Catalysis - Petroleum Technology Quarterly - 2014. Refining, Gas Processing and Petrochemicals

catalysis2014

ptq

cover and spine copy 8.indd 1 01/03/2014 07:23

ACHIEVE

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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 A hydrotreat for Russian refiners ChrisCunningham 5 ptq&a 17 HCN and NOx control strategies in the FCC XunhuaMo,BartDeGraaf,CharlesRadcliffeandPaulDiddams Johnson Matthey, Process Technologies, Intercat

JM Additives

27 Capturing maximum value with tight oil feeds in the FCC AlexisShackleford BASF Catalysts 37 Maximising distillate while minimising bottoms AllenHansen,AdrianHumphries,StephenMcGovern andBarrySperonello Rive Technology, Inc 43 Dewaxing challenging paraffinic feeds RenataSzynkarczuk Criterion Catalysts & Technologies MichelleRobinsonandLaurentHuve Shell Global Solutions International 53 Maximising distillate and alkylation feed from the FCC AlanKramerandGeorgeYaluris Albemarle Corporation 59 Optimising hydroprocessing catalyst systems WoodyShiflett,CharlesOlsenandDanTorchia Advanced Refining Technologies DavidBrossard Chevron Lummus Global

CatalyticReformerNo3atBPsKwinanarefinery,WesternAustralia. Photo: BP

2014www.eptq.com

Editor Ren G Gonzalez

[email protected]

Production EditorRachel Zamorski

[email protected]

Graphics EditorMohammed Samiuddin

[email protected]

Editorial PO Box 11283

Spring TX 77391, USAtel +1 281 374 8240fax +1 281 257 0582

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Advertising SalesBob Aldridge

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PublisherNic Allen

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CirculationJacki Watts

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Crambeth Allen Publishing LtdHopesay, Craven Arms SY7 8HD, UK

tel +44 870 90 600 20fax +44 870 90 600 40

ISSN 1362-363X

Petroleum Technology Quarterly (USPS 0014-781) is published quarterly plus annual Catalysis edition by Crambeth Allen Publishing Ltd and is distributed in the USA by SPP, 75 Aberdeen Rd, Emigsville, PA 17318. Periodicals postage paid at Emigsville PA.Postmaster: send address changes to Petroleum Technology Quarterly c/o POBox 437, Emigsville, PA 17318-0437Back numbers available from the Publisher

at $30 per copy inc postage.

espite signs in 2007 of a slowdown in various sectors of the economy, refi ners remain a big play for prospective investors. It used to be conventional wisdom that higher fuel prices and a slowing economy would curb demand and increase supply, but for the past seven years

that has not proved to be the case. While the rate of increase in world oil demand has declined since the surprising 4% surge in 2004, it nevertheless appears that demand beyond 2008 will grow, along with prices. It is a safe bet that rapidly increasing oil consumption by China, India and even the Middle East producers themselves will continue. It is also safe to assume that refi nery and petrochemical conversion unit capacity will need to expand.

No massive new sources of energy are expected to come on stream for the foreseeable future. The world will remain dependent on oil and gas for decades to come even though the upstream industry faces increasing challenges in the discovery and production of new sources. In fact, some well-placed industry analysts think 2008 may be the year where there is no increase in crude supply at all from regions outside of OPEC. For this reason, we will continue to see signifi cant investment in refi nery upgrades despite surging costs security of feedstock supply, albeit unconventional low-quality feedstock, takes precedence over the quality of feedstock supply.

Feedstock options such as biomass (for biofuels production), Canadian tar sands (for distillate production) and other types of unconventional crude sources require reactor technology that allows for the integration of these operations into existing process confi gurations. The quality of these types of feedstock are one important reason why a wider array of catalysts has been introduced into the market. For example, as refi ners cut deeper into the vacuum tower, the concentration of metals in the VGO requires a properly designed guard bed system to protect active catalysts in the hydrocracker. The characteristics of feedstock with low API gravity (eg,

As hydrocracking team lead at CRITERION, Herman Jongkind is responsible for generating ideas for new catalysts, as well as preparing, characterizing and testing them, making sure this information is transferred to the catalyst plants in a joined R&D/manufacturing effort. Among Hermans most recent and proudest achievements are Z-FX10 and Z-FX20, new generation catalysts that raise the yield of middle distillates above the traditional bar for hydrocrackers. Herman says success at CRITERION comes when fi nding that one little thing that makes a catalyst work better, thereby leading to a whole new generation of catalysts.

The beauty of catalysis is in the details one small discovery can lead to a whole new platform of catalysts.

Meet Herman Jongkind: Hydrocracking Catalyst Developer and Discoverer.

Leading minds. Advanced technologies.

www.CRITERIONCatalysts.com

criterion.indd 1 27/02/2014 14:16

Catalysis 2014 3

Editor Chris Cunningham [email protected]

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ISSN 1362-363X

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 2 2014

A hydrotreat for Russian refiners

Of all the worlds leaders, none knows better how to make a headline than Russias President Vladimir Putin. Back in 2011, for instance, the news was of street demonstrations in Russia demanding higher availability

and lower prices for fuel, amongst other basics. Putins response was to impose high duties on refinery product exports. You might say that this intervention was counter-intuitive in the usual context of refining developments, designed as it was to shore up production of heavy fuel oil, the staple of Russian winter heating, at the expense of diesel production. All of this did not stop even bigger street protests in Moscow later on, this time against election results, but at least demonstrators had the means to keep warm at home.

While other matters led the headlines for President Putin in the first quarter of 2014, fuel prices were back to make the second-page lead. The Kremlin said that it would raise the duty on fuel exports, not quite to the original promise of parity with fuel oil duty, but to significantly higher levels by 2016. The rise in duty is to be stepped to provide a reprieve for smaller, less-developed refin-eries that specialise in fuel oil production, to preserve their profits in the meantime. But the outlook for Russias refining majors is a boost for profits from their diesel output, effectively a shift in emphasis for their product slate from the bottom to the middle of the barrel.

Equally, more lucrative production of diesel gives the bigger refiners greater confidence in their capital expenditures on new plant. Russian refiners are among the biggest current spenders on new equipment and the rise in export duty should inspire the construction of more units to meet Euro IV and V specifications. That means more ULSD production and, in the context of an issue of Catalysis, major growth in an already important market for hydrotreat-ing catalysts. Two new hydrocrackers, each with more than 50 000 b/d capacity, were due for commissioning in Russia early in the current year and many more such refinery revamps are expected to follow, along with a supply of catalyst to feed them.

Of course someone has to pay for a boost in Russias ULSD production. Inevitably, the sector that will have to stump up is western Europes belea-guered refining industry. An increased flow of high quality diesel from the east will squeeze diesel price spreads and hence the already-limited margins of European refiners for whom diesel production is the mainstay of their vulnera-ble profitability.

There may also be a boost for the Russian refining industry from potential markets to the east. China has been talking of a significantly greater reliance on natural gas for its power production, in response to deadly levels of air pollution in the north east of the country, the outcome of an expansion in coal burning to match growth in the nations economy in recent years, along with growth in vehicle ownership. If pressure also mounts to burn cleaner automo-tive fuels sooner, and Chinas refiners cannot meet the new demand, no doubt their counterparts in Russia will be on hand to help out.

