2012 Catalysis__

catalysis2012

ptq

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2012. 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 the publisher cannot be held responsible for any statements, opinions or views or for any inaccuracies.

3 Onwards and upwards ChrisCunningham 5 ptq&a 17 Evaluation of a low rare earth resid FCC catalyst SabeethSrikantharajahandColinBaillieGrace Catalysts Technologies BernhardZahnbrecherandWielandWacheBayernoil

23 Refinery fuel gas in steam reforming hydrogen plants PeterBroadhurstandGrahamHintonJohnson Matthey Catalysts

31 Estimating silicon accumulation in coker naphtha hydrotreaters ThienanTran,PatrickGripkaandLarryKraus Criterion Catalysts & Technologies

35 FCC catalyst coolers in maximum propylene mode RahulPillaiandPhillipNiccumKBR

45 Decrease catalyst costs by regeneration, analysis and sorting PierreDufresne Eurecat FrancoisLocatelli Eurecat France 53 Optimisation of integrated aromatic complexes AxelDkerSd-Chemie AG

59 Troubleshooting a FCC unit ChiranjeeviThota,ShaliniGupta,DattatrayaTammannaGokak, RavikumarVoolapalli,PVCRaoandViswanathanPoyyamani SwaminathanBharat Petroleum Corporation

MarathonOilsCatlettsburgrefinery,Kentucky,USA Photo: Marathon Oil

2012www.eptq.com

EditorRen G Gonzalez

[email protected]

Production EditorRachel Zamorski

[email protected]

Graphics EditorMohammed Samiuddin

[email protected]

EditorialPO 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,

(9(5:21'(5:+$70$.(6285&$7$/

CATALYSIS 2012 3

Editor Chris Cunningham [email protected]

Production EditorRachel [email protected]

Graphics EditorRob [email protected]

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

Business Development DirectorPaul [email protected] Advertising SalesBob [email protected]

Advertising Sales Officetel +44 844 5888 771 fax +44 844 5888 662

PublisherNic [email protected]

CirculationJacki [email protected]

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

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.

Vol 17 No 2 2012

Onwards and upwards

The refining catalysts business is nothing if not responsive. Sometimes that response has to be in the immediate term, reference some significant price hikes for FCC catalyst in particular during 2011, although there is a continuing and strong technical riposte from catalyst developers to the unlegislated rise in rare earth metals prices that chiefly caused the hikes. For the most part, though, the catalyst firms technical development and business focus is determined in the longer term by the twin drivers of economic development and environmental regulation.

In the US and Western Europe, engineering standards are delivering increas-ingly efficient road vehicles, while the post-recession market is applying a more general brake to growth in demand for transportation fuels. As a result, the worlds developing economies are determining the future shape of growth in demand for petroleum products.

To illustrate, demand for transport fuels in developing economies may rise by as much as 300% by 2050, according to the World Energy Council. Half a decade ago, vehicle ownership was at 11 cars per 1000 people in China and about 20% higher in India. The world average was around 110 cars per 1000 capita. But Chinas car ownership has been growing by 12% per annum in recent years, while the equivalent rate in India is 9%. More immediately, China is expected to cut its sulphur limit for vehicle fuels from a street-chocking 350 ppm to 50 ppm, while Brazil, India and the Arabian Gulf area are moving towards ultra-low sulphur diesel regulation, all of which should deliver a strong upsurge in demand for hydrotreating catalysts in the near term. Taken together, these trends are strongly influencing both catalyst sales effort and the siting of new catalyst production centres.

If not quite on the scale of demand for car fuels in developing countries, growth in demand for ships bunker fuels is strong and, geographically, more even. Most of the worlds trade is done by ship and the global fleet continues to grow in line with populations and their trade. Although bunkers share of the total market for fuel oils continues to increase, there is uncertainty about the rate of increase. The reasons are of special interest to catalyst suppliers. The International Maritime Organisations Marpol Annex VI regulations are deliv-ering a steady reduction in the level of sulphur oxide emissions from ships. In its initial stages, the legislation chiefly affected coastal and semi-enclosed seawaters, but now it is taking effect in the open seas.

From the start of this year, a reduction in the global cap on the sulphur content of bunker fuels, from 4.50% to 3.50%, came into force. A progressive reduction in the allowable level of sulphur in ships fuel will see the cap fall to 0.5% in 2020, subject to a review in 2018. For coastal waters and sulphur emis-sion control areas, the allowable sulphur level is set to fall to 0.10%, from a current 1%, in 2015. Uncertainty arises in how the IMO expects to apply the more stringent levels of Annex VI. The IMO does not favour stack emissions cleaning on board ships, but ship owners are not especially in favour of the price premium implied by a radical drop in fuel sulphur levels. Depending on the price balance, operators of new-build ships may opt for distillate as their fuel of choice. In any event, a whole lot more hydrotreating to meet maritime demand is implied.

CHRIS CUNNINGHAM

EditorRen G Gonzalez

[email protected]

Production EditorRachel Zamorski

[email protected]

Graphics EditorMohammed Samiuddin

[email protected]

EditorialPO 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,

Rare earth price inflation is the most serious issue facing the global refining industry. Grace, with our long history of innovation and strong R&D, leads the industry with the first line of commercially successful zero/low rare earth FCC catalysts: the REpLaCeR family.

Launched in the first quarter of 2011, the REpLaCeR family includes five new catalysts for both hydrotreated and resid feed processing with zero and low rare earth content. The REpLaCeR family of catalysts utilizes proprietary zeolites and state-of-the-art stabilization methods to deliver performance similar to current rare earth-based FCC technologies.

Were also investing in our plants to bring these products to the refining industry quickly and globally.

So if youre concerned about rare earth pricing and availability, but need optimal FCC performance, call the technical experts at Grace. Well customize a solution using one of our new zero/low rare earth catalysts that delivers the yields you expect.

REp RTM

Worried about the cost of rare earth?Grace has the solution:

Grace Catalysts Technologies7500 Grace DriveColumbia, MD USA 21044+1.410.531.4000

www.grace.comwww.e-catalysts.com

grace.indd 1 23/2/12 11:54:00

Q Istheresignificantcommercialexperiencewithsolidacidalkylationcatalysts?Whatsortsofadvantagesareexperiencedorexpectedoverliquidacidcatalysts?

A Edwin van Rooijen, Business Manager, Albemarle,[email protected] are still experiencing a considerable amount of interest in our AlkyClean technology, especially in the emerging economies of the world. This technology and the associated solid acid catalyst AlkyStar were jointly developed by Albemarle, Lummus Technology and Neste Oil. AlkyClean technology was honoured by the American Chemical Society with a 2010 Award for Affordable Green Chemistry.

The AlkyClean process significantly improves the safety of refinery alkylation over conventional liquid acid-based processes. It reduces potential hazards asso-ciated with the transportation and handling of liquid acids. Relying on patented technology, combined with Albemarles durable AlkyStar catalyst, the AlkyClean process gives refiners a competitive, cleaner and inher-ently safer alkylation technology. No acid-soluble oils or spent acids are produced, and there is no need for product post-treatment of any kind to remove traces of acid. In addition to these environmental advantages, the AlkyClean process has proven to be economic and robust and requires minimal maintenance.

Q WhatcatalysttypesarebestforminimisingoctanelossesinFCCgasolinehydrotreaters?

A Brian Watkins, Manager of Technical Service andLaboratory Evaluations, Advanced Refining Technologies,[email protected] loss in FCC gasoline hydrotreaters occurs with the saturation of the olefins present in the oil coming from the FCC unit. This saturation readily occurs over hydrotreating catalyst in the presence of heat and hydrogen, so a low-metals cobalt molybdenum (CoMo/Al2O3) catalyst selective for hydrodesulphurisa-tion is recommended. The goal is to be able to provide the required sulphur removal with limited olefin and aromatic saturation. Nickel molybdenum (NiMo/Al2O3) catalyst, although having high hydrodesulphuri-sation activity, also has a much higher olefin and aromatics conversion activity, making it unsuitable for this application. Generally, to minimise olefin satura-tion, lower pressure and high liquid space velocity are recommended in order to limit octane loss.

