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RENTECH breaks new trails in the

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HydrocarbonProcessing.com | OCTOBER 2012

®

PROCESS CONTROL AND

INFORMATION SYSTEMS

Better control systems and

equipment vastly improve

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Cover Image: Photo courtesy of Emerson Process Management

OCTOBER 2012 | Volume 91 Number 10

HydrocarbonProcessing.com

SPECIAL REPORT: PROCESS CONTROL

AND INFORMATION SYSTEMS

35 Update hydrocracking reactor controls for improved reliability

A. G. Kern

41 Use a systematized approach of good practices

in pygas hydrogenation via APC

J.-M. Bader and G. Rolland

47 Why don’t we properly train control engineers?M. J. King

51 Consider automated fault detection systems

to improve facility reliability

A. J. Szladow

55 Optimize desulfurization of gasoline via advanced

process control techniques

V. Yadav, P. Dube, H. Shah and S. Debnath

REFINING DEVELOPMENTS

61 Maximize diesel production in an FCC-centered refinery, Part 2

P. K. Niccum

SULFUR—SUPPLEMENT

S-69 Optimize sulfur recovery from dilute H2S sources

M. P. Heisel and A. F. Slavens

HEAT TRANSFER

83 Identify and control excess air from process heaters

S. Ahamad and R. Vallavanatt

ROTATING EQUIPMENT

91 Apply new pump-drive software to test performance

K. Bihler, D. Dominiak, B. Keith and J. Johnson

DEPARTMENTS

6 Brief

9 Impact

15 Innovations

19 Construction

26 Construction Boxscore

Update

98 Marketplace

100 Advertiser index

COLUMNS

29 Reliability

Equipment life extension

involves upgrades

33 Integration Strategies

Recent trends shape

the future of DCS

102 Water Management

Consider software toolsfor water reuse projects

67 6

34

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http://slidepdf.com/reader/full/gulfpubhp201210pdf 5/1054OCTOBER 2012 | HydrocarbonProcessing.com

President/CEO John RoyallVice President Ron HigginsVice President, Production Sheryl StoneBusiness Finance Manager Pamela Harvey

Part of Euromoney Institutional Investor PLC. Other energy group titles include:World Oil and Petroleum Economist

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EDITORIAL

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Hydrocarbon Processing is indexed by Applied Science & Technology Index,by Chemical Abstracts and by Engineering Index Inc. Microfilm copies avail-able through University Microfilms, International, Ann Arbor, Mich. The fulltext of Hydrocarbon Processing is also available in electronic versions of theBusiness Periodicals Index.

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Hydrocarbon Processing (ISSN 0018-8190) is published monthly by GulfPublishing Company, 2 Greenway Plaza, Suite 1020, Houston, Texas 77046.Periodicals postage paid at Houston, Texas, and at additional mailing office.POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box2608, Houston, Texas 77252.

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| Brief

New fuel standards in the US

The US government recently finalized standards thatwill increase fuel economy to the equivalent of 54.5mpg for cars and light-duty trucks by model year2025. When combined with previous standards, thismove will nearly double the fuel efficiency of thosevehicles compared to new vehicles currently on theroad. In total, the program to improve fuel economy isexpected to reduce US oil consumption by 12 billionbarrels. The standards issued by the US Departmentof Transportation (DOT) and the US EnvironmentalProtection Agency (EPA) build on the previouslyissued standards for cars and light trucks for model

years 2011–2016. Those standards raised averagefuel efficiency by 2016 to the equivalent of 35.5 mpg.

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http://slidepdf.com/reader/full/gulfpubhp201210pdf 8/105Hydrocarbon Processing | OCTOBER 20127

BILLY THINNES, TECHNICAL EDITOR / [email protected]

Brief

Valero has decided to further reduce operationsand reorganize its 235,000-bpd Aruba refinery as a refined products terminal, the company said. The terminal

will feature both deepwater berths and smaller berths, and will have the flexibility to load the very largest crude ships.Terminal activities will, however, require a considerably smaller

workforce, according to the company. The reorganization andreduction in workforce is expected to be complete before theend of 2012. Valero will continue to supply jet fuel, gasoline,diesel and fuel oil to the island, as well as engage in third-party terminal services. In the terminal operations mode, Valero will

continue to invest in Aruba with facility improvements anddock and tankage upgrades, the company said. In the near-term, the refinery will continue to be maintained in a state that

would allow a restart, should Valero be successful in the pursuitof alternatives for the refinery prior to the terminal transition.