CHRIS CUNNINGHAM

Editor Ren G Gonzalez

[email protected]

Production EditorRachel Zamorski

[email protected]

Graphics EditorMohammed Samiuddin

[email protected]

Editorial PO Box 11283

Spring TX 77391, USAtel +1 281 374 8240fax +1 281 257 0582

Advertising Sales ManagerPaul Mason

[email protected]

Advertising SalesBob Aldridge

[email protected]

Advertising Sales Offi cetel +44 870 90 303 90fax +44 870 90 246 90

PublisherNic Allen

[email protected]

CirculationJacki Watts

[email protected]

Crambeth Allen Publishing LtdHopesay, Craven Arms SY7 8HD, UK

tel +44 870 90 600 20fax +44 870 90 600 40

ISSN 1362-363X

Petroleum Technology Quarterly (USPS 0014-781) is published quarterly plus annual Catalysis edition by Crambeth Allen Publishing Ltd and is distributed in the USA by SPP, 75 Aberdeen Rd, Emigsville, PA 17318. Periodicals postage paid at Emigsville PA.Postmaster: send address changes to Petroleum Technology Quarterly c/o POBox 437, Emigsville, PA 17318-0437Back numbers available from the Publisher

at $30 per copy inc postage.

espite signs in 2007 of a slowdown in various sectors of the economy, refi ners remain a big play for prospective investors. It used to be conventional wisdom that higher fuel prices and a slowing economy would curb demand and increase supply, but for the past seven years

that has not proved to be the case. While the rate of increase in world oil demand has declined since the surprising 4% surge in 2004, it nevertheless appears that demand beyond 2008 will grow, along with prices. It is a safe bet that rapidly increasing oil consumption by China, India and even the Middle East producers themselves will continue. It is also safe to assume that refi nery and petrochemical conversion unit capacity will need to expand.

No massive new sources of energy are expected to come on stream for the foreseeable future. The world will remain dependent on oil and gas for decades to come even though the upstream industry faces increasing challenges in the discovery and production of new sources. In fact, some well-placed industry analysts think 2008 may be the year where there is no increase in crude supply at all from regions outside of OPEC. For this reason, we will continue to see signifi cant investment in refi nery upgrades despite surging costs security of feedstock supply, albeit unconventional low-quality feedstock, takes precedence over the quality of feedstock supply.

Feedstock options such as biomass (for biofuels production), Canadian tar sands (for distillate production) and other types of unconventional crude sources require reactor technology that allows for the integration of these operations into existing process confi gurations. The quality of these types of feedstock are one important reason why a wider array of catalysts has been introduced into the market. For example, as refi ners cut deeper into the vacuum tower, the concentration of metals in the VGO requires a properly designed guard bed system to protect active catalysts in the hydrocracker. The characteristics of feedstock with low API gravity (eg,

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Q What catalytic options are available for chloride removal from liquid refinery streams?

A Olivier Ducreux, Adsorbents Business Line Manager, Axens, [email protected] solutions can be implemented for chloride removal from gas or liquid phase refinery streams depending on several factors including: Chloride species present Composition of the stream to be treated.

Axens developed some solutions to remove all trace of chlorides species to avoid corrosion or catalyst poisoning issues around the reformer, isomerisation, hydrockrack-ers or HDT units. AxTrap 800 series are highly efficient trapping adsorbents, designed for the removal of chlo-ride from liquids and gas streams (H2 net gas, stabiliser off-gas) to levels lower less than 0.1 ppm.

If only HCl is present in the feed stream, which is mostly the case in gas and light hydrocarbon streams such as LPG, a simple guard bed set-up is sufficient for chloride removal. Many adsorbent vendors propose HCl removal adsorbents, either based on promoted alumina or based on metal oxide technologies. Axens promoted alumina based adsorbents, named AxTrap 858, have demonstrated much better cost efficiency in the liquid phase, due to their better cost/performance ratio and much better mass transfer characteristics (and thus higher pickup capacities). HCl removal adsorbents can be implemented easily and efficiently regardless of the composition of the feed stream.

If organic chlorides are present in the feed stream and need to be removed, simple adsorption technology can be only partially efficient. Its efficiency is strongly dependent on the chloride species to be removed and on the composition of the feed stream: If the feed stream is only or mostly paraffinic an adsorbent guard bed implementing a multilayer adsor-bent mix (Axens Multibed technology), one for the removal of HCl and one for the removal of organic chlorides, can be implemented. This simple and straightforward solution is sufficient in most cases, especially but not limited to the gas phase. Axens has several industrial references for this application If the feed stream is highly olefinic or highly aromatic, competition between organic chlorides and some of the components of the feed stream can render simple adsorption technologies less efficient. In such (rare) cases catalytic technologies become necessary. A noble metal catalyst used for transformation of organic chlo-rides into HCl followed by a simple HCl guard bed adsorbent will be efficient even in the most difficult

cases. Axens has an adapted catalysts for this application.

A Axel Dueker, Product Manager Fuel Upgrading, Clariant BU Catalyst, [email protected] removal for HCl as well as organic chlorides is typically achieved by so-called Cl-guards. The removal mechanism of state-of-the-art Cl-guards is the chemical conversion of the chlorides with the guard material into chloride salts. Less sophisticated materi-als utilise physical adsorption to bind the chlorides but handling of such materials after use is difficult as uncontrolled emissions of adsorbed compounds may occur. Some of the available less sophisticated materi-als may also form increasing levels of organic chlorides during operation. Materials containing alumina and aluminosilicates should therefore be avoided. Due to the highly competitive environment in todays refining industry, many refineries across the globe have shifted their focus and now aim for the combined removal of HCl and organic chlorides.

Clariant offers a series of Cl-guards designed for the removal of HCl and organic chlorides from liquid and gaseous hydrocarbon streams at high pick-up capacities. The ActiSorb Cl products are based on an engineered combination of zinc oxide with a special binder to espe-cially enhance the removal of organic chlorides. A large number of refineries all over the world had identified the outstanding performance of Clariants Cl-guards.

A Claus Brostrm Nielsen, Product Manager, Haldor Topse, [email protected] is typically found in refinery streams due to continuous addition of chloride compounds in the catalytic naphtha reformers or isomerisation units. The chloride present as organic chloride in liquid refinery streams can be converted into HCl by a hydrotreating catalyst. HCl is then trapped downstream the hydro-treating unit by a chloride guard, where HCl is absorbed on alumina containing alkali metals. Chloride present in refinery streams as HCl does not need any catalytic treatment, but can directly be absorbed by the chloride guard.

For chloride absorbing, Topse offers several products like HTG-1 and HTG-2 which are specifically developed for maximum chloride uptake from refinery streams.

Q Are there economic advantages in trading spent catalyst for precious metals recovery over sending it for landfill/cement production?

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catalysis q&a

Additional Q&A can be found at www.eptq.com/QandA

Q&A copy 12.indd 1 28/02/2014 11:11

A Sam Bowles, PGM Refining Sales Executive, Refining and Chemicals Europe Johnson Matthey Process Technologies, [email protected] group metal (PGM) bearing catalysts are typically employed on substrates (carriers) such as soluble and insoluble alumina, silica alumina, zeolite, or carbon support. They have many roles in many different industries. In the petroleum industry they can provide a significant role in reforming and isomerisa-tion, however the costs of the PGM loadings on the catalysts can be huge. Unfortunately the harsh envi-ronments which contaminate the catalysts mean that over time they lose their efficiency and thus no longer perform effectively and are considered spent. It is at this stage where new PGM catalysts must be used and you are left with the choice of what to do with the spent catalyst.

As the precious metal used in catalysts is an expen-sive and scarce resource, their recovery, recycling and re-use is essential to maintain long term global sustain-ability. In addition, the economics of any process that utilises precious metals is key to profit and growth. Precious metals such as platinum, palladium and rhodium constitute a significant investment, so an important factor in the economics of these processes is the ability to recover the precious metal content from the catalyst once it is spent. A quick and efficient retrieval of the metals is of utmost importance. By trading the spent catalyst for precious metals refining you have the ability to recover the precious metal content from the catalysts. If the PGM catalysts have a greater value of precious metal contained, compared to the costs of refining and recovering it, then there is a clear economic advantage in refining the spent cata-lysts. If you then consider the sheer magnitude of PGM bearing catalysts used by businesses in the process technology industry, it means that there can be millions of dollar worth of precious metal available that can be recovered.

Trading spent catalyst for precious metal recovery also facilitates closed loop refining as the precious metal content recovered in these spent catalysts can be used to manufacture future orders allowing for better metal management, which can be important especially with fluctuating metal prices (see Figure 1).