A Steven Mayo, Global Manager HydroprocessingApplications,Albemarle,[email protected] minimise octane loss in FCC gasoline hydrotreaters, both a catalyst and a process are needed that selec-tively maximise sulphur removal while minimising olefin saturation and mercaptan recombination reac-tions. The best catalysts for the application are formulated to maximise direct-route desulphurisation with minimum hydrogenation activity. Cobalt- molybdenum catalysts are the preferred catalyst type. Olefins are readily saturated under typical naphtha hydrotreating conditions, so catalysts alone are usually insufficient to prevent significant loss of octane in these units. Licensed FCC gasoline post-treatment process technology combined with proprietary catalyst technol-ogy allows for very high levels of sulphur removal (>95%) with minimum octane loss. RT-235 is the latest catalyst development by ExxonMobil Research and Engineering and Albemarle for their SCANfining, selective FCC gasoline desulphurisation, process. This catalyst offers exceptionally high HDS activity with even better octane retention than the first-generation SCANfining catalyst, RT-225. RT-235 can be used in any SCANfiner and is also available for use in selective FCC naphtha desulphurisation units licensed by others.

Q How effective are NOx-reducing additives at cutting

regeneratorstackemissions,andisusingthemacost-effectiveoption?

A Alan Kramer, Global FCC Additives Specialist,Albemarle,[email protected] are two additive types that can lower FCC regen-erator stack NOx emissions. The first type is low-NOx combustion promoters such as Albemarles ElimiNOx. These replace conventional platinum-based promoters used in full-combustion FCC units. ElimiNOx has been shown to be very effective over the past 15 years in lowering NOx emissions while maintaining CO and afterburn control in the regenerator. In the 2007 NPRA annual meeting,1 it was reported that US refineries using low-NOx promoters, in accordance with EPA consent decrees, usually saw between 20% and 80% reductions in NOx after switching promoter type.

The second type of additive is a non-promoting NOx reduction additive, such as Albemarles DuraNOx. These additives are also only used in full-combustion FCC units. The performance of these additives varies

www.eptq.com Catalysis 2012 5

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AdditionalQ&Acanbefoundatwww.eptq.com/QandA

Q&A copy 10.indd 1 23/2/12 12:51:18

greatly from unit to unit and is often difficult to predict. During the 2007 NPRA annual meeting, it was also reported that NOx reduction additives used by US refiners engaged in consent decree trials averaged 26% reduction in NOx. Of the full-burn FCC units reporting results, five saw no effect, 10 observed reductions up to 30%, and eight saw reductions between 50% and 80% when NOx additives were used.

When combined with tighter controls on regenerator excess oxygen levels, Albemarles NOx reduction addi-tives allow refiners to completely avoid the capital expenditure of installing hardware to reduce NOx emis-sions, proving once again that additives can be a very cost-effective option. 1 Sexton, Joyal, Foley, EPA Consent Decrees: Progress on FCC Implementation and Future Challenges, NPRA AM-07-44, 2007.

A Jason Smith, Refining Additives Manager, BASF, [email protected] additive performance and cost effective-ness is highly dependent on the unit, as both equipment characteristics and operational variables play a role in NOx formation and reduction. Controlling NOx emissions is probably one of the most difficult applications in the FCC unit.

There are several interacting factors that influence NOx emissions. These include: type and level of CO promotion, air flow distribution, excess oxygen, regen-erator temperature, regenerator pressure, regen bed level, stripping steam rate, catalyst circulation, and type and quantity of NOx reduction additive.

There are two options to reduce NOx emissions. The first approach is to reduce the level of NOx generated. This can be achieved by replacing the platinum CO promoter with one that generates lower levels of NOx while maintaining the capability of oxidising CO to

CO2. Low NOx Promoter (LNP) is used by many refin-eries in controlling afterburn and CO emissions, with a limited amount of NOx produced. Typically, switching from platinum to LNP will result in a reduction of NOx of approximately 30%.

A second approach is to use a NOx additive specifi-cally designed to chemically reduce NOx to inert nitrogen. Several NOx-reducing products are being offered in the marketplace, including CleaNOx, BASFs NOx reduction additive. CleaNOx has been most successful in the US, where it has been used to address EPA consent decrees. In one example, a US refinery in the midwest was able to reduce NOx by more than 70% from an average of 200 ppm to 60 ppm using 1.4 wt% of CleaNOx in its inventory.

CleaNOx has also been used and proven in applica-tions where a refinery wanted to reduce NOx from an already low average base of 27 ppm on the East Coast of the US. Even in such a demanding application, CleaNOx demonstrated a 33% reduction in NOx.

A Eric Griesinger, Marketing Manager, Environmental Additives, Grace Catalysts Technologies, [email protected] reduction additives generally fall under two cate-gories: standalone NOx reduction additives and low NOx combustion promoters.

Standalone NOx reduction additives are catalytic- based NOx control technologies that provide NOx reduction without any combustion promotional activ-ity. Generally, this NOx control technology has provided a slow response to mitigating elevated NOx concentrations. Grace Davison has developed a cata-lytic NOx reduction additive, GDNOx 1, which shows prospect of providing a quicker ability to curb NOx emissions. Further, GDNOx 1 technology, which has

been patented, provides greater NOx reduction with a correspondingly greater dosing rate (see Figure 1), yet with diminished FCC unit yield penalties often encountered when utilising previous-generation NOx reduction additives. Additionally, GDNOx 1 has not been vulnerable to material surcharges, thus making the product a cost-effective option.

Current generation of low NOx combustion promoters are typically formulated with a noble metal other than platinum. Historically, the use of platinum has been demonstrated to exhibit a correlation with elevated and prolonged NOx concentrations in regenerator flue stack gases. Applications of Grace Davisons current-generation low NOx combus-tion promoter, CP P, when dosed in higher than normal rates, whether intentionally to correct other FCC unit conditions or unintentionally, has shown a shortened duration of

6 Catalysis 2012 www.eptq.com

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0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

NO

, p

pm

Time, hrs

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10.0% GDNOX 1

GDNOX1 NO

x after GDNO

X 1 Percentage NO

x

Addition rate % of inventory Base line NOx, ppm addition, ppm reduction, %

2.5% GDNOX 1 292 139 50

5.0% GDNOX 1 287 110 60

10.0% GDNOX 1 287 62 80

Figure 1 Pilot plant testing: NOx reduction with multiple GDNO

x 1 additions

Q&A copy 10.indd 2 23/2/12 12:51:35

Refners worldwide use our hydroprocessing

technologies and catalysts to deliver

cleanerproducts from low-quality feeds.

Let us show you how. (001)510.242.3177www.clg-clean.com

Learn how CLGs tailored hydroprocessing catalyst systems maximize coversion to clean products visit clg-catalysts.com

ICR 512ICR 180 ICR 185 ICR 250

ISOCRACKING

VGO

clean transportation fuels ultra-low sulfur diesel (


elevated NOx emissions is likely. This observation of a shortened NOx emission excursion interval can provide benefit to refiners when striving to satisfy a rolling day average or other time-based NOx emission limit constraints, while still providing CO promotion performance similar to prior medium-activity plati-num-formulated CO promoters.

The US Environmental Protection Agency (EPA) concluded that newly adopted emission limits utilising additives and combustion controls were achievable, cost effective and had fewer secondary impacts than more costly hardware-oriented control technologies.1

The EPA issued final amendments to its New Source Performance Standards for Petroleum Refineries (NSPS)1 on 24 June 2008. Within this amendment, the EPA states that the currently Best Demonstrated Technology (BDT) to NOx emission control now includes the use of additives in conjunction with an upwardly revised NOx emission limit of 80 ppmv based on a seven-day rolling average. Typically, under EPA Consent Decree proceedings, FCC unit operations have been restricted to a NOx emission limit of 20 ppmv based on a 365-day rolling average and 40 ppmv based on a seven-day rolling average. This NSPS amendment now also recognises the secondary envi-ronmental impact that many of the hardware solutions inflict upon the environment, inherent in their opera-tion to achieve a 20 ppmv maximum NOx emission limit. These secondary impacts include PM (Particulate Matter) as well as additional SO2 and NOx emissions resulting from increased electrical demand. In addition, many of the hardware solutions require supplementary chemical reactants that add hazards and emission problems of their own.2 As such, non-platinum formu-lated oxidation promoters and advanced oxidation controls typically are anticipated to provide the least overall environmental impact, as they generally do not generate further secondary environmental emissions, and do so cost effectively by EPA measures.

