2012 ptq q4__

special features

Gas processinG developments

mass transfer

refininGGas processinGpetrochemicals

petroleum technology quarterly

ptqQ4 2012

cover and spine copy 13.indd 1 12/9/12 16:47:43

Hydrogen plant efficiency is paramount to optimal refining operations. With Topses steam reforming expertise it is possible to futher optimize your hydrogen production:

To ensure economical production it is important to consider factors such as

- feedstock flexibility

- capacity control

- value of steam as by product

in the design and process layout.

Topses complete range of hydrogen technologies and catalysts ensure options for increase of efficiency and reduction of the CO2 footprint.

Design your plant layout to determine your energy efficiency and carbon emissions

Choose your footprint

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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 Buying the store ChrisCunningham 5 ptq&a 19 Processing Trends25 Challenges and opportunities of 10 ppm sulphur gasoline: part 2 DelphineLargeteau,JayRoss,MarcLabordeandLarryWisdomAxens

33 Dynamic simulation: a tool for engineering problems DipanjanBhattacharya,HaribabuChittibabu,JesseMummandJaleelValappil Bechtel

47 Exploiting opportunities with challenging crudes IndiaNagi-hanspal,MaheshSubramaniyam,ParagShah,SergioMoretti andJamesNolandDorf Ketal Chemicals

57 Valuable liquids from refinery gases ZaheerMalikandJohnSlack Linde Process Plants

69 Thermal oxidiser waste heat recovery RyanTate Zeeco, Inc

77 Simulating and monitoring H2 plant operations

GeneYeh Saudi Aramco PrabhasMandal,AbdulaliSiddiquiandFahadAlhemidda Saudi Aramco Riyadh refinery

83 RFCC units set new standard for propylene production PatrickWalkerandRaymondPeterman UOP LLC, a Honeywell Company

95 Value of monitoring exchanger networks LauraCopeland Nalco Company

99 FCC catalysts and additives for cost and emissions control KennethHindleandMariaLuisaSargentiGrace Catalysts Technologies JuanVargas Coryton Refinery

105 Stripping sour water: the effect of heat stable salts RalphWeilandandNathanHatcher Optimized Gas Treating, Inc

111 Production of biolubricant base stock ShaliniGupta,RajeevKumar,SudhaTyagiandPeddyVCRao Bharat Petroleum Corporation

119 Mitigation of heat exchanger fouling BruceWright Baker Hughes Incorporated ToddHochheiserValero Energy Corporation

127 Innovations in wastewater treatment DarrenGurneyLinde Gases Division

135 Optimising sweep gas flow in a flare header SatishMathur Bechtel India

141 Industry News

MarathonPetroleumsGaryville,Louisiana,refineryprocesses490000b/dofprimarilyheavy,sourcrude. Photo: Marathon Petroleum

Q4 (Oct, Nov, Dec) 2012www.eptq.com

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

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

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

PTQ Q4 2012 3

Editor Chris Cunningham [email protected]

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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 5

Q4 (Oct, Nov, Dec) 2012

Buying the store

Oil refining used to be such a predictable business: a Big Oil logo on the front gate and operations tweaked to convert crude to meet local domestic demand and to supply contract customers. Not any more: the name on the gate increasingly reflects a shift away from traditional ownership as selected majors move out of refining. And the emergence of US Gulf Coast refineries as leading exporters of fuel products a job that was supposed to be the preserve of the Middle East has certainly altered their image as servicers of local markets.

The biggest, and by far the least welcome, development in recent times has of course been refinery closures. Sites in Europe and the Caribbean are being transformed for the time being at least into terminalling operations. That is not much of a trend for the Atlantic-bordering industry to look for-ward to. Another development, perhaps the start of a trend of sorts, concerns change of ownership and partial change of use. Perhaps it would be more precise to say change of emphasis. Delta Air Lines took control of its own refuelling destiny when it purchased the idled Trainer, Pennsylvania refinery in June. Effectively, the customer took over the store in a bid to assure sup-plies of jet fuel at stable prices and to give it a potential edge over competi-tors. A refinery set up to produce exceptional quantities of jet, with an owner committed to keeping jet prices down through targeted crude sourcing, could well deliver an advantage in airspace. After all, with jet prices surging recently, who wants to be first to ramp up fuel surcharges when the choice of carriers remains competitive?

The purchase price of the plant was $180 million and Deltas operating sub-sidiary, Monroe Energy, plans to spend around $100 million on upgrades that will take jet production past 30% of its overall output, at the expense of gaso-line production. Aiming to have the plant in operation by the end of September, following a years shutdown, the new owner is also looking to resolve some of the general upward volatility in jet prices by, for the first time, taking control of refinery raw materials. Like other beleaguered east coast sites, Trainer was reliant on imported North Sea supplies when ConocoPhillips was in charge. With Brent crude trading at a hefty premium to North American domestic supplies, Monroe wants to switch to supplies of North Dakota crude as a key element of its plan to lop $300 million from a near-$12 billion bill for jet last year. Monroe has signed a three-year crude supply deal with BP that includes guarantees of jet supplies from BPs own refineries and there is a similar supply deal with Trainers previous owner, Phillips 66.

Jet fuel is also high on the slate at Saudi Aramcos new 400 000 b/d refin-ery in Jubail, where the first of the sites crude distillation units is expected to be operational by the end of 2012. Jet and diesel are expected to account for 54% of output when the refinery reaches its scheduled full output, late in 2013. With two further mega-refineries on the way, Saudi Arabia is aiming for self-sufficiency in fuels, with a portion of its output reserved for the busy international market for products. Saudi Arabia has managed to grow its economy over recent years, hence air miles have risen in number. The new refineries should ensure that its airports can operate without relying on ship-loads of imported jet.

CHRIS CUNNINGHAM

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I can sum up my favorite part about this job in one word: Eureka!

Meet John Smegal:Amateur Detective. Senior Chemist.

Even after 27 years in the industry, John Smegal still gets excited at the mere suggestion of discovering the next big breakthrough in catalyst technology. His proclivity towards discovery helped lead to the development of more than twenty catalysts, including CRITERIONs industry game-changers, CENTINEL and CENTERA. And while today youll find John managing the hydrocracking pre-treat and distillate hydrotreating teams, his favorite moments are still created in the lab - testing countless hypotheses for that exciting next discovery.

www.CRITERIONCatalysts.com

Leading minds. Advanced technologies.

criterion.indd 1 11/9/12 11:23:20

Q Can I have some advice on selection of catalyst for running my FCC pretreat in mild hydrocracking (MHC) mode, with particular reference to HDS and HDN requirements?

A Eelko Brevoord, Technical Services Manager, Refining Catalysts, Albemarle, [email protected], MHC units were simply traditional VGO hydrotreating units that were operated at a high temperature. More recently, units and catalysts have been designed and developed specifically to boost conversion.

MHC units are characterised by a relatively low pres-sure (50-100 bar). Consequently, product nitrogen is relatively high, making zeolitic cracking catalysts much less effective than in full-pressure hydrotreaters. At high product nitrogen (>200 ppm), conversions of up to 25% are usually achieved. The main catalyst for this situation should allow a refiner to achieve their product quality targets, while meeting their required cycle length. For example, CoMo catalysts are often selected for maxi-mum sulphur removal, while NiMo catalysts have the best hydrogenation activity and can yield an uncon-verted product, giving the best conversion in FCC. Trimetallic NiCoMo catalysts have often been used to provide a balance of high HDS activity without sacrific-ing too much HDN activity, especially in low-moderate pressure applications. Replacing some of that catalyst with an amorphous or zeolitic cracking catalyst can boost the conversion in the MHC unit by a few per cent.