US investment group Carlyle has agreed to buy theperformance coatings business of DuPont for $4.9 billion in cash. The transaction is expected to close in the f irst quarterof 2013, subject to customary closing conditions and regulatory approvals. DuPont Performance Coatings is a global supplierof vehicle and industrial coating systems, with 2012 expectedsales of more than $4 billion and more than 11,000 employees.

As part of the transaction, Carlyle will assume $250 millionof DuPont’s unfunded pension liabilities. Carlyle’s industrialand automotive investments include Allison Transmission,Hertz and PQ Corp., as well as recent commitments to investin Hamilton Sundstrand Industrial and regional rail freightoperator Genesee & Wyoming.

Enterprise Products recently began an opencommitment period to determine additional shipperdemand for capacity on its Appalachia-to-Texas (ATEX Express) ethane pipeline. The 1,230-mile system will delivergrowing ethane production from the Marcellus/Utica Shale

areas of Pennsylvania, West Virginia and Ohio to MontBelvieu, Texas. The open commitment period will be usedto determine market interest in executing additional 15-year

binding transportation agreements. The ATEX Express isexpected to begin operations in the first quarter of 2014.

Cosmo Oil will permanently close its 140,000-bpdSakaide refinery in western Japan by July 2013 to meet a government regulation that encourages refining capacity cutsamid falling local demand. The Japanese Ministry of Economy,Trade and Industry set rules in July 2010 requiring refiners toraise residual cracking capacity to a designated percentage of crude refining capacity, as calculated by a formula, by March

2014. By closing the refinery, Cosmo expects to save Y10 billiona year in costs.

Technip has completed the acquisition of the Stone &Webster process technologies and associated oil and gas engineering capabilities. Technip sees this acquisitionas a way to further diversify its onshore/offshore segment,adding revenues based on technology supply. It will also usethe Stone & Webster brand to expand in promising growthareas such as the US, where downstream markets will benefitfrom the supply of unconventional gas. To make the most of these strengths, a new business unit, Technip Stone & WebsterProcess Technology, will be developed within the company’sonshore/offshore segment. Technip paid cash consideration of

around €225 million from existing cash resources, which will be subject to customar y price adjustments.

Air Liquide has officially opened its first public hydrogenfilling station for passenger cars in Düsseldorf, Germany. This station will be followed by 10 new hydrogen fillingstations that will be designed, built and rolled out in the nextthree years under the auspices of the German government’smajor demonstration project. By 2015, Germany will have asupply network of at least 50 public hydrogen filling stations.Driven by the same dynamic, two other stations have beeninstalled recently by Air Liquide in Oslo, Norway, and inBrugg, Switzerland. In Japan, the government sees hydrogen asa promising major energy source for cars and expects to installabout 100 hydrogen distribution stations for fuel cell vehicles

by 2015. In response to this government policy, Air Liquide Japan has recently set up a specialized team focused on thehydrogen business. So far, they have installed three hydrogenenergy stations (in Tokyo, Kawasaki and Saga). One of thesestations demonstrated the feasibility of a complete “bluehydrogen” chain, from wood chips to clean mobility.

Western Refining and Glencore International announcedthat two of their subsidiary companies (York River Fuels and Glencore Ltd.) have entered into a long-term

commercial supply and trading agreement. Glencore has agreedto provide global sourcing, supply and trading and inventory and risk management services to support York River’s mid-

Atlantic wholesale business. In return, York River has agreed toprovide rack marketing and contract and credit management.Glencore has entered into a long-term commitment with EpicTerminals at its terminal in Savannah, Georgia. The Savannahterminal includes over 450,000 bbl of storage capacity for

various grades of gasoline, distillates, ethanol, biofuels and fuel blends. The terminal will enable the two companies to expandtheir wholesale capabilities and provide fuel products to theircustomers from southern Georgia to northern Maryland.