Grace Davison continues offering catalytic NOx control technologies to the refining industry in agree-ment with the EPAs NSPS1 conclusions, whereby the combination of non-platinum-formulated oxidation promoters and advanced oxidation controls typically are anticipated to provide the least overall environ-mental impact, and do so at a reasonable cost in many applications.

1 New Source Performance Standards (NSPS) for Petroleum Refineries, at 40 C.F.R. Part 60, Subpart J/Ja. 73 Fed. Reg. 35838 (24 June 2008). The amendments were proposed in 2007 as the outcome of the periodic review of NSPS standards required under the Clean Air Act - Section 111(b)(1). 72 Fed. Reg. 27278 (14 May 2007). The rules provide technical corrections to the existing Subpart J standards and create a set of new emissions for fluid catalytic cracking units (FCCU), fluid coking units (FCU), sulphur recovery plants (SRP), and fuel gas combustion devices for facilities that were newly constructed, modified or reconstructed after 14 May 2007. The new rules became effective on 24 June 2008.2 Roser F S, Schnaith M W, Walker P D , Integrated View to Understanding the FCC NO

x Puzzle, UOP LLC, Des Plaines Illinois, 2004 AIChE Annual

Meeting.

Q Are there any rule-of-thumb indications of the trade-off in price and performance where low rare earth catalysts have replaced conventional rare earth-containing FCC catalysts?

A Raul Arriaga Global FCC Applications Technology Specialist, Albemarle, [email protected] Ken Bruno Global Applications Technology Manager, FCC, Albemarle, [email protected] total price of an FCC catalyst is the combination of a catalysts base price plus rare earth surcharges. The adjustment formula to calculate the rare earth surcharge is the result of mutual agreement between suppliers and refiners and typically depends on the market price of lanthanum oxide. The base price of the catalyst depends on the type of technology used and the amount of active components in the formulation. Special low rare earth technologies have been devel-oped by catalyst suppliers to compensate for the selectivities and zeolite stabilisation provided by rare earth. Additionally, the amount of active components may need to be increased if the rare earth is reduced. Therefore, it naturally follows that the base price of a low rare earth technology catalyst will be higher than a conventional rare earth-containing FCC catalyst. However, the lower rare earth catalyst results in a reduced rare earth surcharge, making the total price of the catalyst economically attractive.

The changes expected in the performance of FCC catalysts at lower rare earth depend on the gap between the technology used in the original catalyst and the new lower rare earth catalyst. A simple exam-ple is reducing the rare earth on an originally high rare earth catalyst while keeping all other catalyst parameters constant. In this case, the zeolite stability would deteriorate and the equilibrium activity of the catalyst would decline. At the same time, LPG selectivity would increase and gasoline selectivity would drop. Under these circumstances, the catalyst will also produce less coke at constant conver-sion, resulting in lower delta coke. These changes in selectivities are usually not acceptable because each FCC unit is typically operating against multiple constraints.

Based on the above, very rarely would a catalyst supplier recommend only a reduction in the catalysts rare earth content without compensating via advanced low rare earth technology modifications. For example, Albemarle can make use of various features developed for a new family of Low Rare Earth Technology (LRT) catalysts. These features include a new zeolite stabilisa-tion technology, improved porosity, reduced mass transfer limitations (higher accessibility), advanced active matrices and zeolites grown to a high silica-to-alumina ratio, which results in improved structural integrity and lower amounts of non-framework alumina. The right combination of these features will recover most, if not all, of the activity lost with the lower rare earth content and will modify selectivities to keep the FCC unit operating within constraints. The result is maximum profitability for the FCC unit.

Q&A copy 10.indd 3 23/2/12 16:21:58

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A Solly Ismail, Modeling Specialist, BASF, [email protected] the reduction of rare earth in catalyst formula-tions can deliver immediate operating budget cost savings, it is important to consider the impact this will have on product slate margins. Based on proprietary simulation modelling, BASF has shown that as rare earth levels decrease, the conversion of feed to higher valued products will also drop (assuming all other variables are held constant). In order to assist custom-ers with evaluating the impact of lower rare earth catalytic options and to limit its downside, BASF works closely with each refiner to understand specific unit parameters and objectives. A customised strategy can include a combination of levers such as increasing cata-lyst addition rates, increasing total surface area or a combination of both in order to restore activity and achieve desired product specifications and margin targets. By doing so, BASF is able to determine if low rare earth catalyst formulations are appropriate for the customer and, if so, develop a customised strategy to implement a low rare earth catalytic option that fits the needs of the specific user.

As of the end of Q4 2011, 40% of our customers had made the switch to a lower rare earth formulation. Of these, five went through multiple reductions. All customers were happy with BASFs approach of tailor-ing new solutions based on either increased surface area with a minimum of additional catalyst usage. The company also worked closely with refiners in monitor-ing the changes to proactively mitigate surprises.

To get a fuller understanding of the impact of lower REO, the reader is referred to the more detailed article in the Q4 2011 issue of PTQ (FCC catalyst optimisation in response to rare earth prices).

A Rosann Schiller, Senior Marketing Manager, [email protected] and Colin Baillie, Marketing Manager, EMEA, Grace Catalysts Technologies, [email protected] REpLaCeR series of low and zero rare earth cata-lysts from Grace is being used in over 50 applications globally. First and foremost, there has been no trade-off in performance with respect to either product yields or catalyst additions. However, users of the REpLaCeR series of catalysts have experienced significant catalyst cost savings associated with high rare earth prices. Refineries moving to zero rare earth REpLaCeR cata-lysts for low metal feed applications have seen catalyst costs reduced by up to 500 000/y per 1 t/d of catalyst used, while users of low rare earth REpLaCeR catalysts for resid processing have been able to reduce catalyst costs by between 250 000 and 750 000/y per 1 t/d of catalyst used.

Q What catalyst formulations will maximise LCO yield from the FCC unit with minimum effect on bottoms yield?

A Yen Yung, Global Technical Specialist, Albemarle, [email protected]

The biggest challenge in fluid catalytic cracking is converting as much material in the feed with an atmo-spheric boiling point above 370C bottoms to more valuable LPG, gasoline (hydrocarbon molecules boiling between about 40C and 221C) and light cycle oil (LCO hydrocarbon molecules boiling between 221C and 370C). To maximise the yield of LCO, it is impera-tive to maximise the conversion of bottoms to LCO while minimising the conversion of LCO to lighter products and coke. It is generally accepted that meso-pore and macropore activity, the so-called alumina matrix activity, favours bottoms cracking, while zeolites provide higher LPG and gasoline selectivity. Therefore, middle distillate production is generally favoured by higher matrix cracking (as evidenced by a higher meso surface area) and reduced zeolite cracking. In other words, middle distillate production increases as the zeolite-to-matrix ratio decreases.

For greatest bottoms conversion, the feed molecules need to quickly reach the active sites. Conversion of the desirable products in the diesel boiling range and other secondary reactions, such as hydrogen transfer, aromatisation and condensation, must be avoided. This is achieved by increasing the accessibility of the cata-lyst. Accessibility is the property that allows primary products to escape promptly from the reaction sites.

Outstanding performance of highly accessible cata-lysts, as measured by our internally developed Albemarle Accessibility Index (AAI) method, has been confirmed in several applications.

Albemarle has a full line of MD catalysts. Amber MD and Upgrader MD feature very high matrix cracking activity and AAI. Amber MD is recommended for gas oil feed applications and Upgrader MD is recom-mended for cracking residual feedstocks. For applications requiring flexibility, the companys bottoms conversion additive, BCMT-500, is recom-mended for all types of feedstocks. In addition, Albemarles technical specialists have special tools for optimising unit operations and selecting the proper FCC catalysts grades, including those that utilise Low Rare Earth (LRT) technology.