Some MHC units are capable of reducing product nitrogen to much lower levels. By applying zeolitic cracking catalysts, conversions of 30% to 50% can be achieved. In these cases, diesel selectivity is very high, increasing diesel production over gasoline. Upstream of the zeolitic catalyst, pretreat catalysts should have sufficient HDS and HDN activity and adequate stabil-ity to achieve the required cycle length. The HDS and HDN activity needs to be tuned to achieve product quality targets, while also sufficiently reducing the nitrogen to make effective use of the zeolitic cracking catalyst. Demetallisation catalysts may be recom-mended to cope with feed contaminants.

Albemarle has considerable experience in this area and can assist in assessing the possibilities of running the FCC pretreater in conversion mode. We typically recommend an investigation of the impact of the pretreater operation on the FCC unit in order to opti-mise the refinerys overall profitability.

A Robert Wade, Advanced Refining TechnologiesThere are a number of considerations when designing

a catalyst system for MHC service. This mode of opera-tion tends to have higher fouling rates than conventional high-pressure hydrocracking (HCU) service and also has two competing constraints compared to a single constraint for the typical high- pressure service. In a MHC operation, cracking conversion is controlling at the start of run (SOR) and, as the hydrotreating (HDT) catalyst deactivates as the run progresses, HDS and HDN conversion tends to become controlling. It is therefore critical to understand how the H2 partial pressure varies throughout the run and the impact this has on the expected fouling rate of both the HDT and HCU catalysts. In addition, it is important to have a good understanding of the nitro-gen slip to the HCU catalyst so that the activity of this catalyst is properly balanced against desired selectivity. Achieving the proper balance of HDS/HDN activity and cracking activity is a challenge and the system is best customised on a case-by-case basis. The addition of HCU catalyst to the system decreases the volume of HDT catalyst, impacting overall HDS and HDN activ-ity. Typically, current-generation, high-activity HDT catalysts are recommended in these services to maxi-mise HDN activity (minimise nitrogen slip to the HCU catalyst) and provide sufficient HDS activity to meet product sulphur targets. The volume and type of HCU catalyst needs careful consideration to provide the desired conversion and minimise the production of excess gas and naphtha. This is especially important as the cycle progresses and the reactor temperatures approach end of run (EOR). As mentioned above, this is a complex process requiring a tailored catalyst system that is best designed by working closely with the catalysts supplier.

A Kevin Carlson, Business Development Manager, Criterion Catalysts & Technologies, [email protected] and Aristides Macris, Licensing Technology Manager, Shell Global Solutions, [email protected] at our existing FCCPT/FCC complexes, the pretreat unit objectives have tended to change over the past decade with the move to clean fuels production. In the past, the FCC PT units overall value proposition has been a combination of environmental compliance via sulphur removal and increased FCC yields. During the period of 500 ppm sulphur diesel and 300 ppm sulphur gasoline production, the pretreat objectives were often set to produce either a side-draw blendable low-sulphur diesel stream or resultant on-spec FCC naphtha product, or both, with the bonus being improved FCC yields via aromatic saturation and

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Q&A copy 12.indd 1 11/9/12 13:22:53

nitrogen removal. The extent of FCC yield improve-ments were often a function of desired operational cycle life and available hydrogen for the pretreat units. Hydroprocessing catalyst systems were developed util-ising cobalt molybdenum (CoMo) and nickel molybdenum (NiMo), depending on these objectives and constraints.

In todays clean fuel operations, much investment has been made in ULSD and FCC naphtha HDS, with few refiners now achieving environmental compliance via previously designed pretreat units. Additional results of the global drive towards clean fuels are continued advances in catalyst technology that have provided significant gains in both HDS and HDN performance. These technology gains are being utilised to drive new FCC pretreat designs to very high levels of performance and have provided refiners with the option of revisiting how best to maximise the value of existing FCC pretreat units. This has resulted in many units shifting catalyst system designs in order to provide higher levels of nitrogen removal and aromatic saturation by using more high-activity NiMo catalysts, maximising FCC conversion capability.

If distillate maximisation is desired, many FCC pretreat units can be revamped to effectively operate in a MHC mode. This more severe operation is performed with higher reactor temperatures and often by modify-ing the catalyst system to include a more active

conversion catalyst such as an amorphous silica-alumina (ASA) or zeolite.

Depending on the conversion and distillate selectiv-ity required, all alumina, alumina/ASA or alumina/ zeolite stacked systems can be considered. Higher conversions can be achieved by using alumina/ASA stacks and even higher by using alumina/zeolite stacks compared to a total alumina system. In specifying a MHC catalyst system, the balance of hydrotreating versus cracking catalyst and the potential addition of reactor volume is largely influenced by feed qualities and the desired level of conversion. As many of the feeds processed are high in contaminant metals, sulphur and nitrogen, the pretreat section is required to remove these contaminates to ensure a sufficient cycle life can be maintained while both meeting any product targets and minimising nitrogen slip into the cracking section of the reactor. Feed quality and the reactor and catalyst system specified determine the ultimate sulphur and nitrogen removal capability for a given cycle life. HDS functionality can remain an important criteria for some MHC units depending on existing product specifications, which are dependent on site refinery constraints and capabilities. However, HDN capability is often more important, as it influ-ences cracking catalyst selection and performance due to the remaining nitrogen heteroatoms, which reduce cracking reactions. As mentioned, zeolite-containing products can provide the highest levels of conversion, but they tend to be the most sensitive to nitrogen slip, reducing their long-term effectiveness in such cases. Amorphous silica alumina (ASA) cracking catalysts provide increased levels of nitrogen tolerance with a lower level of conversion capability and, for units with limited HDN capability, conventional pretreat catalyst can be operated in a MHC mode but with a reduced conversion capability.

Q Can we use desalter water for coke cutting or are there better recycling options for the task?

A ITW Marcello Ferrara, Chairman, ITW, [email protected] using desalter water for coke cutting, you should at least consider some major problems related to water composition: entrained salts; entrained caus-tic; and entrained sludge and sediments. Entrained inorganics might have an impact on the metallurgies of the cutting tool, coke drum and lines, together with potential salts precipitation in the cutting tools nozzles. Some mitigation of such phenomena might be found in acidification and/or anti-scalant injection, but all of that needs to be carefully evaluated.

Also consider that caustic, oil carry-under and chem-icals might act as emulsifiers and can potentially stabilise the frothing of coke particles, preventing/limiting their precipitation in the water recovery system and creating coke particles carry-over in the cutting tool, which, in turns, creates plugging and possible erosion/corrosion.

6 PTQ Q4 2012 www.eptq.com

: CZlhgLfbma%;:L?K^gbg`:]]bmbo^lFZgZ`^k%CZlhg'd'lfbma9[Zl_'\hfRapid changes in fuels supply and demand can move the relative pricing of a refiners products quickly. As a result, a refiner may find themselves with a non-optimal catalyst and non-optimal unit performance. Operational changes can be made, but will only result in incremental performance changes. For high turnover units, changes in catalyst formulation might be able to keep up these rapidly changing product goals. However, most units would be more likely to benefit from the use of co-catalysts offered by BASF.

Co-catalysts are a standalone product category providing the refiner with the flexibility to change the product slate of the FCC without changing the FCC catalyst. These products are added at rates of 10-40% of the catalyst feed and fundamentally change the performance of the FCC unit in a short period of time.

LCO production could be increased through opera-tional changes: decreased riser outlet temperature, decreased catalyst activity, increased feed preheat and increased HCO recycle. However, these changes do not necessarily improve the profitability of the FCC due to the resultant increase in bottoms product and loss of product volume. Only a change in catalytic performance can definitely increase FCC profitability for LCO maxi-misation. Changing the catalytic performance allows for increased LCO selectivity lower bottoms make and

can maintain profitable product volume and value. A catalyst reformulation could provide this change in cata-lytic performance, but this takes too long to capture the advantage of the rapidly changing economics.