Sending the spent catalyst for refining also elimi-nates the costs of disposing in landfill and can help mitigate the environmental issues associated with disposing of spent catalyst in a landfill or disposal site, especially for those that are considered as hazardous waste. Any company that exports controlled waste has a duty to take all reasonable steps to ensure that their waste is handled lawfully and safely. By sending the spent catalysts to a well-established, highly specialist refiner they have the expertise and licences to ensure that wastes are treated correctly through responsible operations and are in compliance with any applicable international, environmental and legal regulations. All of this is achieved without forfeiting the value of the precious metal content.

Further information on the refining of spent catalyst can be found by visiting www.jmrefining.com .

A Claus Brostrm Nielsen, Product Manager, Haldor Topse, [email protected] catalysts containing precious metals can be handled by specialist companies that can recover most of the precious metals. The recovery of the metals is typically so high that there is a large economic advan-tage in sending the spent catalyst for metal recovery rather than using the spent catalyst for landfill/cement production. Due to the high prices of precious metals, even catalysts containing small amount of metals are worth sending for metal recovery.

A Steve Metro, Senior Business Leader Naphtha Products, UOP Catalysts, Adsorbents, and Specialties, [email protected] catalysts that contain precious metals such as UOP Platforming catalysts are never sent to direct land fill due to the Pt content and monetary value. They are sent to reputable precious metals recovery firms such as Gemini Industries, Sabin Metal Corporation or Heraeus Precious Metals, where they can efficiently recover Pt, Re, Ir, and Pd from solid alumina substrates.

Q We are not getting the cycle life we were expecting from our hydrotreating catalyst after presulphiding. How should we be adjusting process conditions after presulphiding?

A Ken Koziol, Hydrotreating Global Sales Support Manager Catalyst, Adsorbents, & Specialties, UOP, [email protected] question is complicated based on the use of the term presulphiding as it is either referring to prob-lems with a hydrotreating catalyst that has been presulphided prior to being loaded into the reactor or it is referring to performance issues with the hydro-treating catalyst after it has been in-situ sulphided with a sulphiding agent such as DMDS during the unit start-up. With regards to any hydrotreating catalyst and its performance after start-up, one key item that is critical to maintain the optimum catalyst activity is to maintain the feed free of cracked stocks for 72 hours

6 Catalysis 2014 www.eptq.com

1600

19001887

1526

1039

1800

1700

1500

1400

1300

1200

1100

10002010 2011 2012 2013 2014

Figure 1 PM Pt fix in US dollars over the last five years Source:LPPM.com

Q&A copy 12.indd 2 28/02/2014 11:11

www.jmprotech.com

UK Tel +44 (0)1642 553601 Fax +44 (0)1642 522542

Johnson Matthey is a global supplier of market leading hydrogen plant catalysts, FCC additives, technologies and services for the oil refi ning industry.

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after sulphiding unless the catalyst has been pre-acti-vated with cracked feed protection. During these first three days after catalyst activation, the hydrotreating catalyst is in a state of hyperactivity and thus the introduction of cracked stocks can create aggressive coking on the catalyst, thus diminishing the activity of the catalyst for the rest of the cycle. After sulphiding, it is important to bring the respective catalyst operating temperatures up or down from the final sulphiding hold temperature as necessary to meet the target prod-uct specs and no higher. It is also important to make sure the recycle gas scrubber is immediately put in service after sulphiding to remove the excess hydrogen sulphide as increased levels of hydrogen sulphide will require a higher temperature to meet the same product specifications.

With regards to other issues that could occur during sulphiding that can impact the catalyst performance, it is critical to make sure that the temperatures of the sulphiding steps and the necessary hydrogen sulphide breakthroughs are reached and maintained as detailed by the catalyst manufacturer as these steps are critical to reach the optimum catalyst activity for the cycle. It is also imperative to understand the hydrotreating reactor temperature limitations during start-up as there have been cases where units have been designed with integrated heat exchange based on normal opera-tion but during start-up this heat is not available to fully activate the catalyst, such as in a diolefins reactor, where it may be of value to have this catalyst pre-acti-vated to maintain the necessary activity. Another key item during the sulphiding process is to make sure that the feed rate used during the sulphiding is greater than 70% of design to make sure that the full catalyst is being fully contacted and sulphided.

If this question is referring to issues with presul-phided catalyst performance then the key items to review with your catalyst supplier and the presulphid-ing service supplier are the sulphur level of the presulphided catalyst, the metals content of the cata-lyst provided, and finally verifying that the method of presulphiding is appropriate for the respective Type I or Type II catalyst that had been chosen. Issues in any of these areas can impact hydrotreating performance.

A Claus Brostrm Nielsen, Product Manager, Haldor Topse, [email protected] cycle life of a hydrotreating catalyst depends on many factors, such as feed properties, product require-ments and operating conditions. If the cycle life is not reached with the design parameters, one of these factors must be relaxed. This could be processing an easier feedstock, like lower sulphur and nitrogen content, lower end boiling point or density or less metal content. If the feedstock properties cannot be changed, the product requirements could be relaxed, like higher product sulphur and nitrogen. The last option is to change the operating conditions to more favourable conditions, like reduced feed rate, higher hydrogen partial pressure, higher hydrogen oil ratio or increased treat gas purity. Any change in these factors

will have a positive effect on the cycle life of the hydrotreating catalyst.

A Brian Watkins, Brian Slemp, Greg Rosinski, Carrie Constantine, Meredith Lansdown, Advanced Refining Technologies Technical ServiceThere are several likely reasons for not achieving the expected cycle life from a catalyst loading. First, it is important to understand the difference between the types of ex-situ catalyst sulphiding in order to ensure that you are gaining the most activity from the ex-situ sulphided catalyst. Once optimum catalyst activity is ensured, you can then examine the process conditions after the completion of the activation to help to main-tain the proper cycle life.

Presulphided catalystThis type of catalyst has had the stoichiometric amount of sulphur, plus some excess, added to the catalyst surface so that it is ready to be activated once in the reactor under the proper conditions. This type of start-up requires that the H2S that is generated by the decomposition of the sulphur compound present on the catalyst is recirculated and allowed to activate the catalyst once the catalyst bed temperatures are high enough. Use of liquid during this start-up can help with controlling the heat of reaction produced when the sulphur chemical begins to react. This type of acti-vation can create a very high delta temperature in the reactor if not monitored closely. If this type of activa-tion is used, and there is an upset during start-up, it is possible to lose some of the required H2S and can end up with a catalyst system that may be significantly less than 100% activated. Use of virgin feedstock during this start-up process will help to mitigate this issue due to availability of extra sulphur in the feed as well as provide additional heat control from the extra mass in the reactor.

Presulphided/activated catalyst This type of ex-situ sulphiding has actually had the metal sites on the catalyst converted from the oxide state to the sulphided state. This process, where the sites are already converted to the active phase is easier to start up since there is less heat generated which results in a lower chance of a thermal runaway. The conversion of the oxide metal sites to sulphide sites in the ex-situ process also helps to ensure that as much of the catalyst activity as possible is maintained for the process. This type of ex-situ sulphiding can also be passivated for ease of handling during loading, or it may require special handling during loading in order to avoid contact with oxygen.

Once the system is sulphided the initial catalyst activity is extremely high. The extremely high activity will generate higher than average temperatures on the catalyst surface. The increased surface temperature can cause incremental coking and excessive deactivation of the catalyst active sites. The hydrotreating system will not achieve its ultimate run life potential from the excessive initial coking deactivation if feedstocks

Q&A copy 12.indd 3 28/02/2014 11:11

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containing large amounts of coke precursors are processed immediately after start-up. To minimise this, ART recommends using virgin feedstock (low olefin and low aromatic content) with a lower end point that has lower coking potential for the first 72 hours after catalyst activation. The use of the lower reactivity virgin feed helps moderate the catalyst surface temperature and control coke distribution to minimise the negative impact on activity to allow a longer over-all operating cycle.

Another issue to address that can affect any catalyst cycle is poisons. It is recommended to monitor the spent catalyst for poisons. If the catalyst that is removed contains a higher than expected quantity of poisons, then it is time to explore the use of specialty guard catalysts in order to protect the main bed hydro-treating catalyst.