Once an FCC catalyst is selected, Albemarles techni-cal specialists will assist their customer in optimising their operating strategy for maximum LCO production, as discussed in the following two examples.

The first example includes an FCC unit processing vacuum gas oil with a typical API of 23C and a sulphur content of about 1 wt%. The catalyst used in this example is Amber MD. The FCC unit was operat-ing at a unit riser outlet temperature of 518C, a combined feed temperature of 226C and a catalyst-to-oil ratio of 7.0 kg/kg. In this example, the gasoline end point is minimised to an ASTM D-86 end point of 149C, while the LCO end point is very high at an ASTM D-86 end point of 379C. With these cut points and the use of Amber MD, a yield of 44 wt% LCO is obtained with a typical cetane index of 34. This unit applies no bottoms recycle.

The second example also consists of an FCC unit that is processing vacuum gas oil. Like the first example,


Q&A copy 10.indd 4 23/2/12 12:51:57

action loves reactionChemical reactions require chemical catalysts. As the global leader in chemical catalysts, BASF acts through continuous product and process innovations in collaborative partnerships with our customers. The result is a broad chemical catalyst portfolio backed by dedicated customer and technical service and enabled through the strength of BASF - The Chemical Company.

At BASF, we create chemistry.

www.catalysts.basf.com/process

n Adsorbentsn Fine Chemical Catalysts n Environmental Catalysts n Catalysts for Fuel Cells n Catalysts for Oleochemicals & Other Biorenewables n Oxidation & Dehydrogenation Catalysts n Petrochemical Catalysts n Polyolefin Catalysts n Refining Catalysts n Syngas Catalysts n Custom Catalysts

basf.indd 1 23/2/12 11:58:16

Amber MD is used. In this example, there is a low reaction temperature (499C), high combined feed temperature (368C) and low catalyst-to-oil ratio (4.0 kg/kg). Bottoms recycle (the recycle rate/fresh feed ratio varied between 0.5-1.0 vol/vol) is applied to enhance the production of LCO. Note that the volume of recycle can be as high as the fresh feed intake. The gasoline end point is also minimised. LCO yield and cetane index are very high at 42.4 wt% and 34, respec-tively. Bottoms yield (21.2 wt %) is higher due to

extremely low severity. Despite the high bottoms yield unit, the economics were much improved as the market favoured a high LCO yield.

A Rosann Schiller, Senior Marketing Manager, [email protected] and Colin Baillie, Marketing Manager, EMEA, Grace Catalysts Technologies, [email protected] LCO maximisation catalysts obviously need to have good bottoms-cracking performance. Therefore, Grace catalysts for LCO maximisation incorporate high matrix activity, including the option of utilising a new technology that provides a controlled deposition of a thin layer of reactive alumina on the surface of the zeolite crystals to facilitate the pre-cracking of large feed molecules. In addition, an FCC catalyst for LCO maximisation must also have the ability to maintain the cracked HCO molecules within the LCO boiling range fraction, which requires limiting the cracking of LCO to gasoline. Therefore, LCO maximisation cata-lysts from Grace incorporate proprietary pore restructuring functionality, which results in more pores with the diameter range of 100-600 (see Figure 1). This boost in porosity enables a more effective release of LCO molecules from the acid sites, minimising the undesired cracking of LCO into gasoline. Graces LCO maximisation catalyst brands include DieseliseR, Midas and Rebel FCC catalysts.

A Stefano Riva, Technical Service Manager, BASF,

[email protected] maximising LCO, an intermediate product in the cracking reaction sequence, focus should be on the matrix cracking activity of the catalyst. While the zeolite can achieve good bottoms cracking in a coke- selective way (low delta coke), the amount of zeolite required for that objective will rapidly crack the desired LCO to lighter products. Due to this trade-off, the bottoms cracking has to come from an increase in matrix. It is generally recognised that, at constant conversion, a lower Z/M (zeolite-to-matrix surface area) catalyst may have a higher delta coke. However, this will not necessarily result in a hotter regenerator (typically the opposite is true) when a unit moves from maximum conversion to maximum distillate modes. Not only should the catalyst Z/M be adjusted for maximum LCO, but also the catalyst activity and the FCC operating conditions. FCC units should operate at lower reactor severity (lowering the heat demand), and with lower equilibrium catalyst activity (reducing delta coke). This leaves plenty of room to accommodate a moderate increase in higher delta coke that can be derived from a lower Z/M catalyst. With that said, attention should still be paid to selecting both the right amount of matrix and the associated technology, with preference for the best coke-selective low Z/M catalyst. This will provide ample flexibility to swing between maximum conversion and maximum distillate opera-tions with the same catalyst should the market change rapidly. BASFs Prox-SMZ (Proximal Stable Matrix and Zeolite) technology is an example that addresses all of


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Unit composition Early trial Late trial Competitor, % 85 31

Stamina, % 15 69

Unit operating conditionsTotal feed rate, ton/d 1723 1672Feed preheat temp, C 178 232ROT, C 520 515Regenerator bed temp, C 721 720C/O, wt/wt 7.0 5.8

Feed qualitySpecific gravity 0.93 0.92Conradson carbon, wt% 0.71 1.14Basic nitrogen, ppm 450 410TBP90, C 547 571

Equilibrium catalyst propertiesV + Ni, ppm 4100 4240TSA, m2/g 120 127MSA, m2/g 53 64Z/M 1.3 1FACT activity, wt% 73 70

FCC unit yields (with cutpoint adjustments)Gasoline (C

5-160C), wt% 37.19 34.06

LCO (160-340C), wt% 29.03 33.87Slurry (340C+), wt% 13.57 13.14Coke, wt% 5.79 5.09LCO/slurry, % 68.1 72.1

Summary:Achieved >4.8 wt% greater distillate yields at partial turnoverMaintained lower bottoms at reduced reactor severity and dirtier feed conditions.

European maximum distillate trial of BASF Stamina catalyst

Table 1

Q&A copy 10.indd 5 23/2/12 12:52:08

Value adding catalysts, absorbents, additives and process technology for oil refining processes.

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JM_2485_RefineriesAd_ART_210x297.indd 1 09/02/2012 15:59j matthey.indd 1 23/2/12 11:59:38

the above (see NPRA-AM-09-34 and NPRA-AM-10-17).

With BASFs unique manufacturing process, the zeolite and the matrix are not physically blended, as in a traditional low Z/M catalyst, but are created in-situ during a single manu-facturing step. This process creates unprecedented proximity of matrix and zeolite, enabling reduced diffusion path length and best-in-class coke selectivity among the low Z/M family of catalysts. Further, the extremely low sodium content (below 0.1 wt%) achiev-able in this manufacturing process not only enables high stability of both zeolite and matrix to reduce the opex, but also helps to reduce the hydrogen transfer reactions, improving the LCO cetane. Maximum LCO catalysts from the Prox-SMZ technology have been commercially established and are avail-able for both VGO (under the name of HDXtra) and resid feeds (under the name of Stamina).

In several classic distillate maximisation trials with BASFs Stamina catalyst, LCO yields have increased while either holding steady or dropping slurry yields. In one case, a European FCC unit was processing resid feed and wanted to move to LCO maximum mode while dropping slurry yields and improving coke selectivity. The unit severity was dropped by lowering the reactor outlet temperature by 5C and increasing the feed preheat. The reduced severity conditions together with the highly stable Stamina MSA generated a 4.84 wt% improvement in LCO yields while maintaining bottoms conversion. All this was achieved in spite of dirtier feed conditions (ie, higher Conradson carbon and feed metals).

The second case was an Asian trial that also underwent reduced reactor severity to maxi-mise LCO yields. While using Stamina catalyst, the lowest bottom yields on record were achieved together with record throughputs due to the coke-selective bottoms upgrading.

Q Are there any dedicated catalyst developments geared towards favouring FCC propylene yield?