Similarly, gasoline production can be influenced quickly and most effectively using a maximum conver-sion co-catalyst as opposed to operational adjustments and base catalyst changes. Gasoline yield is maximised while maintaining high throughput and coke selectivity.

In one commercial example, HD Ultra, BASFs maxi-mum LCO co-catalyst, replaced 30% of the catalyst feed, increasing matrix activity and stability. The resul-tant product slate saw a 2% increase in LCO and a 2% reduction in slurry. In another commercial example, Converter, BASFs maximum gasoline co-catalyst, replaced 20% of the catalyst feed. Slurry oil decreased by 4.5%, while conversion jumped by 5.2%, gasoline grew by 3.5% and LPG increased by 2.1%. Co-catalysts quickly changed the product slate at these refineries to maximise profitability. Further examples can be found in the 2010 NPRA paper AM-10-110: Co-catalysts Provide Refiners with FCC Operational Flexibility.

While operational changes are quick, they have limited ability to change unit performance and may have undesirable trade-offs. Base catalyst formulation can provide fundamental unit performance changes, but they often take too long to be of use in a changing market. Usage of either a maximum gasoline co-catalyst or a maximum LCO co-catalyst allows refiners to rapidly change unit performance and capture the most favourable economics at all times, maximising FCC profitability.

J P^Zk^ mZk`^mbg`fZqbfnfikhire^g^ikh]n\mbhg _khfma^?kb\'Khblbg9:q^gl'\hfWhen increasing the propylene yield, the gasoline production will reduce. The gasoline properties will change as follows: Olefin content will stay relatively constant Aromatic content will increase significantly and could be a constraint in the gasoline pool RON will increase; with conventional maximum gasoline operation, FCC gasoline will reach around 92 RON. When the propylene yield is at 10 wt%, 94-95 is very common. As a consequence, the gasoline pool will require less reformate or lower severity reformate. It will have a positive effect on the aromatic content in the pool and could compensate the additional aroma-ticity of the FCC gasoline RVP will increase slightly because the content of C5 in the gasoline will increase.

In order to address the last point on RVP, Axens advises considering adding a TAME unit or an oligom-erisation unit on the C5 cut downstream Prime-G+ first step, which constitutes an ideal feed pretreatment

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Q&A copy 11.indd 2 1/6/12 12:56:11Q&A copy 12.indd 2 11/9/12 13:23:03

Refners worldwide use our hydroprocessing

technologies and catalysts to deliver

cleanerproducts from low-quality feeds.

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clean transportation fuels ultra-low sulfur diesel (


We can help to reduce sludge and sediments entrain-ment with our patented chemicals for online cleaning. These transform the sludge into oil, with the additional advantage of releasing the entrained sediments and avoiding their carryover.

A Thomas Meek, Principal Technologist Delayed Coking, Shell Global Solutions, [email protected] our operating experience, we tend not to do this and it is certainly not recommended at any Shell delayed coking sites due to: Potential for desalter carry-under, resulting in oil and sludge being routed to the cutting water tank, resulting in: Oil and solids, (containing Ca, Si, Ni, Va and other inorganics) Contamination of petroleum coke

Cutting water system fouling and corrosionCutting water odour, resulting in health and safety

concerns for operators performing drum opening and decoking

Release of vapours into the environment during coke drum opening or decoking from storage piles and coke barns.

Our considerations may not apply to other sites.

Q Can you provide advice on operational or equipment measures to tackle plugging in the resid lines of our delayed coker?

A Thomas Meek, Principal Technologist Delayed Coking, Shell Global Solutions, [email protected] our organisation, we had success applying the following: Prevention or mitigation of plugging: Steam and electrical tracing and insulation are installed on all residuum lines. Newer heated liquid medium tracing has not been installed on any of our units. We understand that this has been installed at several industry locations with good results Flushing oil supplies and connections to unit heavy slop or maintenance decontamination recovery systems are installed on all residuum systems for flushing lines and equipment such as exchangers and pumps prior to stagnation setup Residuum feed lines routed into delayed coking furnace passes are steam purged cleaned with high-pressure steam at all Shell locations under specific SIS (Safety Instrumented System) controls. Coke drums inlet lines are swept clean with steam during normal operations and with an alternate utility source during utility outages Pump warm-up lines with enough capacity to keep standby pumps sufficiently hot to prevent stagnation solidification, equipped with a flushing capability when the equipment is taken out of service for maintenance Turnaround or shutdown activities: residuum lines and equipment are to be flushed as soon as possible to prevent stagnation setup. Individual exchangers and

pumps have flushing oil and steam connections for purging residuum out into connections to unit slop or maintenance decontamination recovery systems. Best practice is to have these systems permanently installed along with nitrogen for air freeing prior to recommis-sioning and startup. Residuum lines should be decontaminated and then inspected for heavy oil deposits such as precipitated asphaltenes or coke. If these foulants are present, the lines are to be hydro-blasted clean. Failure to remove foulants can result in partial or complete plugging with shorter unit run lengths and lost production. If a line is known to have heavy oil foulants or coke, it must be included in the turnaround list for hydroblasting. Lines such as delayed coker heater outlet and coke drum overhead vapour lines are to be hydroblasted at every turn-around. IR camera inspection of lines has been used to determine the extent of fouling and helps in line clean-ing planning as well as on-the-run monitoring.

Our operations and considerations may not fit with every approach.

Q Our FCC regenerator NOx emissions are consistently over-spec. Does this mean we need to adjust the balance of oxygen supply and operating temperature? If so, how?

A Eric F Griesinger, Marketing Manager, Grace Catalysts TechnologiesOperational variables that often have an effect on NOx emissions have been found to include: excess O2, regen-erator mixing efficiency, platinum-formulated combustion promoter, antimony-based nickel passiv-ators and feed nitrogen. Generally, a decrease in excess O2 will lead to lower NOx emissions (see Figure 1). While regenerator hydrodynamics are complex, a change in dense bed level and/or temperatures may provide conditions favourable to reduce NOx emis-sions. Use of platinum-formulated combustion promoters and/or antimony have also been observed to increase NOx emissions. When dosed at exception-ally high rates, even non-platinum CO promoters can worsen NOx emissions. Oddly enough, while feed nitrogen has been found to be the major source of NOx emissions, typically other variables have a stronger influence over the actual NOx emissions. Graces research has concluded that generally less than 5% of the available feed nitrogen is released as regenerator NOx emissions. The fact that only a small amount of feed nitrogen is converted to NOx contributes to the complexity of controlling NOx through management of an FCC units operating conditions.

Adjusting regenerator excess oxygen can influence NOx emissions. A cross plot of NOx as a function of excess O2 can be indicative of your units response. Typically, at low excess O2 conditions, the NOx increases rapidly with excess O2. The NOx curve then flattens out as excess O2 increases further (see Figure 2). Naturally, if the FCC unit is operating in the steep part of the response curve, relatively small changes in excess O2 will likely yield noticeable changes in NOx.

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cbi.indd 1 11/9/12 11:34:23


Conversely, if the FCC unit is operating in the rela-tively at portion of the response curve, changes in excess O2 will not have much of an in uence on NOx.

