.1500 63.1510 63.1508

Equilibrium values, mole percent

Table 4


criterion.indd 7 10/06/2014 12:33


Fernando Maldonado is the Business Development Manager Gas Treating Catalysts for Criterion Catalysts and Technologies, located in Houston. He has global responsibility for Criterions gas treating catalyst business. Prior to joining Criterion Catalysts & Technologies in 2001, he held positions as a process design engineer, unit contact engineer, and an operations superintendent in two US Gulf Coast refineries. He holds a bachelor of science degree in chemical engineering from Texas A&M University. Email: [email protected]

Michael A Huffmaster is a process expert and consultant to industry for gas processing and treating, refining operation, CO

2 capture,

and related research. His activities regarding sulphur recovery include amine treating, Claus, tail gas treating, and tail gas treating catalyst development, design and operation. He retired from Shell Oil in 2005 with 36 years of experience. He holds a bachelor of science degree in chemical engineering from Georgia Institute of Technology and is a registered professional engineer in Texas. Email: [email protected]

water gas shift. As noted, hydrogen is held constant.

If the entire mixture is at equilib-rium, then COS would be the same as if for COS hydrolysis or sour shift. However, outlet mixtures are not at equilibrium because of space velocity (limited catalyst inven-tory). Typically, CO is two or three times equilibrium even with very high conversion because inlet concentrations are fairly high. This means that the sour shift, for instance, would express a higher COS equilibrium value than would the hydrolysis pathway. As the expression says, as goes CO, so goes COS. Figure 6 shows COS for various concentrations of CO.

Part twoThe second part of this article develops reactor modelling with a kinetic reaction model, the effects of temperature and space velocity, catalyst activation, catalyst deactivation, and determin-ing TGU catalyst health from a commercial unit temperature profile example.

30

50

60

40

20

10

CO

S w

et,

ppm

0200 220 240 260 280 300 320 340

Temperature, C

500 ppm CO1000 ppm CO2000 ppm CO

250 ppm CO

Figure 6 COS equilibrium sour gas shift 1% H2O, 2% H

2


dust obtained after the second and third filtration stages is sold to the paper industry, so the process delivers zero waste. The roaster and its filtration system are the subject of patents.

The hydrometallurgy processThe calcine that was produced during the roasting process is treated by hydrometallurgy in three steps: first calcine is leached to produce a slurry containing tung-sten and molybdenum, depending on the composition of the catalysts and their contaminants (which are mainly phosphorus and arsenic). In a step using decantation and filtra-tion, a solid concentrate containing alumina and silica, along with oxides of nickel, is produced. This material is reserved for the pyro-metallurgical process.

The soluble fraction of the slurry is purified to remove phosphorus and arsenic. These contaminants are not recycled and are disposed of as hazardous waste; they repre-sent less than 1% of the starting

material. Tungsten and molybde-num are present in the purified solution which is mixed with reagents to precipitate calcium tungstate or a mixture of calcium molybdate and tungstate. The yield of tungsten recovered in one shot is more than 85%. These metallic concentrates are calcined and sold to steelmakers, more particularly to companies looking for tungsten units, for example the EuroW company which produces tungsten carbide and cemented carbides, or Erasteel which produces steel and tungsten alloys. The hydrometallur-gical process is protected by a patent.

The pyrometallurgy processThe leaching residues are melted at a high tempe

ptq 2014 q3

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