A Stuart Foskett, Regional Technology Manager, BASF, [email protected] is continually developing new catalyst technologies aimed at enhancing propylene production for maximum propylene operations (upwards of 10 wt% or 17.5 vol% propylene yield). A high level of ZSM-5 is always a prerequisite for maximum propylene; however, it is the characteristics of the FCC catalyst itself that define how much propylene can ulti-mately be produced. Propylene yields eventually reach a plateau as ZSM-5 content is increased to high levels; therefore, a holistic


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Q&A copy 10.indd 6 23/2/12 12:52:21

approach to catalyst design requires attention to additional factors beyond the ZSM-5. It is the genera-tion and preservation of gasoline ole ns, as precursors to ZSM-5 cracking, that is the de ning factor for ultimate propylene potential.

The high percentage of active ingredient in the catalyst, enabled by our in-situ zeolite synthesis, allows us to offer maximum propylene catalysts featuring reduced rare earth content, without any penalty in terms of activity and required catalyst addition rate. Lower rare earth helps to minimise hydrogen transfer, preserving more gasoline ole ns for cracking to propylene by ZSM-5. We have also invested heav-ily in technology upgrades for our plants to allow extreme levels of ultra-stabilisation, to produce zeolites with very low and stable unit cell size (UCS). BASFs MPS (maximum propylene solution) tech-nology was rst introduced in 2005 (see NPRA-AM-05-61) and has undergone continuous improvement since then. MPS has been operating continuously in the worlds largest propylene-focused FCC unit since 2006. Based upon extensive circulat-ing pilot plant evaluations, we are anticipating the latest MPS develop-ments will achieve incremental gains in propylene yield in the range of 0.5 to 1.0 wt% compared to the previous state-of-the-art technology.

Meanwhile, the development of additional technologies aimed at maximising propylene are progress-ing. This includes technologies aimed at offering high propylene yields with resid feeds combined with leading coke selectivity and metals resistance.

A Carel Pouwels, Global FCC Resid Specialist, Albemarle, [email protected] record-high propylene and conversion from wide ranges of feed qualities offers considerable challenges to catalyst design. Key to this is good understanding of the mechanisms involved and then responding with the proper catalyst technology and design to meet a units objectives. Crucial to the success of reaching record propyl-ene yields is the ability to minimise

hydrogen transfer while having suf cient cracking activity.

Albemarles AFX catalyst has been developed to meet the desired objectives, through its unique features of high catalyst accessibil-ity and strong matrix activity. Hereby, maximum slurry conver-sion is achieved while generating a maximum of gasoline precursors, which are converted in record propylene yields. The high accessi-bility of AFX enables fast diffusion of primary cracking products away from the acid sites, thus minimising unwanted hydrogen transfer.

Q What is the impact of vanadium level on E-cat affecting FCC gasoline sulphur?

A Alan Kramer, Global FCC Additives Specialist, Albemarle, [email protected] Generally, re ners want to avoid loading their catalyst with vanadium due to the known negative effects it has on zeolite stability and catalyst activity. However, increased levels of vanadium in catalysts with higher alumina contents (which typically are more resistant to vanadium) directionally yield lower levels of gasoline sulphur. Testing has indi-cated the vanadium mechanism primarily reduces the saturated sulphur content of the gasoline and has little to no effect on benzothio-phene, which often comprises the bulk of gasoline sulphur. Commercially, vanadium levels need to be increased by at least 1000-2000 ppm on E-cat before differences can be measured. The losses in catalyst activity and negative yield effects related to these large levels of extra vanadium on the catalyst are rarely justi able. Depending on local regu-lations, equilibrium catalyst with high levels of vanadium may be classi ed as hazardous or toxic waste and can be very dif cult and expensive to dispose of properly. Re ners do have other options besides increasing E-cat vanadium or using vanadium-based products for reducing gasoline sulphur. For example, Albemarles R-975 and Scavenger catalyst additives are designed to remove gasoline sulphur and do not contain any vanadium.


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Tower packings, catalyst support material and column equipment.

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Evaluation of a low rare earth resid FCC catalyst

Rare earth metals have played an important role in the refin-ing industry since the 1970s, when it was discovered that they could be used to stabilise the zeolite-Y component of FCC cata-lysts to provide higher activity, as well as being used to influence product selectivity. Rare earth metals play an additional role in resid processing applications, as they have proven to be until now the most effective vanadium trap, helping to maintain stability and activity.

The two main rare earths used in FCC catalysts are lanthanum and cerium, and these metals have historically been readily available for under $5/kg. However, a reduc-tion in Chinese export quotas resulted in rare earth prices rising dramatically in 2010, with the price of lanthanum reaching $140/kg around May 2011. Since then, rare earth prices have subsided some-what, but remain significantly higher than historical levels.

The rare earth market is incredi-bly unpredictable and is expected to remain highly volatile. Against this backdrop of uncertainty with respect to availability and pricing, zero and low rare earth catalysts will continue to play an important role in the FCC industry. Grace Catalysts Technologies provides the REpLaCeR series, the first commer-cially successful zero and low rare earth FCC catalysts.

Zero and low rare earth FCCcatalystsSimply removing rare earth from an FCC catalyst would result in a considerable detrimental effect in

A zero rare earth catalyst blended with a rare earth-based resid catalyst enabled a refinery to reduce its FCC catalyst rare earth requirement by 80%

SABEETH SRIKANTHARAJAH and COLIN BAILLIE Grace Catalysts TechnologiesBERNHARD ZAHNBRECHER and WIELAND WACHE Bayernoil

most FCC operations due to the lower activity and worsening prod-uct yield slate obtained. To develop FCC catalysts containing lower rare earth content, it is necessary for alternative materials and processing techniques to be used that stabilise the zeolite component. Grace has considerable experience developing zero and low rare earth FCC cata-lysts. During the 1990s, it developed Z-21, a rare earth-free stabilised zeolite-Y, which was the basis for the Nexus catalyst family. This was commercialised in 1997 as a rare earth-free catalyst family for low-metal feed applications, and has since been successfully used in 10 applications.

In 2010, the company developed the REpLaCeR series of zero and low rare earth FCC catalysts, which are based on the existing Z-21 zeolite technology, as well as a new Z-22 zeolite technology. State-of-the-art methods are used to stabilise the rare earth-free Z-21 and Z-22 zeolites, involving proprietary stabilising compounds and unique manufacturing processes. FCC cata-lysts incorporating these new zeolites provide similar and even improved performance compared to conventional rare earth-contain-ing catalysts. Based on the Z-21 and Z-22 technologies, the REpLaCeR series of zero rare earth catalysts for low-metal hydrotreating and VGO applications includes REsolution and REactoR, which are currently being used in more than 15 applications.

For resid applications, the devel-opment of rare earth-free catalysts is much more challenging due to the additional demands placed on

zeolite stability. However, signifi-cant advances have been made by applying processing technology involving metals resistance func-tionality to catalyst systems containing the Z-21 and Z-22 zeolites. This has resulted in the rare earth-free REduceR catalyst, which can be blended with rare earth-based resid FCC catalysts, thus reducing the overall rare earth requirement and the costs associ-ated. There are currently 22 refineries using the REduceR cata-lyst, and typically they are applying a stepwise approach to implement the rare earth-free catalyst. Refiners are starting with a blending level of 30% REduceR catalyst and, upon confirming its performance, many are then moving to a blending level of 50%. Bayernoil is using the REduceR catalyst in both of its two FCC units with blending levels even higher than 50%.

Commercial experience of low rare earth resid catalystsThe Bayernoil Vohburg refinery is located in the Bavarian region of southern Germany and, along with the nearby Bayernoil Neustadt refinery, contributes to a total refin-ing capacity of 10.3 million t/y. The two locations combined contain three crude units, two vacuum towers, two FCC units, one mild hydrocracker and hydrogen plant, one visbreaker, three reformers and one ether plant. The FCC unit at Vohburg is a UOP side-by-side model and was built in 1967. It is a resid unit with a typical throughput of 14 000 b/d, operates in deep partial burn and processes 80-90% atmospheric residue. The feedstock


grace.indd 1 23/2/12 12:56:58


require higher catalyst additions, which has not been the case in any application of the REduceR catalyst. Figure 1 shows the catalyst addition rate and e-cat microactivity at Bayernoil Vohburg before and after using the 30% blend. It can be seen that good activity retention was achieved after the switch at a simi-lar or even slightly lower catalyst addition rate, highlighting the high vanadium tolerance of the REduceR catalyst.