Regenerator temperatures (dense bed and/or dilute phase) often correlate with NOx emissions. Unfortunately, it is dif cult to predict how an increase or decrease in these temperatures will in uence NOx emissions. Observations from numerous commercial catalytic NOx reduction applications demonstrate that some FCC units observe lower NOx as temperature increases, while other FCC units experience lower NOx through a decrease in regenerator temperature. It is for this reason, that Grace recommends performing a thor-ough study of NOx emissions through the use of statistical modelling via multiple regression analysis. While the initial goal of any regression modelling is to develop a useful model to predict NOx emissions, NOx can be dif cult to model. However, detailed multiple regression modelling can point the FCC unit engineer to potential operating knobs that are in uencing NOx emissions, and which way to directionally move the knobs. Further, it must be noted that such multi-ple regression modelling efforts are speci c to each individual FCC unit, rarely transferable to other FCC units, even FCC units of a similar design and operating under similar conditions.

Historically, it has been found that CO promoter, even non-platinum, low-NOx combustion promoters, when dosed at rates in excess of the additions neces-sary to control afterburn and/or regenerator CO emissions, can lead to elevated regenerator NOx emis-sions. When regenerator NOx emissions were not an issue, the practice of dosing promoter at elevated rates was widely accepted, as the negative side effects were typically not noticed nor problematic. As regenerator NOx emissions limits tighten, optimisation of promoter dosing rates is crucial. Grace has developed an analytic method to characterise an FCC units equilibrium cata-lysts propensity to oxidise CO to CO2. This analytical method, known as the CO Index, can assist the re nery and Graces technical staff to determine the optimum, FCC unit-speci c, CO promoter dosing rate.

While the chemistry behind the formation of NOx from within an FCC unit regenerator is complex,

successful NOx reduction can be achieved by manipu-lating the contributing operating variables identi ed by analysis and modelling of the speci c FCC unit. A Ray Fletcher, Engineering Fellow, Intercat, ray. etcher@

intercatinc.comNOx emissions on the FCC unit are strongly a function of excess oxygen in the ue gas for units operating in full combustion, maldistribution in the regenerator and the use of platinum-based combustion promoters. There exists a weaker correlation with the nitrogen content in the feed. The use of antimony for equilib-rium nickel passivation increases NOx emissions in many but not all FCC units. NOx emissions are directly related to CO levels in partial-burn operations.

Control of NOx emissions requires careful trouble-shooting to determine the root cause of the NOx formation. For example, are the NOx levels constant and stable or do they uctuate? Has there been a step change increase in NOx at any point in time? The following guidelines are offered as a starting point for the troubleshooting and control of emissions: Combustion control NOx emissions are directly related to excess oxygen levels in full combustion and CO levels in partial-burn operations. It is recom-mended that FCC operators control either the excess oxygen or CO concentrations at the lowest stable levels possible. NOx emissions pass through a minimum at zero excess oxygen and zero CO concentration. However, operations at the zero point generally result in unstable operations for most unit designs Maldistribution Maldistribution in the regenerator is the second leading cause of high NOx emissions following excess oxygen in the ue gas. There are several established troubleshooting techniques for identifying maldistribution in regenerators, which include: radial and vertical temperature pro les, cross plotting of NOx emissions versus delta cyclone outlet temperatures (ie, set #1-set#2, set #2-set#3) and look-ing for pattern shifts, the use of an reaction mix sampling (RMS) device with a portable gas analyser for direct measurement of gas concentrations, and gas and catalyst tracer studies (Tracerco).

Intercat is now employing computational particle

1000

10

100

1250 1340 1430 1520 1610 1700 1790

NO

concentr

ati

ons,

ppm

Temperature, F

1

O2 = 0.1%

O2 = 10%

O2 = 1%O2 = 4%

FCCU

Figure 1 Thermodynamics of NOx formation under typical FCC unit conditions

120

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20

0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

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0

Some commercial units operate in this regime with low excess O2

Other commercial units operate in this regime even at very high excess O2

Figure 2 Excess oxygen increases NOx: pilot plant data

Q&A copy 12.indd 4 11/9/12 13:23:26

uid dynamics (CPFD) to simulate the uid dynamics and coke combustion chemistry in FCC regenerators to identify design parameters leading to maldistribution. Re ners are able to identify speci c regions in their regenerator for modi cation. Finally, the impact of the proposed modi cations can be checked to verify that they have met the speci ed criteria.

In some cases, maldistribution can be minimised by adjusting, where possible, the amount of combustion air being delivered to speci c regions within the dense bed. In other cases, modi cations to spent catalyst distributors or air distributors during the next shut-down will be necessary Combustion promotion Re ners utilising platinum-based combustion promoters are strongly recommended to utilise a non-platinum-based combus-tion promoter. Many re ners observe a 50-70% reduction in NOx emissions after the removal of plati-num from the circulating inventory. The rate of NOx emissions decrease is not instantaneous due to the half-life of the platinum oxidation activity. The decay rate is a function of the concentration in the circulating inven-tory, catalyst inventory in the regenerator, concentration of poisons (sulphur), and so on Equilibrium catalyst Ni passivation The use of anti-mony will in most, but not all, units increase NOx emissions. Re ners are recommended to discontinue antimony injection if possible or minimise injections to the lowest tolerable levels permissible by the wet gas molecular weight. Catalyst suppliers are able to add crystalline alumina to most formulations, which encap-sulates nickel. It may be possible in some units to eliminate antimony injection by use of this technology Use a NOx additive Several effective additive technol-ogies exist to reduce NOx emissions. Typical reductions are up to approximately 50%. Addition rates are usually very low at 1-3 wt% and so do not pose a risk to base catalyst activity dilution. Units suffering from excessive NOx emissions may bene t from the use of NOx additives.

A Alan Kramer, Global FCC Additives Specialist, Albemarle, [email protected] NOx formation is rather complex and is affected by several operational and design factors. Additive use can also affect NOx emissions. The factors to consider are: Feed nitrogen: about 50% of the feed nitrogen typi-cally winds up going to coke. Of the coke nitrogen, about 5-15% ends up forming NOx. Lowering feed nitrogen may lower NOx emissions Excess oxygen in the ue gas: decreasing excess oxygen will decrease NOx. There is a ne balance between operational stability and ue gas oxygen. The challenge is to maintain oxygen at the lowest possible safe level Regenerator bed level: changing the bed level may affect NOx, but the effect is highly unit dependent. It may be worthwhile tracking NOx versus bed level to see if a correspondence exists on your unit Catalyst/air mixing: similar to spent catalyst

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distribution, better mixing usually results in lower NOx emissions because it minimises zones of high oxidation in the regenerator Large regenerator temperature gradients: this is indicative of poor mixing, and actions to mitigate gradients without resorting to high levels of combus-tion promoter use may help lower NOx Spent catalyst distributor design: better distribution will usually lower NOx. While not an operational vari-able, it is a design variable. It could be something to investigate and to consider improving during the next scheduled turnaround Regenerator design: units designed with countercur-rent catalyst/air flow in the regenerator tend to have lower NOx emissions Use of a non-platinum-containing combustion promoter: switching from a platinum to a non-plati-num combustion promoter, such as Albemarles Eliminox, will lower NOx emissions to the same level of afterburn and CO control Optimal combustion promoter use: overpromoting or adding too much of any promoter (platinum or non-platinum) will increase NOx emissions. Add promoter frequently in small doses and only as much as is neces-sary to control afterburn or CO emissions Antimony use: if antimony additions are a regular part of operations, make sure the minimum amount of antimony is added to achieve the necessary passivation NOx reduction additives: reduction can be between 0% and 80%, but is variable and often hard to predict. A collection of experiences during EPA consent decree trials indicated an average reduction of 26% across 28 different FCC units. (Source NPRA AM-07-44). Beware of copper-containing NOx additives because copper can drastically increase hydrogen yield.

Regenerator temperature does not significantly affect NOx formation. N2 fixation occurs at temperatures greater than typical regenerator temperatures of 700-750C. If the unit has a CO boiler, it is recommended to keep combustion zone temperatures low, oxygen levels below 6-7% and to avoid overfiring the boiler.