Q Is there a catalyst option for upgrading LCO to ULSD without an additional process step?

A Antoine Fournier, Business Line Group Manager, Catalyst Technology Department, Axens and Jacinthe Frcon, Technology Group Manager, Middle Distillates & Conversion Business Line, Axens, [email protected] already has experience with pure LCO feed-stock hydroprocessing. When, most of the time, producing ultra low sulphur diesel can be achieved with a conventional catalyst in a single stage process, the main constraint with LCO hydroprocessing is to meet other characteristics associated to Euro V produc-tion, and in particular the cetane and/or the density specifications.

In that case, several approaches could be envisioned: Using a two-stage approach with the implementation of a noble metal catalyst section in order to complete the aromatic saturation required for cetane improve-ment and density reduction while maximising the diesel yield (minimum cracking) Using a combination of pretreatment and cracking catalysts in a single stage process in order to reduce the density and improve the cetane thanks to naph-thenic ring opening. This solution can bring a higher density and cetane boost compared to the two-stage approach (pure hydrogenation option) but results in a lower diesel yield.

A Claus Brostrm Nielsen, Product Manager, Haldor Topse, [email protected] of LCO feedstock to ULSD is possible with a catalytic treatment in a typical hydrotreating unit. Depending on the properties of the LCO, a hydrotreat-ing catalyst can make the upgrade to ULSD; however, in some cases, a hydrocracking catalyst is needed. If the LCO is high in density, maximum aromatics satu-ration is needed in order to reach the density and cetane number specifications for ULSD. This is obtained by using a NiMo hydrotreating catalyst at high pressure. However, if the LCO is high in density, and the density specifications cannot be reached by

sulphur removal and aromatics saturation, it is recom-mended to use a hydrocracking catalyst in the lower beds to reach the density specifications for ULSD. Topse has several references on the use of hydroc-racking catalyst for this application and has recently also introduced the NiMo catalyst TK-609 HyBRIM which has an exceptionally high hydrogenation activ-ity, making it the optimum choice for LCO upgrading.

A Anubhav Kapil, Lead Technical Sales Specialist CA&S Refining Hydroprocessing, UOP, [email protected] cycle oil (LCO) is a by-product of catalytic crack-ing and is normally high in sulphur, nitrogen and aromatic content. LCO material typically is in the same boiling range as diesel, but as it is rich in multi-ring aromatics, it produces fuel with very low cetane number (typically 1525). Because of the high sulphur and low cetane number, LCO makes a poor diesel fuel blending stock.

Ultra low sulphur diesel (ULSD) specification can vary slightly from country to country, but generally it means diesel fuel with substantially lowered sulphur (less than 10 or 15 wtppm). If sulphur speciation of a LCO feedstock is conducted, we will find that a signifi-cant portion of the sulphur is found in alkyldibenzothiophenes (DBT). In order to achieve the ultra low sulphur, most of these difficult refractory compounds in the feed have to be converted; this makes the upgrade of LCO to ULSD complex. Depending on whether one is trying to make just ULSD or also trying to produce high quality diesel product with low aromatics, careful consideration has to be given not only to feed quality but also to the product objectives.

UOP has made significant advancement in the field of upgrading LCO to ULSD by developing state-of-the art catalysts as well as processes optimised for LCO upgrading. The main technologies available for LCO upgrading are the Unionfining process and the Unicracking process. UOP offers the Unionfining process with both base metal as well as noble metal catalysts. The choice of which process and catalyst to use depends on the desired improvement in cetane index and on existing limitation at the refinery. The one limitation of base metal Unionfining is that it requires a high severity operation and provides only a modest improvement in cetane number. A partial conversion Unicracking unit with moderate distillate selectivity catalyst is generally the best option when trying to achieve ULSD with good cetane number improvement. The hydrocracking catalyst helps convert the complex DBT and significantly benefits cetane by cracking the most difficult to hydrogenate aromatic compounds to naphtha.

A Brian Watkins, Brian Slemp, Greg Rosinski, Carrie Constantine, Meredith Lansdown, Advanced Refining Technologies Technical ServiceThere are several basic impacts that need to be under-stood when considering upgrading any particular

Q&A copy 12.indd 4 28/02/2014 11:11

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arounds. This may mean that processing additional LCO, or processing it completely in a single hydro-treater, may require the use of a system with higher pressure and additional hydrogen in order to utilise a more powerful NiMo catalyst designed for aromatic saturation and removal of the additional hard sulphur compounds.

In general, cracked stocks (cokers and LCOs) are more challenging to hydrotreat and require a higher weighted average bed temperature (WABT) compared to a straight run (SR) material at the same product targets. Feeds from the fluid catalytic cracker (FCC) are much higher in aromatics than their SR counter parts and are especially concentrated in poly aromatics. This also gives these feeds a much lower API gravity rela-tive to SR or coker stocks. The concentration of sulphur and nitrogen in these feeds are dependent on the presence of a pretreater upstream of the FCC which can help in lowering the total sulphur or nitro-gen content. However, the sulphur and nitrogen compounds in FCC are usually the more difficult refractory species requiring a much higher required WABT to achieve the same product specification (see Figure 2).

If your distillate hydrotreater has incremental hydro-gen available and operates at high enough pressure, LCO can be processed, but will likely require the switch to an all NiMo catalyst system. LCO normally contains the highest amount of aromatics and therefore will provide the maximum volumetric expansion from hydrotreating. LCO will also undergo the largest increase in cetane across the hydrotreater as shown in Figure 3.

As always, ART is prepared to discuss these options and assist in making the best choice with the catalyst system already in use, and also to help prepare for the next catalyst load in order to take advantage of this process change.

Q We are experiencing excessive pressure drop during hydrotreating as a result of iron scale build-up in the catalyst bed. Is the problem best addressed in the desalter or is this more likely to be carry-through of plant corrosion problems?

A Brian Watkins, Brian Slemp, Greg Rosinski, Carrie Constantine, Meredith Lansdown, Advanced Refining Technologies Technical ServiceIron works its way into hydrotreater feed as rust and iron scale from corrosion of upstream equipment and piping as well as unfiltered particulates present in the feed. Iron naphthenates can form from piping corro-sion due to naphthenic acid in the feed, and the iron readily precipitates out in the presence of heat and H2S. Characterisation of the iron to help identify the source is important to understand and develop the best methodology to mitigate its effects on the hydro-treater. Iron scale materials are due primarily from corrosion of piping and equipment en route to the hydrotreater. This is a solid type of iron that, if allowed to bypass the feed filters or there are no filters present,

stream in a refinery, especially LCO. With increases in the final boiling point of the feed, the total sulphur and nitrogen, the concentration of hard sulphur, and aromatics content all increase. This is independent of the source of feedstock (see Figure 1). In order to main-tain the same product specifications, this will need to be compensated for by increasing the reactor tempera-ture. Examining your available hydrotreaters and their processing capabilities as well as the availability for an increased demand for hydrogen in one area or another in the refinery is important to avoid unexpected turn-


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Figure 1 Fraction of hard sulphur depends on endpoint

Figure 2 Impact of FCC LCO on ULSD hydrotreater

Figure 3 Impact of FCC LCO on ULSD cetane index

Q&A copy 12.indd 5 28/02/2014 11:11


form the crust layer in the hydrotreater and require special grading materials to help minimise this prob-lem. Ef cient and effective use of the desalter is always recommended to avoid bringing in additional iron sources that can overwhelm the catalyst grading system.

These iron particulates ll the interstitial spaces in the catalyst bed which will result in a higher than expected pressure drop. To help mitigate the pressure drop associated with iron, ART uses a series of grading materials which have high void space to accumulate and store these particulates. Use of a specialised iron trapping material (GSK-10) which has high internal void space for trapping iron inside its large pore network is also valuable (see Figure 1).

If iron is known to be the cause of the pressure drop issues, then larger diameter catalysts can also be used in an effort to allow for additional void space in the reactor. Sock loading a large portion of the top of the reactor will also greatly increase the effective void space, allowing the smaller iron particles to move through the reactor.