Figure 2 shows the e-cat coke and gas factors of Nektor and the 30% REduceR catalyst against nickel equivalents to compare nickel resistance. The 30% REduceR cata-lyst shows lower gas factors and similar coke factors, further demon-strating its suitability for high metal resid feeds. The FCC unit data provided in Figure 3 show that the REduceR catalyst blend provided improved bottoms conversion compared with the Nektor catalyst. In addition, a lower delta coke was obtained, which reduced the regen-erator bed temperature by about 10C. This allowed the refinery to achieve higher conversion at constant feed atmospheric residue content, or to process an increased amount of atmospheric residue at constant conversion.

The refinery considered the performance of the REduceR cata-lyst to be such a success that they increased the blending ratio from 30% to 50%, thus reducing the over-all rare earth content of the catalyst to 1.5 wt%. Table 1 shows the FCC unit product yields obtained with the 50% REduceR catalyst blend compared with the Nektor catalyst. During the REduceR catalyst trial, feed quality deteriorated and feed throughput decreased; therefore, for the purposes of evaluating the actual catalyst performance, the yields shown are calculated on the basis of constant feed properties and independent operating condi-tions. The key objective of the refinery was to maintain conversion and bottoms upgrading while reducing rare earth content. As can be seen, these key objectives were met, and in addition conversion and bottoms upgrading were even increased. The REduceR catalyst

has a Conradson carbon content of 3 wt%, and the e-cat metals levels are approximately 4500 ppm vana-dium, 3500 ppm nickel, 6000 ppm Fe and 5000 ppm sodium.

This Vohburg FCC unit was previously using a Nektor catalyst from Grace containing 3.1 wt% rare

earth, which performed well. In April 2011, the refinery began to blend 30% of REduceR catalyst with the Nektor catalyst, with the simple objective of reducing rare earth while maintaining high perform-ance. A certain misconception about rare earth-free catalysts is that they

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rotcafsaG

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Figure 2 Coke and gas factors of the REduceR catalyst blend at 30%

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provided a similar coke yield but an improved delta coke, and allowed the regen bed temperature to be decreased by 15C. The higher LPG yield at the expense of gaso-line is a consequence of the lower hydrogen transfer from REduceR. This is a positive yield shift for the refinery and was anticipated.

Bayernoil Vohburg was highly


satisfied with the REduceR catalyst trial, and subsequently became the first refinery to move to a 70% blending level, further reducing the rare earth content to 1.0 wt%. In December 2011, the refinery increased the blending ratio of the REduceR catalyst up to 80%, thus reducing rare earth to 0.6 wt%. Despite high nickel and vanadium

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levels, the refinery continues to see excellent performance. It is esti-mated that the switch to the REduceR catalyst has provided the refinery with over 2 million /y cost savings when taking into account catalyst costs and product yields obtained.

GRACE, GRACE CATALYSTS TECHNOLOGIES, REPLACER, RESOLUTION NEKTOR, NEXUS, REDUCER and REACTOR are marks of W R Grace & Co.-Conn.

Colin Baillie is Marketing Manager with Grace Catalysts Technologies EMEA and holds a masters degree and PhD in chemistry from the University of Liverpool, UK. Email: [email protected] Srikantharajah is Technical Service Manager at Grace Catalysts Technologies EMEA. He holds a diploma in chemical engineering from the University of Munster. Bernhard Zahnbrecher is Process Development Engineer for FCC with Bayernoil. He holds a university diploma in chemical engineering. Wieland Wache is a Process Engineer in the Production department at the Bayernoil Refinery in Vohburg. He holds a diploma in chemistry from the Technical University Aachen and PhD in chemical engineering from University Bayreuth.

Figure 3 FCC unit data of the REduceR catalyst blend at 30%

Nektor 50% Nektor 50% REduceRCat-to-oil, g/g Base Base + 0.4Conversion, wt% Base Base + 0.5Hydrogen, wt% Base Base + 0.02C

1+C

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Propylene, wt% Base Base + 0.4C

4 olefins, wt% Base Base + 0.6

LPG, wt% Base Base + 2.0Gasoline, wt% Base Base - 1.6LCO, wt% Base Base - 0.2Slurry, wt% Base Base - 0.2Coke, wt% Base Base - 0.1Delta coke, wt% Base Base - 0.09CAR, MT/D Base BaseFeed Ni, ppm Base BaseFeed V, ppm Base BaseRegen bed temp, C Base Base - 15C

Calculated FCC unit data of the REduceR catalyst blend at 50%

Table 1

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Refinery fuel gas in steam reforming hydrogen plants

Operators of steam reform-ing-based hydrogen plants want feedstock options to minimise operating costs and maximise operational flexibility. Consequently, new-build hydrogen plants are often designed for a number of hydrocarbon feeds. It is common to have three or four feed-stocks ranging from offgases through to naphtha requiring full operational flexibility across the range.1,2 Operators of existing plants are also evaluating alternatives to the original feedstock slate and in some cases implementing changes that may necessitate modification of the plants operating conditions, hardware, equipment, catalyst selection and so forth.3-6 The quest for cheaper feedstock options is undoubtedly heightened by the significant increases in both natural gas and crude oil prices in the last few years, although the emergence of shale gas production has reversed this trend in certain areas. A feed-stock option being considered increasingly by hydrogen plant operators associated with oil refin-eries is the refinery fuel gas (RFG) pool. Relative to imported natural gas and many other hydrocarbon streams and offgases in the refinery, RFG has a comparatively low value. Thus, RFG represents an attractive feedstock option where there is excess RFG available.

RFG is not widely used as a hydrogen plant feed. This is because its composition leads to a number of difficulties in process-ing in the feedstock purification and steam reforming sections of the hydrogen plant flowsheet. In this article, we will explore these

Fuel gas is an attractive feedstock for hydrogen production, but appropriate catalysts and temperature control are needed to address high olefin levels

Peter BrOadhurst and Graham hintOnJohnson Matthey Catalysts

difficulties and the strategies for hydrogen plant design and opera-tion, which may be used to allow processing of RFG as a feedstock. This will include some recently developed catalytic and control solutions developed jointly by Johnson Matthey and Air Products & Chemicals.

rFG composition and processing difficultiesRFG is a combination of refinery unit waste or by-product gases, often referred to as offgases. The offgases that are sent to the RFG pool are those that cannot be proc-essed elsewhere in the refinery either because of the composition or because there is an excess availa-ble. The offgases in the RFG come from various refinery unit opera-tions (catalytic reforming, FCC, hydrotreating, coking), the availa-bility and amount of which will depend on the refinery operation.

Hydrogen-containing offgases may be partly or fully used in hydrogen-consuming units or may be treated to recover the hydrogen in a membrane or PSA unit so that a hydrogen lean gas is available to the RFG pool. Also, offgases or offgas blends with high olefin levels may be treated to recover olefins, with the olefin lean gas going to the RFG pool. Thus, RFG can differ significantly between refineries. Examples of RFGs, which have been proposed for hydrogen plant feeds, are shown in Table 1. This shows the substantial variations in: hydrogen, from 11-35 mol%; meth-ane, from 2665 mol%; and olefins, from 2.615.9 mol%.