A Robert Ludolph, Principal Technologist Cat Cracking, Shell Global Solutions, [email protected] our experience, the combustion environment of a full-burn regenerator is important in determining how low the NOx emissions can ultimately become. Key conditions are flue gas excess oxygen, the radial distri-bution of combustion air (oxygen), the radial distribution of spent catalyst, and the uniformity of oxygen/catalyst mixing and contact time.

In general, NOx directionally increases with rising flue gas excess oxygen. So by reducing air rate and/or oxygen enrichment (less oxygen entering the regenera-tor), a reduction in NOx emissions would be expected. Also, it is generally accepted that NOx reduces to N2 after contact with carbon monoxide (CO) and/or coke carbon carried by spent catalyst (C). So operating in a manner that promotes better oxygen/catalyst mixing and contact time will also mitigate NOx.

By reducing oxygen entering the regenerator, less CO

will oxidise to carbon dioxide (CO2), thus providing more opportunity for NOx to react with CO and reduce to N2. Some CO, however, will enter the dilute region of the regenerator, oxidise to CO2 and create an unde-sirable heat release referred to as afterburning. Afterburning can threaten the mechanical integrity of regenerator internals, so excessive afterburning must be avoided.

A full-burn regenerator that mixes well and distrib-utes oxygen and spent catalyst uniformly will allow a refiner to operate with low flue gas excess oxygen. Such regenerator operations will tend to generate fewer NOx emissions along with minimal afterburning. A regenerator that mixes and distributes less effectively will be susceptible to afterburning, be less capable of operating at low flue gas excess oxygen and thus less capable of mitigating NOx.

Some refiners have employed combustion promoters to reduce afterburning. These catalyst additives accel-erate the oxidation of CO to CO2. Unfortunately, by doing this, the available CO for reducing NOx is lowered, which results in higher regenerator NOx emissions. Other refiners have also adjusted their heat balance or raised their catalyst additions to drive the regenerator higher in an attempt to reduce afterburn-ing and potentially NOx.

The reaction system contributes NOx precursors via the spent catalyst entering the regenerator. Refiners lower these precursors by improving their feed atomis-ation and dispersion, operating more effective riser outlet separation systems, improving stripping effi-ciency and/or lowering feedstock nitrogen content. The impact on NOx for each of these approaches is quite unit specific and difficult to project.

Q We encounter severe foaming problems using mixed amines for gas.

A Heather Sartain, Product Specialist, MPR Services, Inc, [email protected] mixed amine for gas sweetening is a common practice. Any liquid will produce froth or foam if gas is introduced into the liquid faster than the two phases disengage. Removing the contaminants that stabilise foam is the only efficient way to control amine system foaming. This is done through an abatement process. If that abatement process does not remove the contami-nants (surfactants, solids) that cause and sustain foaming, foaming will occur again. You can reduce and stop the foaming by removal of the contaminants with-out adding anything to the amine. This is done through a mechanical means of abatement in which the foam is separated from the solution. This can be performed on an as-needed basis or continually and does not inter-rupt any operations, thus allowing continuous gas treating with any mixture of amines.

The available process for the mechanical removal of foam-causing contaminants is SigmaPure, a unit provided by MPR Services, Inc. The foam-causing agents/contaminants are incorporated in the foams


Q&A copy 12.indd 6 11/9/12 13:23:52

structure. Thus, if the amine is foaming and the foam is separated from the solution, the contaminants that caused or enhanced the foaming are also removed (see Figure 1).

A slipstream of the recirculating amine stream is pumped into the SigmaPure processs foaming column (shown on the left). Non-oxidising gas is injected into the solution to adsorb soluble contaminating surfac-tants and carry them to the bulk gas/liquid interface.

The surfactants are incorporated in the foam above the gas/liquid interface and removed from the bulk solution as it propagates up into the drying section. Free liquid drains from the foam as it moves through the drying section and into the stripping section of the process. The gas and liquid fractions of the foam are separated by breaking the foam with a stripping spray (normally make-up water). The foam-causing contami-nants contained in the liquid fraction of the foam are coalesced with the stripping spray and collected as foam waste, while the gas fraction of the foam is recy-cled back to the foaming column for reuse.

This process has been successfully used to control foaming in a variety of gas sweetening processes worldwide. These processes include LNG, natural gas, re ning and chemical plants. Further, it has been used to control foaming in a wide variety of sweetening solvent solutions, which include DEA, MDEA, DGA, DIPA, Flexsorb, Sulphinol and mixed amines. The mechanical foam abatement application is not plant, process or solution speci c. Furthermore, the use of this application will not negatively affect the sweeten-ing solutions in any way.

Mechanical abatement is also more reliable and endurable than antifoams. Additionally, activated carbon and mechanical lters are known to contribute to foaming.

If the solution can foam, it can be controlled with a portable or permanent foam abatement process.

A Berthold Otzisk, Technical Consultant, Kurita Europe GmbH, [email protected] mixing of amines can provide advantages for gas sweetening operations. Improved acid gas absorption,

Feed

Return Foamate

Figure 1 SigmaPure process for amine foaming control

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Q&A copy 12.indd 7 11/9/12 13:24:09

Nasty StuffHeavy crudes are here to stay. As long as oil prices remain high,Canadian, Venezuelan, Deep WaterGulf of Mexico, Mexican andother low API gravity crude oilswill play an ever more importantrole in supplying world refineries.And prices promise to remain highbecause gainsayers notwithstanding,Hubbert was right.

A big question is how to best handlethese nasty crudes? Do you revamp existing units or invest innew capacity? With refineries nowrunning flat out, the balance mightseem to favor grass roots expansion,but given the substantial cost multiplier over revamps, this could

be questioned. Whichever the case,however, an inescapable fact is that the process design of the projectwill prove crucial. Between thecharge pump, the desalter and theunits' distillation columns there aremany places where miscalcula-tions in the process design couldwreck the entire project.

Can you really be sure of attainingdesired crude rates? Desalting viscous crude is extremely difficult.Minimizing coking or asphalteneprecipitation in the heaters demandsextreme care. Can you reasonablyexpect high diesel and HVGOrecoveries, acceptable levels ofnickel, vanadium, and microcarbon

residue (MCR)? Refiners who cutdeep should not be surprised whenthe HVGO product MCR is over 2wt % and the vanadium content isin excess of 10 ppmw. Any one ofsuch difficulties can result in lowerrevenue, unstable operation oreven unit shutdown. It is critical tounderstand that the inherent properties of these low API gravitycrudes dictate that exact processdesign is of paramount importance.

The point of this litany of possibleproblems is to remind you not toskimp in the early phases of engineering. From the start of theLP work through the completion offront-end process engineering,actual product yield and qualitiesdepend on the process design.

The message is clear. Nasty crudeswill continue to make up anincreasing proportion of refineries'crude slates. But time is precious.The sooner we face this fact, unwelcome as it may be, the moreexpeditiously we can adapt.

For a more in depth review ofheavy crude challenges, ask us forTechnical Papers 173, 185 and197.

3400 BissonnetSuite 130Houston, Texas 77005USA

Ph: [1] (713) 665-7046Fx: [1] (713) [email protected]

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pcs nasty.indd 1 1/6/12 11:58:35

reduced energy requirements or additional carbon capture are notable benefits. Applied mixtures are formulations of primary-tertiary amines, secondary-tertiary amines, tertiary-tertiary amines or formulated amines with additional activator molecule or hindered amines.

There are a number of possible reasons why your mixed amine system is suffering from foaming. In general, clean amines do not show a foam formation; this is why contaminants could be the foam initiator. Contaminants in the feed gas are small particles or degradation products. When the surface tension is low, liquid droplets (aerosols) can surround gas bubbles to create foam. Fine particles such as coke or iron sulphide form a layer in the film around the gas bubble. The installation of an effective amine filtration system helps to reduce foaming. The filtration equipment should include a suitable separator, gas liquid coalescer, acti-vated carbon filter and cartridge filter.