Other options are to utilise materials that are specially designed to increase the void fraction in the top bed of the reactor and are ef cient at trapping iron, other particulates and scale. These measures are help-ful for delaying pressure drop build-up, but they do not prevent eventual pressure drop build-up. Effective feed ltration to remove particulates (at least 25 microns) provides a longer lasting solution in helping mitigate pressure drop build-up from these sources, as well as a way to identify the sources of iron that are present in the process.

If the amount of iron that is making it into the hydrotreater requires too large a volume of grading materials at the top of the hydrotreater, such that it is impacting the desired cycle length, then the remaining option is to remove it from the feed altogether. As feed rates and qualities vary signi cantly day after day, upstream prevention combined with guard bed technology can extend the cycle length of the hydrotreater.

It has also been found that some of the synthetic crudes may also contain very ne particulates of clay or sand that are associated with asphaltenes or other heavy polycyclic molecules. These particulates can be removed through proper use of the desalter to avoid crude tower fouling. However, these small particulates, typically

A Claus Brostrm Nielsen, Product Manager, Haldor Topse, [email protected] choice of catalyst for a hydrotreating unit depends on the feedstock, product requirements and operating conditions. Generally, at low pressure, a CoMo type catalyst is the optimal choice for HDS, and at high pressure, a NiMo type catalyst is the optimal choice for both HDS and HDN. When a NiMo catalyst is applied at low pressure in order to increase HDN then the HDS conversion would be lower, and this would often be the case also if a stacked bed CoMo/NiMo catalyst was applied. Therefore, in most cases, a single type catalyst system is the optimal solution. Topse offers catalyst products for all ranges of pressure and all types of feeds such as the high activity CoMo catalyst TK-578 BRIM and the high activity NiMo catalyst TK-609 HyBRIM.

A Brian Watkins, Brian Slemp, Greg Rosinski, Carrie Constantine, Meredith Lansdown, Advanced Refining Technologies Technical ServiceOne of the keys to successful ULSD production is a detailed understanding of the chemistry involved. It has been known for some time that there are two reac-tion pathways to remove sulphur from dibenzothiophene and substituted dibenzothiophenes. The first pathway is the direct abstraction route, which involves adsorption of the molecule on the catalyst surface via the S atom followed by C-S bond scission. C-H bonds using chemisorbed hydrogen then replace the C-S bonds. This is the primary pathway over cobalt-molybdenum (CoMo) based hydrotreating cata-lysts. The rate determining step is the C-S bond scission and not C-H bond formation, which explains the low H2 partial pressure dependency of desulphuri-sation over CoMo catalysts. The second pathway, the hydrogenation route, involves saturation of one aromatic ring followed by the extraction of the S atom. Nickel-molybdenum (NiMo) catalysts, which exhibit a higher hydrogenation activity than CoMo catalysts, have a higher selectivity for desulphurisation via this route.

To reduce sulphur to


so-called easy sulphurs, are more effectively desulphu-rised via a direct sulphur abstraction route, and these reactions are best catalysed by a CoMo containing cata-lyst. Substituted DBTs, or hard sulphur, are more effectively removed by hydrogenation of an aromatic ring followed by C-S bond scission. This type of reac-tion is more efficient over a NiMo containing catalyst.

The SmART system can therefore give better perfor-mance than either CoMo or NiMo alone. The significant advantage of the system is not only due to the staged catalyst configuration but also to unique catalyst formulations. The systems NiMo catalyst was developed to promote the hydrogenation route for HDS with partially desulphurised feed at a moderate H2 partial pressure.

An additional benefit of the NiMo component is the enhanced HDN activity over an all CoMo system will help to improve both product colour and colour stability.

Detailed work in ART laboratories has elucidated the

mechanism of the staged system. Figure 1 shows that the system removes easy sulphur as well as a CoMo catalyst, removes hard sulphur as well as a NiMo cata-lyst, and removes the transition species better than either a CoMo or NiMo catalyst.

Another important advantage of the SmART system concept is the efficient use of H2. Figure 2 illustrates how the SmART system can be tailored to provide the best balance of maximum HDS activity while minimis-ing H2 consumption.

The SmART system design is the culmination of an extensive effort put towards understanding the chem-istry and process conditions required for ultra low sulphur fuels. ART has devoted significant resources to designing the best ULSD catalysts for use in the system. This effort has lead to the recent commerciali-sation of ARTs new CoMo catalyst 425DX, and the new NiMo catalyst, 545DX. These new technologies capitalise on the extensive material science and catalyst knowledge encompassed in the ART joint venture.

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HCN and NOx control strategies in the FCC

Increasing environmental aware-ness at a global level is driving enforcement of more stringent

regulations to limit emissions of sulphur and nitrogen containing gases to the atmosphere.

NOx (mixed nitrogen oxides) and SOx (mixed sulphur oxides) emis-sions have been under scrutiny for some time now, especially in North America and Europe. More recently, however, hydrogen cyanide (HCN) emissions (present in FCC flue gas at levels up to about 150ppm) have come under scrutiny in the US and some parts of Europe. Controlling flue gas emissions of this new species is an emerging challenge for refiners operating FCC units.

The origin of HCN in FCC flue gas has been poorly understood and public domain information very limited. In this article we explain our recent research on nitrogen chemistry as it relates to the FCC regenerator, covering the origin of HCN and its relationship with other nitrogen containing gases. We also explain how modern FCC unit designs geared for low NOx emis-sions may unintentionally have been trading these off against HCN and ammonia emissions. Continuing development of catalytic additives for FCC regenerator flue gas emis-sions control will help refiners to meet the emerging regulatory emis-sion limits. We explain how to use a combination of operating variables, additives and regenerator design to reduce emissions.

FCC NOx and SOx emissionsThe FCC unit is a major conversion unit present in many refineries throughout the world. FCC units are

Results of research into emissions from the FCC, plus guidance on how toobtain the minimum level of NOx

XUNHUA MO, BART DE GRAAF, CHARLES RADCLIFFE and PAUL DIDDAMSJohnson Matthey, Process Technologies, Intercat

JM Additives

highly flexible and able to upgrade feeds comprising many components ranging from light-sweet hydro-treated VGO to heavy-sour residues, and may include additional heavy streams from other refinery units, such as coker gas oils. Because of the resilience of the process and catalyst system, the majority of FCC feedstocks contain many contami-nants including metals (Ni, V, Cu, Fe, Ca, Na, K) and heteroatoms (sulphur, S and nitrogen, N).

The FCC converts low value, high molecular weight (high boiling point) hydrocarbon feeds to lighter, more valuable products via cleavage of C-C bonds (cracking). Typically, 5-6wt% of the feed is converted to coke as a byproduct of cracking. This is burned in the FCC regenerator where the heat of combustion is used to provide the energy required to vaporise and crack the feed (hence, the FCC unit is said to be in heat balance).

Metals accumulate on the catalyst where they deactivate/poison the catalyst or cause undesired side reactions such as dehydrogenation and additional coke and gas forma-

tion. Some contaminants in the feed are transferred to the regenerator in the coke. In this way, a portion of the sulphur and nitrogen in the feed is combusted in the regenerator.

The products of combustion of sulphur and nitrogen in the FCC regenerator include the gases SO2, SO3, COS, H2S, N2, NO, N2O, NO2, NH3 and HCN, all which may contribute to stack emissions at vari-ous concentrations in the FCC flue gas. The exact composition of these gases in the flue gas depends upon the detailed reaction conditions. A simplified reaction pathway for nitrogen compounds is shown in Figure 1.