RFG feeds often contain quite high levels of sulphur compounds. Up to 100 ppmv can be found and this can contain quite a significant proportion of mixed organic sulphur compounds. The level and speciation are necessarily


mol% example 1 example 2 example 3 example 4 example 5 example 6Hydrogen 34.9 10.8 25.5 34.1 13.9 14.4Methane 26.3 64.9 34.8 45.3 43.2 42.3Ethane 11.0 13.4 23.5 8.2 12.2 13.7Propane 9.5 2.5 5.2 3.2 8.3 6.8Butanes 7.1 1.4 3.2 1.4 0.3 4.4Pentanes 0.0 0.2 0.5 0.6 0.3 1.5Hexanes 0.0 0.3 0.9 0.2 0.3 0.6Ethene 3.8 3.1 3.4 1.5 7.2 6.6Propene 2.1 0.5 0.6 0.9 8.3 6.7Butenes 3.0 ~ ~ 0.2 0.3 0.3Pentenes 0.0 ~ ~ ~ 0.1 TraceNitrogen 1.9 1.8 1.9 3.7 4.5 2.2Argon ~ ~ ~ Trace Trace ~Oxygen Trace ~ ~ ~ ~ ~Carbonmonoxide ~ 0.3 0.3 0.3 1.1 TraceCarbondioxide 0.4 0.8 0.2 0.4 ~ 0.5Total 100.0 100.0 100.0 100.0 100.0 100.0

rFG compositions considered for hydrogen plant feed

table 1

j matthey.indd 1 23/2/12 13:02:52


the inlet olefin level to an accepta-ble level. This approach has some disadvantages. Depending on the inlet olefin level and therefore the extent of dilution required, the recycle can be substantial. This increases capital expenditure in a number of ways: the recycle flow usually increases the vessel size to stay within design space velocity design limits and additional equip-ment is needed such as a recycle cooler and circulator.

Without a recycle system, there is limited flexibility in terms of the olefin level using standard HDS catalyst types, so approaches that widen the operating envelope with-out installation of a recycle system will be beneficial. One such approach that Johnson Matthey has recommended is to use a Katalco higher activity catalyst. This has a higher active metals loading and allows operation at inlet tempera-tures down to ~250C (462F) with the same exit temperature limit of 400C (752F). Thus, the amount of olefins that can be processed with-out installation of a recycle system is increased to 78 mol%, depend-ing on the precise composition of the feed in terms of heat release and specific heat.

This concept has been extended to form part of the technology claimed in recent patent applica-tions filed jointly by Johnson Matthey and Air Products & Chemicals7 and which is available for licence. Detailed evaluation of a typical range of RFG feed composi-tions established that the extremely active pre-sulphided Katalco prod-uct allows the olefin hydrogenation reaction to strike below 150C (302F). This widens the operating temperature envelope to over 250C (450F) and allows the processing of feeds containing well in excess of 10 mol% olefins.

It is imperative, however, that the consequences of the changes in operating temperatures are fully considered if this is to be retrofitted into an existing reactor to accom-modate a higher olefin feed.

An alternative approach is to use a tube-cooled converter.8 The heat of reaction is removed on the shell side of the converter using water,

dependent on the blend of gases going to the RFG pool.

Additionally, the RFG composi-tion can fluctuate significantly in a given refinery as rates on different units change and particularly if a unit comes off line. The amount of offgas available to the RFG pool changes and so impacts on the composition of the blend, which comprises the RFG. This presents control issues in some cases.

In terms of incorporating RFG into the hydrogen plant feed slate, the aspects that may cause difficul-ties can be summarised: High olefin levels Variability in the RFG composi-tion as the blend of offgases changes High hydrogen levels Significant sulphur levels Substantial levels of higher hydrocarbons, which may include naphthenes and/or aromatics Less usual trace and minor components.

Not every RFG will present each of these difficulties and each case must be considered separately. If a new-build hydrogen plant is being considered, it must be designed to include any RFG feed case(s). When considering using RFG on an exist-ing plant, the extent to which there is a problem will be influenced by the original design basis.

Feedstock purification sectionRFG feeds can cause various issues in the feedstock purification section.

High olefin levelsOlefins need to be removed from the hydrocarbon feed in a hydrogen plant to a level below 1 mol% to minimise possible olefin-derived carbon formation in the steam reformer, although higher levels may be acceptable where there is a pre-reformer in the flowsheet. The hydrodesulphurisation (HDS) cata-lyst is also an effective olefin hydrogenation catalyst and removes olefins almost completely as long as there is sufficient hydrogen present. Thus, for RFGs with significant olefin levels, the hydrogen available in the feed and as recycle must be sufficient for the olefin

hydrogenation reaction, other hydro-gen-consuming reactions and to provide the target hydrogen level specified at the HDS converter exit. Johnson Matthey recommends a different level of hydrogen be present in the HDS effluent, depend-ing on the feed composition and how heavy it is. For the gases given as examples 5 and 6 in Table 1, insufficient hydrogen is present in the RFG on its own to hydrogenate the significant olefin content. This means that additional hydrogen must to be added, usually recycled to the purification section of the plant, of approximately 5 mol% of the RFG feed rate for example 5, and approximately 3 mol% of the RFG feed rate in example 6.

Olefins hydrogenate exothermi-cally over the HDS catalyst and the temperature rise can be 20+C (36F) per mol% olefin, depending on the heat capacity of the feed gas. The inlet temperature must be adjusted to ensure that the maxi-mum HDS bed temperature remains below 400C (752F). However, using standard HDS catalysts, such as Katalco 41-6T or Katalco 61-1T, the inlet temperature needs to be above 300C (572F) to provide sufficient activity for reactions to initiate. Given the need for some operating margin inside these restrictions, this limits the olefin that can be processed to a few mol% in a once-through reactor system.

To process higher olefin levels, a recirculation system is usually employed around the HDS reactor (see Figure 1). The reactor effluent is olefin free so the recycle dilutes

Cooler

Recirculator

Figure 1 HDS converter with recirculation

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and the temperature in the catalyst packed tubes is maintained in the required range. The reactor is not truly isothermal, as the heat release is sufficiently fast for the tempera-ture to rise in the reaction zone within the tubes before the coolant brings the temperature back down. This approach has been commer-cialised in at least one plant.

Variability in the RFG compositionAs refinery unit operations change rate, come off line or back on line, the RFG composition can fluctuate. This can make step changes in the gas going forward to the hydrogen plant and can cause control issues, particularly where there is a substantial olefin content in the feed. If the olefin level increases sharply, it is possible that the 400C (752F) upper limit for HDS operating temperature might be exceeded. Also, if the inlet temper-ature has been lowered to well below 300C (572F) to allow for the hydrogenation exotherm, and the olefin level decreases sharply, the exotherm will collapse, which may lead to organo-sulphur slip. In both cases, the HDS inlet temperature needs to be adjusted quickly in response to the change in RFG composition.

A control system concept has been developed to allow this to happen.7 There is a rapid feedback system from changes in the HDS bed exotherm into the upstream feed preheat so that the tempera-ture in the catalyst bed can be controlled within acceptable limits.

Another possible problem is if the hydrogen level in the RFG decreases suddenly to a point where there is insufficient to hydrogenate olefins (and any traces of oxygen and the expected organo-S compounds) in the feed. Additionally, the recom-mended HDS exit hydrogen level should ideally be maintained. If a rapid decrease in feed hydrogen level occurs, another source of hydrogen, probably recycle hydro-gen, needs to be rapidly established. If not, the consequences could be slippage of olefins and/or sulphur compounds to the steam reforming section, with resulting carbon formation and/or poisoning.


High hydrogen levelsSome RFG blends may contain a significant amount of hydrogen. In some circumstances, this might provide a driving force for side reactions over the HDS catalyst if the RFG unusually happened to contain extremely low sulphur levels. The undesirable side reac-tions are methanation, which would also need a substantial amount of carbon oxides present, and hydroc-racking, which would need heavier alkanes present. Both are very rarely observed and are associated with operation at transient or abnormal operating conditions (for instance, low flow, very low sulphur and excess temperature). Methanation and hydrocracking activity can be significantly suppressed by pre-sulphiding the HDS, an effect that is also achieved if there is a reasonable level of sulphur in the feed.

Significant sulphur levelsRFG blends can contain significant sulphur levels, of which much may be present as organo-sulphur compounds. As long as the maxi-mum and typical levels are known and there is speciation of the sulphur, new plants can be designed appropriately.

Existing plants may have been designed for a lower level of and/or less difficult organic sulphur compounds so that conversion in the existing HDS converter may not be possible. There are three retrofit options depending on the addi-tional HDS capacity needed: Replace the existing HDS catalyst with a higher activity version (for instance, replace Katalco 41-6T or Katalco 61-1T with Katalco 61-2F) Install a combined product, which delivers HDS activity and H2S absorption (such as Katalco 33-1) in the downstream H2S removal beds Replace the existing HDS converter with a larger vessel.