Primary and secondary amines show a fast reaction with CO2 to form carbamates. The higher heat of reac-tion with CO2 due to the carbamate reaction requires more energy for regeneration. The regeneration of mixed amines is more difficult to manage because of the different reboiler duty. The result is often a thermal degradation of primary or secondary amines. A better temperature control during regeneration will help to reduce the degradation of the mixed amine.

An underestimated problem is oxygen contamina-tion. Oxygen can react at low ppm levels with amines to form carboxylic acids. These acids react with amines and degradation products to form fatty acids or long-chain organic acids. Fatty acids increase the hydrocarbon solubility in the amine solution. Mixed amines often show a higher absorption tendency of heavier hydrocarbons such as aromatics, resulting in foam formation. Maintaining the temperature of the absorber above the hydrocarbon condensation temper-ature will help to reduce the foaming potential. Antioxidants will scavenge oxygen, while surface active antifoams will eliminate foam. Antifoams for gas sweetening processes are designed to prevent the formation of foam and to break existing foam.

Antifoams and corrosion inhibitors play an impor-tant role in the gas sweetening process. They are surface active components and must be used with a thorough understanding of the chemistry. The selection of less suitable additives can increase the risk of foam-ing. Overdosing of silicone-based antifoams can create foaming. At an elevated concentration, the antifoam is tied up in micelle structures. They form lenses and are no longer spread on the interface.

Underdosing of an antifoam also increases the poten-tial for foam formation if there is a need to inject an antifoam. Activated carbon adsorbs surface active contaminants and hydrocarbon condensates. Silicone-based antifoams are removed there as well, which reduces the antifoam concentration in the mixed amine. Misuse of additives can produce severe consequences, which is why a correct application with a proper concentration is mandatory.


Q We are planning to process heavy crude feed with a high aromatics content. What changes will I need to make to the FCC catalyst to crack those aromatic rings?

A Eelko Brevoord, Technical Services Manager, Refining Catalysts, Albemarle, [email protected] feeds are more hydrogen deficient and are more difficult to crack. As a rule of thumb, every 10 kg/m3 density increase results in a drop in conversion of 3%. At the same time, aromatics are absorbed on the catalyst surface and form coke. In order to crack heavy aromatic molecules to valuable products, the preferred cracking reaction must take place before dehydrogena-tion and condensation reactions occur, creating coke. A very accessible catalyst is required, where large mole-cules can easily diffuse into the catalyst pores. Precracking on selective matrices, followed by zeolite cracking, is the preferred reaction pathway. Albemarle has developed the Upgrader catalyst family specifically for this purpose. Commercial experience has proven its bottoms cracking characteristics that maximise the refin-ers profitability. Its metals resistance allows a refiner to maintain a high conversion at high concentrations of feed contaminants, which often coincides with process-ing heavy feed. The exact catalyst formulation needs to be tuned to meet the product quality and selectivity targets, while also addressing the units constraints.

A Robert Ludolph, Principal Technologist Cat Cracking, Shell Global Solutions and David Hunt, Senior Technologist Fluid Catalytic Cracking Design/Licensing, Shell Global Solutions, [email protected] catalysts are not designed to crack aromatic rings. Feedstocks with a high aromatic content occur through-out the gas oil and residuum boiling ranges, which can be categorised as heavy crude feed. Aromatic feedstocks lack hydrogen content, are difficult to crack and tend to produce more coke per unit of conversion than feed-stocks containing more hydrogen. As a result, delta coke will increase, the regenerator temperature will also increase and the catalyst circulation will decline. Also, since aromatic feedstocks are more difficult to crack, unit conversion will decrease, producing more bottoms, especially if the feedstock is residuum. Lighter products will have higher olefin and/or aromatic contents.

In general, to address the delta coke increase, it would be desirable to regain the loss in catalyst circulation. Reducing the feed temperature to the riser is an option if coke burning capacity is available. Catalytically, a reduction in the circulating activity should be consid-ered. Reducing zeolite content is a common approach for accomplishing this. Also review the zeolite rare earth content; potentially, you could improve coke selectivity while maintaining good zeolite stability.

To address the loss in conversion and bottoms upgrad-ing, an increase in matrix content should be considered. Additional matrix can help in maintaining your bottoms yield depending on how heavy the aromatic feedstock becomes. Be careful not to let the matrix acidity get too high; coke selectivity will suffer and may negate the upgrading benefit of additional matrix.

Q&A copy 12.indd 8 11/9/12 13:24:26

3400 BissonnetSuite 130Houston, Texas 77005USAPh: [1] (713) 665-7046Fx: [1] (713) [email protected]

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upsets from water slugs andother unpredictable situationsthat have damaged internals,resulting in diluent losses andhigh vacuum unit overhead con-densable oil. Diluent is neithercheap nor plentiful, and highvacuum column operating pres-sure will reduce overall liquidvolume yields. And if the designof the delayed coker fractionatoris based on todays experiencewith conventional heavy feed-stocks you will be lucky to runsix months.What all this means is thatspecial process and equipmentdesigns are needed to satisfythe special demands of pro-cessing oil sands crudes. Suchprocesses are not generated bycomputer based designers whohave little or no experience andnever leave the office. They aredeveloped only by engineerswith know-how who have realexperience wearing Nomex suitsand measuring true unit per-formance in Northern Alberta.Shouldnt this be kept in mindby those considering long termsupply agreements?

Oil Sands Crude Profits andProblems?Canadian bitumen productioncurrently runs about 1 MMbpd,with some being sold as Synbitand Dilbit. Over the next 10-12years output is expected toincrease to 3.5 MMbpd and morerefiners will begin investing toprocess it and come to dependon the Synbit and Dilbit for asignificant part of their supply.Few today, however, have everprocessed these feeds at highblend ratios, and are unawarethat conventional process andequipment designs are not upto the job. Canadian oil sands

feedstocks are extremely hardto desalt, difficult to vaporize,thermally unstable, corrosive, andproduce high di-olefin productfrom the coker. If you intend tolock into a long-term supply,therefore, it is imperative that youconsider reliability and run lengthfrom a particular design.Too low tube velocity in thevacuum heater tubes will lead toprecipitation of asphaltenes. Toofast a flow rate will erode thetube bends. If coil layout, burnerconfiguration and steam rate arenot correct, run length will bemeasured in months, not years.Diluent recovery unit designsmust take into account possibleFor a discussion of factorsinvolved in designing refinery unitsto process difficult oil sands feed-stocks, ask for Technical Papers#234 and 238.

10 PTQ 01:10 01 PC PTQ 0107 ADF 10/19/07 4:42 PM Page 1

pcs 2.indd 1 1/6/12 21:05:28


So, the zeolite-to-matrix ratio of the catalyst system will tend to shift lower if the aromatic feed contains residuum; the ratio may be similar or higher if the aromatic feed is mostly gas oil. Catalyst addition rates may need to shift higher in order to manage feedstock metals. Metal traps or equilibrium flush catalyst could also need to be considered. The formulation may need further adjustment if the feed-stock nitrogen is also high; aromatic nitrogen can have a profound impact on cracking reactions, driv-ing unit conversion down further.