In full burn FCC units (where coke is combusted in an excess of oxygen) the main species formed are the most highly oxidised species: SO2, SO3, N2 and NO. However, in partial burn FCC units (where the coke is combusted under sub-stoi-chiometric oxygen conditions) much higher levels of the reduced S and N species (COS, H2S, NH3, HCN) are present in the flue gas as it leaves the regenerator. In partial burn units a controlled amount of the carbon in the coke burned is


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Figure 1 Regenerator nitrogen reactions

cat intercat.indd 1 28/02/2014 11:23


Investigation of coke combustionIntercatJM used temperature programmed oxidation (TPO) to study coke combustion, to better understand FCC regenerator chem-istry. The TPO protocol involves pre-heating a sample of coked cata-lyst (spent catalyst) in an inert atmosphere up to a chosen initial temperature (for example, 150C), then switching to the combustion gas containing oxygen. (In more detailed studies, additional selected gases may also be included, for instance CO2, CO, SO2, steam.). The temperature is then ramped (for instance at 10C/min) to 730C then held there isothermally. The result-ing combustion flue gases are continuously analysed by an on-line infrared detector and mass spec-trometer. It is worth noting that the nature of the coked catalysts has significant effect on the emission profiles during TPO. The emission profiles are dependent on the types of nitrogen species formed. These depend on the nature of the nitro-gen species in the feed, CCR, contaminant metals, conversion and stripping of the catalyst. The lab TPO data shown in this article were obtained using a spent catalyst taken from a commercial FCC unit (containing 1 wt% carbon, 0.1 wt% sulphur and 395 ppm nitrogen), and from a synthetic spent catalyst prepared using a metals-free FCC catalyst.

The first nitrogen containing species evolved (at the lowest temperature in the TPO) is HCN (see Figure 2). HCN production is observed at low temperatures, beginning at about 450C (780F). At this low temperature the rate of conversion of HCN to the thermo-dynamically more stable NO or N2 forms is slow, so the HCN survives to be observed. NO does not begin to be formed until the temperature exceeds about 570C (1060F). After this point, as the temperature is increased the HCN concentration declines while NO increases; HCN conversion is fast enough that further HCN formed is readily converted into NO or nitrogen. Despite being thermodynamically unstable at this temperature N2O is also observed at temperatures

combusted to CO rather than CO2 in order to decrease the heat produced in the regenerator via coke combus-tion. This allows the processing of heavier, higher coke making feeds within regenerator temperature constraints. Most partial burn units have a CO boiler downstream of the regenerator in which CO is converted to CO2 to control CO emissions and recover additional heat of combustion for steam production. The CO boiler also converts reduced S and N species to more highly oxidised forms, so the result in both full burn and partial burn with a CO boiler is that the flue gas contaminants reaching the stack are predominantly SOx (SO2, SO3) and NOx (NO, N2O, NO2). Other species are generally only present at much lower concentra-tions. Note that a partial burn unit without a CO boiler will emit substantial levels of the CO and reduced S and N gaseous species and there are actually still a number of such FCC units being operated in this way.

Nitrogen chemistry in the FCC regeneratorFCC feedstocks contain many differ-ent nitrogen compounds, generally measured as total and basic nitro-gen. Normally, 30-50% of the feed nitrogen compounds are basic nitro-gen species that strongly adsorb on acid sites on the catalyst. This tightly bound nitrogen is not removed in the stripper and therefore carried with the catalyst into the regenera-tor where it is combusted as part of the coke together with the carbon, hydrogen and sulphur. As a rule of thumb, about half of the feed total nitrogen is combusted in the FCC regenerator. See Table 1 for a typical FCC nitrogen balance.

Coke composition primarily depends on feed properties and stripper efficiency. Coke is comprised of carbon-rich polycyclic aromatic structures containing heteroatoms and contaminant metals as well as unstripped hydro-carbon products (10-30% of coke can be gasoline, diesel and fuel oil range products that are not stripped from the pores of the catalyst). Typically, coke has a hydrogen content of 5-8

wt%, largely present in the unstripped products. The concentra-tion of nitrogen in coke is an order of magnitude higher than in the feed (about 50% of feed nitrogen goes to coke compared to about 5% of feed carbon).

Combustion of carbonaceous coke and unstripped hydrocarbons in the regenerator forms CO2, CO and H2O. Sulphur in coke forms SO2, SO3, COS and H2S, but nitrogen in coke behaves very differently. When oxygen reacts with carbon-rich coke, much of the nitrogen is initially converted to HCN; the same chem-istry is observed in coal combustion. At typical steady-state FCC regener-ator bed temperatures (680-755C, 1255-1390F), HCN is thermody-namically unstable and, given sufficient time, all of the HCN would be converted. Nitrogen followed by NO are the most ther-modynamically stable nitrogen species under FCC regenerator conditions, with the thermodynamic equilibrium concentration of NO being about 10 ppm in nitrogen. However, the much higher levels of HCN found in commercial FCC unit flue gases clearly illustrates that nitrogen reactions are kinetically controlled and do not reach thermo-dynamic equilibrium. HCN present as a reactive intermediate can be hydrolysed by steam in the regener-ator to form NH3. Both HCN and NH3 can be readily oxidised to form N2 or NO, depending on regenera-tor conditions and the presence of combustion promoters which catalyse these reactions. Previously, the reaction of CO + NO was thought to be one of the main driv-ing forces for reducing NO. Our work shows this reaction to play a very minor role under FCC conditions.

Product Nitrogen, wt%FFFuel gas NH

3/HCN 5-15

Gasoline 1-5LCO/diesel 10-20HCO/bottoms 25-35Coke 35-60

Typical nitrogen balance: wt% feed nitrogen to FCC products

Table 1


around 650C, indicating that N2O may also either be a reactive inter-mediate in the formation of NO or a byproduct of the reduction of NO.

When higher oxygen levels are used in the combustion gas (for example, 4 vol%) both the rate of HCN formation and its subsequent conversion is increased notably: the first traces of NO in flue gas appear at a lower temperature, ~550C (1020F).

These experiments show that HCN is most readily formed at low temperatures, especially where oxygen concentrations are high, while at higher temperatures HCN becomes unstable and is readily converted to NOx and nitrogen.

HCN formation and survival is favoured at low temperatures. The zones within the FCC regenerator where these conditions occur are the entry point for the cooler spent cata-lyst (at about 500-550C, close to the HCN maxima in the TPO experi-ments) and the cold air at about 190C. As spent catalyst and air mix with the hot catalyst in the bed their temperatures increase and HCN formation declines and is replaced by combustion of nitrogen in coke to NOx or N2. Some of the HCN that was initially formed in the cooler zones heats up in the regen-erator (especially when passing up through the bubbling catalyst bed) and is converted to NOx or N2. Any HCN surviving at the flue gas exit did not have sufficient contact time at elevated temperatures to be converted.

This explains why HCN emissions are highly dependent on regenerator spent catalyst and air distributor design (see Figure 3).

If spent catalyst is deposited on the top of a poorly mixed catalyst bed, where it takes more time to heat up, it spends longer under conditions ideal for HCN formation and survival, resulting in higher HCN levels in the flue gas.

If the spent catalyst enters the lower part of a well mixed regenera-tor catalyst bed, but far enough above the air injection for it to have already been heated to above ~650C, it will more rapidly heat up. The time available for HCN forma-tion is therefore minimised, and any


HCN formed has better contact with the hot catalyst bed where it is more likely to be converted. Large bubbles can offer HCN an escape route; air distribution should be optimised to avoid large bubbles that spout gas and catalyst into the dilute phase. Note that conditions exist where HCN in flue gas can be also reduced by hydrolysis (reaction with steam).

Hydrolysis is an alternative, low temperature destruction path where HCN is converted to ammonia (NH3), which may go on to be oxidised to NO. The relative amounts of HCN and NH3 breaking through will depend on many varia-bles, such as metals on catalyst, type of nitrogen in feed, and regenerator design.