If the total sulphur level is higher than the original design, the life of the H2S removal beds will be short-ened. If the design features lead-lag H2S removal beds, allowing change-out on-line, the consequence is more frequent change-out. Selection of the highest capacity H2S removal

absorbents (for instance, Katalco 32-5) can lessen the change-out frequency. The problem can be greater if the design has only a single H2 S removal bed built to last between turnarounds, where it is possible the increased sulphur level will not allow operation for the normal interval. Higher capacity absorbents may help, but a retrofit of a second vessel may be required.

Substantial level of higherhydrocarbonsIn the event that the RFG contains higher hydrocarbons, there may be an increased tendency for thermal cracking in the feed preheat coil. The carbon formed can carry forwards and deposit on top of the HDS catalyst, leading to an increased pressure drop over time and some deactivation if the top catalyst becomes coated with carbon. If this problem is observed, it can be mitigated by replacing the hold-down balls on top of the cata-lyst with a high-voidage shape, such as Dypor 604, which has more capacity for the carbon foulant, before the pressure drop becomes critical.

Less usual trace and minorcomponentsThere are a number of other species that can be present in a refinery offgas stream and which, therefore, could find their way into the RFG. These include chlorides, arsine, oxygen, acetylenes and dienes.

Chloride can be dealt with by hydrogenation of any organo- chlorides over the HDS catalyst followed by the removal of HCl using an HCl removal absorbent such as Katalco 59-3. This must be placed upstream of the ZnO-based H2S removal absorbent. In existing plants, it may be necessary to retro-fit this into the purification section, usually by putting it on top of the H2S removal absorbent.

Arsine will be removed on the surface of the HDS catalyst and acts as a poison. If present, levels are likely to be sub-ppm and the effect on the HDS catalyst is minimal. For a new plant design, the volume of HDS catalyst would be increased slightly to allow for the absorption

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temperature as the PSA unit goes through its cycles. Additionally, if RFG is being used as the feed to the plant, it is likely that the trim fuel type will also have changed. This will necessitate that the suitability of the burners is checked to fire this new fuel type with good control and flame stability.

Significant sulphur levelsWith proper design and operation, sulphur should be removed in the feed purification section.

Substantial level of higherhydrocarbonsIn new plant designs, the selection of steam reforming technology and catalysts should take account of the RFG composition. In existing plant with non pre-reformer flowsheets, the impact of a heavier hydrocar-bon component in the feed must be assessed in case a change in steam reforming catalyst is required to cope with the heavy component in the RFG. As mentioned above, this may necessitate an increase in the steam-to-carbon ratio for the plant, a reduction in reformer outlet temperature or even a change in steam reforming catalyst type.

Less usual trace and minor componentsWith proper design and operation, these should be removed in the feed purification section.

Variability in the RFG compositionThis presents possible problems for the steam reforming section if there is not sufficient control. If there is a sudden decrease in olefins causing the HDS exit temperature to decrease, slip of organo-sulphur is possible, which would poison the pre-reformer or steam reforming, whichever is first in the flowsheet.

If there is a sudden decrease in hydrogen, there may be insufficient to hydrogenate olefins and/or organo-sulphur. The resulting slip could lead to sulphur poisoning and carbon formation in the pre-reformer or steam reforming, whichever is first in the flowsheet.

ConclusionsWhile RFG is an attractive economic


of arsenic and associated poisoning of the HDS catalyst at the bed inlet.

Oxygen will be removed by hydrogenation over the HDS catalyst. This is a very exothermic reaction and so the temperature rise and hydrogen consumption must be taken into account in addition to any from olefin hydrogenation.

Acetylenes and dienes may be present at low levels. There is some evidence that these may polymerise in the feed preheat or HDS converter, leading to carbon deposi-tion. This is unlikely to be a major issue as long as the level remains at low ppm levels so that any pressure drop rise and catalyst deactivation caused by the carbon is very slow.

Steam reforming sectionSome considerations and impacts for the steam reformer and associ-ated equipment need to be considered.

High olefin levelsWith proper design and operation, olefins should be converted in the feed purification section. However, levels of up to 1 vol% olefins can be accommodated in the feed to a steam reformer.

High hydrogen levelsThe process duty in the reformer may be lower for feeds with high hydrogen levels compared to other feeds such as natural gases. This is because there is less endothermic steam reforming reaction in order to generate the same quantity of hydrogen. Additionally, since the feeds are more hydrogen rich than a natural gas, less feed flow may be needed in order to produce the same quantity of hydrogen. However, even though the feed is more hydrogen rich than a typical natural gas, the average carbon number can be higher, meaning

that the tendency for carbon forma-tion within the reformer is also higher. This may necessitate either an increase in steam to carbon, a reduction in outlet temperature, or a change in the steam reforming catalyst type. This is discussed further below.

All of these effects are shown in Table 2. In the table, the reformer heat load for constant hydrogen production has been calculated, assuming that no other process parameters are changed (inlet and outlet temperatures, steam-to-carbon ratio and reformer outlet pressure). The second row of the table shows how the molar flow of the RFG in question will compare to the molar flow of a typical natu-ral gas for the same hydrogen production rate.

In a new plant design, all these factors can be taken into account. If introducing such a feed to an exist-ing plant, however, these factors and implications arising from them need to be taken into account and reviewed. The reduction in reformer heat load will have a number of consequences. The first, and most obvious, is that the firing on the reformer box must be reduced. This means that the bridge wall temper-ature will reduce, the flow rate of combustion gases will reduce and the amount of heat available to be recovered in the flue gas duct will be less. Hence, there is the possibil-ity that some of the coils may become pinched, leading to a reduc-tion in steam production or in combustion air preheat tempera-ture. Second, if the plant is a modern PSA hydrogen plant in which the PSA tail gas is used as the major fuel source on the reformer, it is possible that the trim fuel requirement is dropped to a level where there are control issues in maintaining the reformer outlet

Table 2

Natural Example Example Example Example Example Example gas 1 2 3 4 5 6Reformer heat load, % 100 93.4 97.8 94.2 89.6 99.9 99.5Feed flow, % 100 76.2 88.4 81.6 109.7 69.6 64.5Average carbon no. 1.06 2.09 1.34 1.76 1.42 1.71 1.85

Impact of varying feed composition on feed flow and reformer heat load

Table 2

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option for hydrogen plants associated with refinery operations, its processing presents challenges in the feedstock purification and steam reforming sections of the flowsheet. These challenges result from the composition of the RFG and also from its variability.

In the feedstock purification section, the range of options for handling the high olefin levels often found in the RFG pool has been expanded in recent years by consid-ering more active catalysts and heat exchange reactors. In conjunction, control systems have been devel-oped to allow the HDS converter operating temperature to be adjusted as the feed composition changes to maintain the tempera-ture within the acceptable range for successful operation.

In the steam reforming section, the impact of the change in feed and fuel type needs to be modelled and understood. There may be minimal impact associated with the change but, conversely, there may


be changes required in operating parameters, catalyst type, heat exchanger performance or even heat exchanger design, as well as consideration given to any neces-sary changes in control schemes.

KATALCO is a mark of the Johnson Matthey Group of Companies

References1 Cromarty B J, Hydrogen Market Review, Synetix Technical Paper, 1999.2 Ratan S, Hydrogen Technology Overview, Proceedings of 6th International Conference on Refinery Processing, AIChE Spring National Meeting, New Orleans, Apr 2003.3 Chlapik K, Slemp B, Alternative Lower Cost Feedstock for Hydrogen Production, NPRA Annual Meeting, San Antonio, 21-23 Mar 2004.4 Winsper A J, Irizar I C, The Study on the use of Butane Feed for the Repsol-YPF La Coruna Hydrogen Plant, ERTC 11th Annual Meeting, Paris, 13-15 Nov 2006.5 Cotton W J, Singh V, Feedstock Conversion for Indian Ammonia Plants. A Review of the Challenges, Proceedings of Fertilizer Association

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