A Rosann Schiller, Senior Marketing Manager, Grace Catalysts TechnologiesThe aromatic cores of heavy feed molecules will remain largely uncracked. Without the proper FCC catalyst design, these aromatic compounds will condense on the catalyst surface and lead to increased coke yield, high regenerator temper-atures and lost conversion. To effectively crack a heavy aromatic feed, an FCC catalyst with a balanced zeolite-to-matrix (Z/M) ratio, an appropriate hydrogen transfer activity and an optimum pore structure is required. Industry-leading coke selectivity, such as offered by Grace FCC catalysts, is crucial for units limited by regenera-tor temperature and/or air blower constraints. A properly balanced Z/M ratio minimises coke formation and maximises liquid product.

The high-activity matrix incorpo-rated into Graces resid catalysts possesses the majority of its poros-ity in the crucial 100-600 Angstoms () pore size diameter range. This mesoporosity allows for the free diffusion of heavy feed molecules into the matrix, where pre-cracking is necessary to achieve complete vapourisation. The selective-active matrix is also responsible for the conversion of naphthenoaromatic rings, reducing aromatic feed species into gasoline and LCO range product rather than coke. Hydrogen-deficit feeds require higher hydrogen transfer activity in the zeolite. The balance of mesopo-rosity and optimised acid strength greatly improves the selectivity of the bottoms cracking reactions that

take place without the gas penalty often observed when cracking aromatic feeds.

The specific FCC catalyst reformu-lation directives for any FCC unit shifting to a heavier, more aromatic feed are strongly dependent upon the current base catalyst technology. Graces broad FCC portfolio provides the flexibility to re-optimise the catalyst recipe for the specific refiner, feedstock, and projected unit constraints and objectives.

Q How effective is software simulation for calculating mass transfer in trays and packings? A Ralph Weiland, President, Optimized

Gas Treating, Inc., [email protected] reliable, predictive simulation software does not use equilibrium (ideal) stages, efficiencies, HETPs, residence times of ideal stages, heat transfer efficiency, or any other information that cannot be read from a PFD or internals vendor drawing to translate ideal stages into real trays or physical depths of real packing to approximate the perfor-mance of real tower internals. Software that does is using the best guesses of the user of the software to fill the huge gap between ideality and reality. Such software is espe-cially unsuitable for dealing with packing. The reality is that mass transfer rates on trays and in pack-ing depend on column hydraulics, physical and transport properties, and the mass transfer characteristics of the internals. If the model is not 100% mass transfer rate based, it is either ignoring the tower internals altogether or is providing only a very rough estimate of performance. A strictly mass transfer rate-based simulator such as ProTreat is the only reliable way to predict column performance. Other software is useful if you have data from the plant in question, or a similar plant, that can be used to tune the model. But such a model needs to be fitted to data and is therefore not really predictive. If you are dealing with packing, mass transfer rate-based simulation handles all sorts of random and structured packing very reliably and is the only way to go.


Our new clean-fuels plant is straining the

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TO MEET CLEAN FUELS requirements for gasoline, a medium-VL]HG0LGZHVWHUQUHQHU\DGGHGDORZVXOIXUIXHOVWHFKQRORJ\SODQW*DVROLQHWKURXJKSXWZDVXQFKDQJHG+RZHYHUWKHVKDUSLQFUHDVHLQVXOIXUUHPRYDOUHTXLUHGPRUHK\GURJHQIURPWKHK\GURJHQXQLWDQGVHQWPRUHVXOIXUgases to the amine treaters and GRZQVWUHDPVXOIXUXQLWV7KHVHDX[LOLDU\XQLWVEHFDPHERWWOHQHFNVRYHUGULYHQDWWKHFRVWRISURGXFWSXULW\DQGDPLQHFRQVXPSWLRQ

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Q&A copy 12.indd 9 12/9/12 13:40:52

Survey: refinery approaches to energy efficiencyHydrocarbon Publishing CompanyAccording to the US Energy Information Administration (EIA), energy usage represented 43% of the overall refinery operating expense, excluding crude purchases, in 2010.1 In European refineries, energy spending can account for as much as 60% of the oper-ating budget, according to a CONCAWE report.2 The figure has been doubled for the last two decades due to rising energy costs, increasingly tight fuel standards and higher refinery complexity. A small fraction in energy savings can translate into billions of dollars. As refining margins are rather slim in the down cycle, cost reduction via energy improvement may turn a loss into a profit.

Drivers for energy efficiency can loosely be catego-rised as internal or external. Primary internal drivers for energy efficiency include the desire to improve productivity and profitability, reduce fuel consumption costs in the face of volatile prices, improve plant safety and personnel satisfaction, and optimise plant opera-tions and maintenance. External drivers for energy efficiency can come in the form of government regula-tions and mandates, industry competition, availability of cost-effective technologies, and from the public in regards to the social responsibilities of an industrial company.

Hydrocarbon Publishing Company conducted a survey among refiners during Q4 2011 in order to help the industry better understand refiners views on energy efficiency and to highlight which approaches to energy efficiency work best. The survey, in particular, examines where refiners can improve energy efficiency in both utility providers (such as heat, steam and hydrogen) and energy consumers such as processing units. Forty-four refineries, each with crude oil process-ing capacities of more than 50 000 b/d, responded to the survey, which contained 17 questions. Around 40% of the responses came from refineries located in North America (18), followed by Europe (11), Asia/Asia-Pacific (seven), Latin America/South America and the Middle East (three each), and Africa (two).

Importance of energy efficiencyA large majority of survey respondents (89%) view energy efficiency as important to very important, while only 9% reported that their refinery viewed energy efficiency as not very important. (2% of survey respondents did not respond to this question.) Around 78% reported that energy efficiency at their refinery has improved in the last five years, while 13 indicated that there has been no improvement or a drop in energy efficiency over the last five years. When asked about the reasons behind energy management projects the participants refineries have performed,

Reduce gasoline cutpoint

70% of respondents reported that their refineries undertake energy management projects due to a combi-nation of environmental (lower CO2 emissions) and economic (reduced operating costs) incentives. The remaining 30% indicated that energy management projects are performed solely for economic incentives.

Energy management team and site-wide assessmentsOne of the first steps for improving energy efficiency throughout the refinery is forming and/or hiring some sort of energy management team and conducting a site-wide assessment. Refineries cannot improve their energy efficiency without first understanding the plants energy consumption and designating someone to examine opportunities to improve efficiency. Almost half of the survey respondents reported that their refin-ery had an in-house team designed to examine and improve energy efficiency at their facility. One-third of the respondents reported using both an in-house team and a third-party consulting service to manage refinery energy use. Meanwhile, every respondent indicated that at least one site-wide assessment had been performed at their plant. Around 11% of respondents reported that such assessments were performed more frequently than every six months, 34% indicated annual assessments, and 14% reported assessments take place every two years.

Prioritising energy efficiencyPrioritising energy efficiency and developing an energy efficiency mindset is important for a successful energy management programme. One of the first places to start developing an energy efficiency culture is with new employees. Teaching employees about the importance of energy efficiency early on can help them to continually think about opportunities to improve energy efficiency and reduce operating costs at the refinery. Of the refineries surveyed, over half reported that energy efficiency is currently included in their new employee training programme. Another aspect that is beneficial for successfully implementing energy efficiency projects is budgeting money specifi-cally for such projects. Over half of respondents appear to have realised the importance of setting aside money for energy efficiency projects and currently do so.

Survey participants were also asked about the role that energy efficiency considerations play in the selec-tion of new units. When asked about new process units, only 7% of respondents indicated that energy efficiency was a primary concern when selecting new units. A greater percentage of respondents, 18%, indi-cated that energy efficiency was a primary concern when examining auxiliary equipment. For each case, it is notable that every respondent acknowledged that


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three levels of investment discussed. The first set of projects considered will be viewed as short-term effi-ciency improvements. These solutions comprise those identified as operational adjustments that can be achieved with relatively little commitment of time and money; these types of improvements are often referred to as good housekeeping practices as they primarily involve getting the most out of the existing configura-tion. The next set of solutions will be oriented toward longer-term goals and will encompass the maintaining of the first-level projects while also including the additional investment opportunities identified. Lastly, innovative solutions that are targeted in a medium- to long-term frame of time incorporate the higher-end investment options that are described as major revamps.