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Scenario 1Spent catalyst return on top of the regenerator fluid bed

High amounts of non-oxidised N-species (HCN, NH3) can be emitted

High temperatureLow oxygen concentrationMinimum back mixing of gas phaseLow residence time of combustion gases

Scenario 2Spent catalyst return just above the air grid

Rapid coke combustion at low temperature

Lowest possible regenerator temperature Spent catalyst 530C (980F) Air 200C (400F)Highest oxygen concentration

Highest amounts of HCN formedWhere bubbles will break through the bed substantial HCN emission is possible

Scenario 3Spent catalyst return in the middle of the bed

Moderate coke combustion limits the emission of non-oxidised N-species

Moderate/high temperatureLow/moderate oxygen concentration

High amount of back-mixing helps conversion of HCN and NH3 into N2 and NOLowest HCN emission expected

Figure 3 Effects of regenerator layout



Another important item to consider is that mixing effects play a major role in combustion kinetics. Introduction of spent catalyst into the centre of the bed without proper radial mixing can be much worse for emitting reduced nitrogen species in ue gas compared with spreading spent cata-lyst onto the top of a bubbling bed.4

The effect of CO promoters on HCNAppropriate catalytic additives can increase the rate of conversion of HCN in the FCC regenerator. Both platinum (Pt), and non-Pt promoters ef ciently increase the rate of HCN conversion, leading to lower concen-tration in the ue gas.

The results of TPO experiments shown in Figure 4 and Figure 5 compare spent catalyst combustion with and without the addition of various CO promoters.

The highest levels of HCN are formed in the absence of CO promoter. Adding either Pt or non-Pt CO promoters decreases the amount of HCN and NH3 observed by catalysing their conversion to more oxidised forms. However, Pt based promoters increase the NO signi cantly, while non-Pt CO promoters increase NOx to a lesser extent very much in line with commercial experience using these additives (see Table 2).

The use of non-Pt promoters is now widely practised and has led to signi cant NOx reduction (typically ~70%) by eliminating this undesired side effect of Pt promoters. In the US, non-Pt promoters have almost entirely replaced Pt based CO promoters.

CO promoters help conversion of CO to CO2 within the regenerator bed, reducing afterburning (combus-tion of CO to CO2 in the dilute phase above the regenerator catalyst bed leading to increased tempera-tures). Figure 6 shows that this activity is short-lived with a half life measured in hours, meaning that where afterburn is a problem CO promoter has to be added semi-continuously. Fresh and equilibrated CO promoters have different effects on FCC nitrogen chemistry.

Fresh Pt based and non-Pt CO promoters both initially increase

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HCN emissions from their FCC units. This is an update of the process described by the author in Reducing FCC unit NOx emissions, which explains steps 1-5 in more detail.

Step 1: determine unit operating variable effects on NOx and HCNThe rst step to NOx/HCN reduction is to thoroughly under-

FCCs, residual HCN is combusted and the vast majority of the NOx is produced in the CO boiler, so this approach is not relevant to these units.)

Steps to reduce FCC NOx and HCN formationThere are a series of steps which can be followed by re ners faced with requirements to reduce NOx and

NOx (Pt > non-Pt). However, NOx production markedly differs after aging.

As Pt and non-Pt CO promoters age, the active metal sinters to form large clusters hundreds of atoms in diameter (see Figure 7). In Pt based CO promoters, the Pt clusters continue to drive conversion of intermediates (HCN, NH3) to NOx with selectivity towards making NOx increasing with increasing age (Pt particle size, see Figure 8). Aged non-Pt promoters however exhibit a very different effect: the activity for NOx formation is short-lived, while its activity for HCN conversion (to nitrogen) remains for a long time (see Table 3 and Table 4).

Metals and feed affect the selectiv-ity of the ue gas nitrogen species. With a synthetic spent catalyst (steam deactivated, no metals applied and using a standard VGO, selectivities towards NH3 and HCN change compared with the commer-cially obtained spent catalyst (see Table 5). Where the commercially obtained spent catalyst did not show NH3 in ue gas, the synthetic spent catalyst shows NH3 upon coke oxidation. The pattern in ue gas products that appears is very similar to the commercially obtained spent catalyst as both the Pt combustion promoter as well as the non-Pt combustion promoter effectively destruct HCN. Again, the selectivity towards NO is high over the Pt, low over the non-Pt combustion promoter. Note that the non-Pt combustion promoter also exhibits a higher ef ciency in NH3 destruction compared to the Pt combustion promoter. This shows that both Pt and non-Pt combustion promoters can effectively oxidise reduced nitrogen species, but the non-Pt combustion promoter is more effec-tive in these reactions than the Pt combustion promoter and exhibits a higher selectivity to nitrogen over NO.

Reduction of refi nery NOx and HCN emissions With this improved understanding of the chemistry, we will explain some practical steps for re ners to minimise FCC regenerator NOx and HCN emissions. (In partial burn

160

200

180

140

120

NO

x, p

pm

100

65

75

70

60

55

Aft

erb

urn

, F

500 60 120 180 240 300

Time, minutes

CO oxidation activity deactivates rapidlyImmediate stable NOx formationCO oxidation activity deactivates rapidly

Figure 6 CO promotion activity of Pt CO promoter has a shorter half life than NOx production

Atom pairs

Single atoms

1nm

Fresh COP

COP in Ecat150 nm

Pt sinters as the additive ages

In fresh COP the Pt is highly dispersed mostly as single atoms


therefore critical to minimise additions (or better, to replace the Pt CO promoter with a non-Pt promoter).

Pre-blending CO promoter results in a large excess of Pt usage for most of the time. Any CO promoter additions should be independent from fresh catalyst to avoid exces-sive use which will drive up NOx formation.

Step 3: establish the minimum levelof platinum promoter additionsShot dosing promoter causes only small, short-term spikes in NOx emissions. A strategy of either manual application, or using an additive loader, to dose promoter only when required to suppress spikes in afterburn will minimise Pt in the inventory.

Having minimised the usage of platinum promoter, the NOx and HCN emissions can be reassessed. If further reductions in NOx are required proceed to Step 4.

Step 4: replace platinum promoterwith a non-platinum promoter suchas COP-NPNumerous commercial trials of COP-NP have demonstrated signifi-cant reductions in NOx emissions when substituting platinum based combustion promoters, while main-taining equal afterburn control and low CO emissions. Furthermore, COP-NP reduces HCN emissions.

Step 5: try a NOx reduction additiveIf NOx and HCN emissions are still above the required level, then a NOx reduction additive like IntercatJMs NOxGetter can be used.

Step 6: regenerator modification If after carrying out all of the above steps NOx or HCN emissions are still above target, then hardware solutions are required to improve the spent catalyst and air distribu-tion within the regenerator.

This process to minimise NOx emissions can be illustrated as a flow chart (see Figure 9).

ConclusionsFCC regenerator nitrogen chemistry is complex with a subtle interplay between regenerator design and

FCC operation. It will also provide a base line method to evaluate improvements and demonstrate progress to the regulators. Typical variables are: excess oxygen, opti-mise the use of Sb, optimise regenerator bed levels.

Step 2: discontinue any pre-blended promoter usageWhile platinum promoter does effectively control afterburn and assists in HCN conversion, it is a major factor in increasing NOx. It is

stand the existing regenerator operation. Reducing FCC unit NOx emissions explains the usefulness of regression analysis for determining the effect of major FCC operating variables on regenerator NOx emissions, and a similar approach is needed to evaluate HCN emissions.

The resulting analysis allows the refiner to assess how operating variables can be adjusted to mini-mise NOx and HCN emissions while minimising the impact on

150

250

300

200

100

50

NO

x, p

pm

00 20 40 60 80 100 120

Days

Pt COP

Commercial FCCU Transition from Pt COP to COP-NPNOx drops by 70%

COP-NP additions begin

Figure 8 NOx emissions remain for a long time following discontinued use of Pt CO promoter

CO/CO2, NO, HCN, NH

3, N

2O, Total N

Vol/Vol Vol% Vol% Vol% Vol% rel. to w/o COPw/o COP 0.52 39 12 - 0.3 1.0Pt-COP 0.24 89 8 - 0.3 1.9Non-Pt COP 0.23 84 6 - - 1.7

Impact of fresh CO promoter on N-species selectivity in the TPO of spent catalyst (IR detector)

Table 3

CO/CO

2, NO, HCN, NH

3, N

2O, Total N

Vol/Vol Vol% Vol% Vol% Vol% rel. to w/o COPw/o COP 0.52 39 12 - 0.3 1.0Pt-COP 0.30 92 8 - - 2.0Non-Pt COP 0.31 67 6 - - 1.4

Impact of deactivated CO promoter on N-species selectivity in TPO of spent catalyst (IR detector)

CO/CO

2, NO, HCN, NH

3, N

2O, Total N

Vol/Vol Vol% Vol% Vol% Vol% rel. to w/o COPw/o COP 0.70 15 2.9 11 0.3 1.0Pt-COP 0.15 93 0.1 7 - 3.4Non-Pt COP 0.15 64 - 3 - 2.5

Impact of deactivated CO promoter on N-species selectivity in TPO of spent catalyst (IR detector)

Table 4

Table 5


cattec.indd 1 26/02/2013 16:59


Johnson Matthey. He holds a MSc in chemical engineering from Twente University and a PhD in heterogeneous catalysis and chemical processes from University of Amsterdam.Charles Radcliffe is a Technical Consultant, FCC and Refining. He has more than 30 years technical and managerial experience in the refining, petrochemical and plastics industries, and holds a BSc in chemical engineering from Birmingham University and an MBA from The Open University. Paul Diddams is Vice President for FCC Additives within Johnson Mattheys Refineries Division. He has over 25 years experience in refining and catalysis, and holds a BSc in chemistry from Newcastle University and a PhD in physical chemistry from Cambridge University.

NOxGeTTeR and COP-NP are trademarks of Intercat

JM.

References1 Radcliffe C, Reducing FCC unit SOx emissions, PTQ, Catalysis, 2008.2 Mo x, de Graaf B, Diddams P, HCN emissions in fluid catalytic cracking, PTQ, Q2 2013.3 Diddams P A, AFPM Annual Meeting, San Antonio, 2013 AM-13-19.4 Wilson J W, AFPM Annual Meeting, San Antonio, 2003, AM-03-44.

Xunhua Mo is a Catalyst Development Scientist with Johnson Matthey Technology Center in Savannah, USA. She holds a PhD in chemistry from Clemson University.Bart de Graaf is FCC R&D Director with

coked catalyst. A substantial part of the nitrogen from the feed is left in the coke and during its combustion HCN is readily formed at low temperatures in the presence of oxygen, as well as nitrogen and NOx. FCC regenerator conditions generally favour conversion of HCN to nitrogen or NO.

Combustion promoters help reduce HCN by catalysing its conversion to nitrogen or NO. Pt combustion promoters prefer to do this by creating mainly NO, whereas non-Pt promoters prefer to convert HCN to nitrogen.

Move to full burn or hardware changes

Remove promoter and add separately

Minimise promoter additions to reduce

NOx/HCN

Determine what operating variables affect NOx/HCN in your unit data

with IntercatJMs help

Operate to minimise NOx/HCN within unit operating constraints

Start here...

Using Pt

Full burn regen?NOx/HCN

emissions under target?

Using pre-promoted

catalyst?

Use non-Pt promoter

NOx/HCN emissions under

target?


target?

Trial NOXGetter

Improve catalyst/air distribution

SUCCESSNOx/HCN

emissions under target?


target?

No No Yes

Yes

Yes

Yes

Yes

No

No

No

No

Yes

No Yes

Yes

No

Figure 9 Process to minimise NOx emissions


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Capturing maximum value with tight oil feeds in the FCC

Tight oil production has changed the refining land-scape for major portions of

the US and market forecasts show dramatic changes in the interna-tional refining community as tight oil production rates continue to ramp up. According to Hart Energy estimates, tight oil production will represent 46% of domestic crude oil production in 2020.1 While tight oil is of higher quality, many US refin-eries have been configured to process the increasingly heavy sour crudes previously projected to be available. Fluidised catalytic crack-ers (FCC) at refineries processing tight oil have seen serious operat-ing changes; choice of catalyst and overall catalyst management strat-egy is a critical factor in achieving successful optimisation. BASF is the market leader in supplying FCC catalysts to refineries processing tight oil. In general, tight oil FCC feeds are light, paraffinic, have different contaminants, and are low in vacuum gasoil (VGO) and resid-uum content. Typical challenges for FCCs processing these crudes include high amounts of liquefied petroleum gas (LPG), maintaining stable heat balance, higher alkali metals, increased iron loadings and reduced feed rates. This article will illustrate how BASF is helping refiners to capture maximum value with tight oil feeds through operat-ing strategies, innovative catalysts and technical service. BASF has a diverse catalyst portfolio providing the flexibility required to help solve these problems including high activity, optimum delta coke and high iron tolerance.

Tight oil quality varies between

FCCs processing tight oil feeds require catalyst choices to deal with higher conversion, heat balance concerns, and higher sodium, calcium and iron

ALEXIS SHACKLEFORD BASF Catalysts

oil fields and has been shown to be highly variable even from the same field. Batch shipping these crudes by truck and rail increases this vari-ability. Given this, there are many general properties which tight oil crudes exhibit. Tight oil formations are relatively young, light, low boil-ing point, low in Concarbon, have high naphtha and distillate yields, lower vacuum gasoil cuts, contain almost no vacuum resid, have low contaminants of sulphur, nitrogen, nickel and vanadium but have higher sodium, calcium, potassium and iron. The high naphtha and distillate yields can choke the crude column, limiting crude rates. Low sulphur will reduce the sulphur load across the refinery, thus lower-ing the sulphur plant loads. Due to the high naphtha yield, which is more paraffinic, maintaining the octane balance can become difficult, requiring the need to maximise alkylation and reforming, and plac-ing higher emphasis on FCC gasoline octane. With the low resid content of the crude, refiners may consider shutting down the resid processing unit and feeding the resid directly to the FCC. Crude compatibility also needs to be

addressed when blending the light/sweet tight oil crudes with heavy/sour crudes, creating a dumbbell feed that does not act as a homogeneous mixture, resulting in asphaltene precipitation.

Processing tight oil in the FCC brings benefits and challenges to refiners. The VGO cut of tight oil is typically light, low carbon produc-ing, and low in contaminant sulphur, nitrogen, nickel and vana-dium. Table 1 shows the VGO cut of two tight oils compared to West Texas Intermediate (WTI) and Maya. The resid cut of tight oils shows the same trend in properties as the VGO cut, including being light and low carbon producing. The light, low boiling point feed is easily converted to lighter products. The lower sulphur and nitrogen in the feed reduces gasoline sulphur and flue gas NOx and SOx, making it easier to meet regulations. With less nickel and vanadium, hydrogen and coke are lower. However, high conver-sion and high LPG yield may limit the gas plants throughput and thus the FCC rate. The lower coke making tendency of the feed can constrain the unit on heat balance and catalyst circulation.


VGO cut properties TX Shale Bakken Core WTI Maya BlendAPI gravity 31.9 24.5 26.3 21Sulphur, wt% 0.18 0.27 0.46 2.05Acidity, mg KOH/g 0.049 0.053 0.095 0.085Nitrogen, wt% 0.01 0.11 0.13 0.18Refractive index, 67C 1.4588 1.4824 1.4759 1.498Nickel, ppm 0.09 0.47 0 0.64Vanadium, ppm 0.08 0.14 0 4.48Concarbon, wt% 0.03 0.68 0.01 0.47

Properties of VGO cut from different crude sources by KBC

Table 1

basf cat.indd 1 28/02/2014 11:52

sabin.indd 1 27/02/2013 15:01


include higher e-cat activity through higher additions, higher rare earth (REO) content, or chang-ing to a less coke selective catalyst. If the unit cannot maintain heat balance, some less desirable options to investigate are turning on the air pre-heater, adding torch oil and reducing dispersion or stripping steam. The air pre-heater and air

Catalysis - Petroleum Technology Quarterly - 2014. Refining, Gas Processing and Petrochemicals

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Transcript of Catalysis - Petroleum Technology Quarterly - 2014. Refining, Gas Processing and Petrochemicals