In each level of investment, improvements can be made to utility providers and systems (such as furnace, boiler, pump, compressor, fan and heat exchanger) as well as specific units (such as CDU, coker, visbreaker, HT and HC, catalytic reformer and alkylation.)


some level of consideration is given to energy efficiency during new unit/equipment selection.

Major sources of energy inefficiencyThe three most commonly cited sources of ineffi-ciency include process heaters, steam distribution system and waste heat, with 74%, 72% and 67% of the survey participants indicating these sources, respectively. Fouling and boilers were also significant concerns, with around 50% of participants identifying these issues as problem-atic. Figure 1 shows major sources of refinery inefficiency identified by survey respondents. Refiners answering Other cited turbines, heat integration and unplanned shutdowns as addi-tional sources of energy inefficiency.

Refiners seem to recognise the crude distilla-tion unit (CDU) as a process with significant room for improvement; 76% of respondents selected the CDU as one of the process units in their plant with a lot of room for improvement with regards to energy efficiency. The second most commonly cited unit was the fluid catalytic cracker (FCC), with 37% of respondents identifying this process unit. Nearly a quarter of participants also indicated that there is major room for improvement in the catalytic reformer, hydrocracker (HC) and coker. Figure 2 shows process units with the most room for efficiency improvements based on survey respondents replies. Refiners answering Other cited high vacuum units, propane deasphalter and aromat-ics complex.

The most commonly implemented project in refineries was adjusting operating conditions on a process unit to reduce energy consumption, with 93% of respondents indicating that their refinery has done so to increase efficiency in the last five years. Adjusting heat exchanger networks (for instance, rearranging and/or adding new heat exchangers to increase heat recovery) and improving insulation closely followed as popular choices, with 80% of respondents each indicating their refinery had performed these projects. Less common projects included installing a cogeneration facility, with 30% of respondents performing this project in the last five years. Figure 3 shows energy efficiency projects completed in the last five years by survey respondents. Refiners answering Other cited performing steam trap studies, generating steam from waste heat, optimising heaters, performing online cleaning for heaters, and installing a magnetic resonator in the naphtha/gas line of gas turbine/heat recovery steam generator as addi-tional energy efficiency projects.

Three options to improve energy efficiencyThe surveys results show commitment yet budget concerns over energy efficiency improvements in a refinery. Refiners are recommended to group the energy-saving opportunities into three categories for implementation, which will often correlate with the

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ConclusionThe survey results also reveal the key synergistic role played by energy management in overall operations (see Figure 4). Energy management directly affects refinery margins, as energy savings go straight to the bottom line. At the June 2012 Industrial Energy Technology Conference (IETC) in New Orleans, Louisiana, LyondellBasell received the Energy Award

for reducing energy consumption at its Houston, Texas (US), plant by 12% via the implementation of an energy efficiency programme. The programme has helped save the refinery 42 trillion Btu since 2007, with the flare opti-misation programme alone saving over 500 billion Btu/y. At an assumed energy cost of $5.50/MMBtu, the refiner saved an average of $46.75MM a year via the implemen-tation of the energy efficiency programme.

The execution of functional safety assessment and validation must take place on every safety project and must be carried out by functional safety experts

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Figure 4 Synergistic role of energy management

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Energy management is also intricately connected to asset management, as well-planned maintenance can result in less energy consumption in units generating and distributing utilities. Additionally, meeting produc-tion targets and quality standards will require extensive data collection that can be used in both asset manage-ment and energy management systems. A number of energy improvement strategies will go hand in hand with improvements in terms of plant maintenance, reli-ability and safety. Maintenance- and reliability-driven projects such as fouling control, maintaining/fixing insulation, repairing leaking pipes and conducting cata-lyst change-outs will typically lead to either direct or indirect improvements in energy efficiency. Asset management is known to yield profitability and produc-tivity improvements, primarily through minimising downtime. According to consultancy ARC, unscheduled shutdowns coupled with poor maintenance practices cost the global process industries 5% of their annual production, which is equivalent to $20 billion.3 The firm estimates that 80% of the losses are avoidable. Ineffective maintenance practices also lead to unscheduled down-time, costing operators an additional $60 billion a year.

In terms of environmental regulations, flaring is an area that is directly linked to energy management programmes. Excess flaring, in particular, can result in negative publicity and fines from local and national governments. Flare gas recovery sending the flue gas that would normally be sent to the flare back through the unit for use as fuel or feed provides a dual benefit of saving fuel and reducing emissions. In April 2012, US

refiner Marathon Petroleum announced an agreement with the EPA to reduce volumes of gas sent to flares. The company has already invested around $45MM to boost combustion efficiency at its plants and intends to spend another $6.5MM to comply with the agreement. According to the EPA, the proposed changes will cut emissions from Marathons six refineries by about 5.4K t/y. In the longer term, energy management is able to minimise the risk of violating carbon legislation if/when it is passed and supporting corporate sustainability goals. Also, with energy consumption monitoring being built into the asset management system, refiners will be provided with an easy path to monitoring, accounting and managing carbon emissions if/when it becomes mandated at a future date.

The surveys questions can be viewed at www.hydrocarbonpublishing.com/survey/eesurvey.pdf. For further analyses, see Hydrocarbon Publishing Companys report, Refinery Energy Management: Latest Technologies and Strategies to Enhance Operational Economics, July 2012. Contact: Thomas Yeung at [email protected]

References1 US Energy Information Administration, Table 2.1d Industrial Sector Energy Consumption Estimates, 1949-2010 in Annual Energy Review 2010, (Washington, DC: US Department of Energy, Oct 2011), http://205.254.135.24/totalenergy/data/annual/pdf/sec2_9.pdf (accessed 25 Jan 2012).2 EU Refinery Energy Systems, CONCAWE report no 2/12, Mar 2012.3 Hollywood P, Making the business case for reliability, Hydrocarbon Processing, Jun 2012, 15.



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Challenges and opportunities of 10 ppm sulphur gasoline: part 2

An emerging worldwide standard for ultra-low-sulphur gasoline (ULSG) as well as the challenges of increased heavy crude supplies and the gasoline/diesel imbalance demand careful consideration and selection of processing options. Part 1 of this article (see PTQ, Q3 2012) discussed commercially proven configurations that are available to meet these constraints and maintain profitabil-ity. An economic study, presented here, was also conducted to deter-mine the best scenario to meet ULSG requirements: severe FCC feed pretreatment alone or less severe pretreatment coupled with FCC gasoline post-treatment. The impact of catalytic feed hydrotreater (CFHT) cycle length requirements, with and without post-treatment, was also examined.

An existing refinery reconfigured to process heavy Canadian crudes while maintaining its FCC unit was assumed. The VGO feedstock consists of a 55 000 b/d blend of

Economic evaluation of processing options for ultra-low sulphur gasoline compares severe pretreatment with a combination of pre- and post-treat solutions

DELPHINE LARGETEAU, JAY ROSS, MARC LABORDE and LARRY WISDOM Axens

straight-run VGO and heavy coker gas oil with 4.2 wt% sulphur. Due to the refractory nature of this feed, it has to be hydrotreated in a high-pressure unit prior to feeding the FCC unit, and the resulting gasoline constitutes about one-third of the total gasoline pool and all of the pool sulphur. The following three cases were considered:

Case 1: A high HDS CFHT unit and FCC unit capable of producing 10 wppm gasoline pool sulphur without the need for a FCC post-treatment unit with a CFHT cycle length of four years to match the FCC

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