Western Ref ining operates ref ineries in El Paso, Texa s,

and Gallup, New Mexico. The company also runs productsterminals in Albuquerque and Bloomfield, New Mexico.

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Impact

BILLY THINNES, TECHNICAL EDITOR / [email protected]

Increased coal-to-olefinsprocesses in China

China’s significant domestic supply of coal, combined with a domestic short-age of several key chemical feedstocks,especially ethylene and propylene, aredriving increased Chinese demand formore production of chemical feedstocksfrom coal, according to a new IHS study that assessed the key technologies and

economics of coal-to-olefins (CTO)processes employed in China.

The study noted that, in 2011, Chinahad an ethylene capacity of 15.7 MMtand production of 14.4 MMt. On thedemand side, China’s total ethyleneequivalent consumption (including im-ports of first-order derivatives such aspolyethylene) far exceeded its domesticethylene supply. China imported nearly 8 million tons of polyethylene alone in2011, accounting for 42% of total Chi-nese demand.

In a new five-year plan covering2011–2015, the Chinese set a target that20% of the country’s ethylene produc-tion will come from other diversifiedsources, which for China—a country

with abundant coal supplies that is a net-importer of oil—practically means coal.

According to IHS, China’s domesticdemand for oil was 9.4 million bpd in2011, of which 57% was imported.

Likewise, China’s propylene produc-tion was 13.1 MMt in 2011. On the

demand side, China’s total propyleneequivalent consumption, including im-ports of first-order derivatives such aspolypropylene, also far exceeded itsdomestic propylene supply. China im-ported nearly 5 MMt of polypropylenealone in 2011, accounting for 30% of total demand. The propylene shortagein China is projected to stay at about 5MMtpy until 2020.

The processes studied included thegasification of bituminous coal by GETexaco or Shell gasifiers to produce

synthetic gases (syngas), followed by methanol synthesis and methanol-to-

olefins (MTO) production. The MTOtechnologies studied included UOP/Hydro MTO and Lurgi methanol-to-propylene (MTP) technologies. Eco-nomic evaluations were based on a USGulf Coast location. However, sincemost coal-based olefin projects are oc-curring in China, the economics in thereview were adjusted to reflect produc-tion and capital costs for a Chinese lo-cation. The adjustment was achieved by

examining the variations in technolo-gies deployed in China and accounts forcapital investment, raw materials, utility and labor costs relative to the design ba-sis used in the report.

To address the country’s chemicalfeedstock shortage, China has builtor is planning many high-capacity, in-tegrated CTO and coal-to-propylene(CTP) plants. Thirteen plants are inthe works, with four of those currently operational.

According to the IHS review, all coal- based processes analyzed in the review showed lower direct costs, but higherindirect costs (due to high capital in-

vestments) as compared to competing(petroleum-based) processes for CTOand CTP, respectively. To enable base-line comparisons of chemical engineer-ing processes for this review, return oninvestment (ROI) was the primary fac-tor considered, and the costs were not

weighted for environmental impact.For olefins production, based on

the market price of olefins at the timeof analysis, the MTO process based onoutsourced methanol offers the highestROI, followed by the integrated GE/MTO process, and finally, steam-crack-ing of naphtha, which is a petroleum-

based process. In terms of propyleneproduction, based on the market priceof propylene at the time of analysis,the MTP process based on outsourcedmethanol offers the highest ROI, fol-lowed by the integrated Shell/MTP pro-cess using bituminous coal, the integrat-

ed Shell/MTP using lignite, and finally,the integrated Siemens/MTP.

New nanoscale referencematerial to be knownas P25

The National Institute of Standardsand Technology (NIST) has issued a new nanoscale reference material for use in a

wide range of environmental, health andsafety studies of industrial nanomateri-als. The new NIST reference material isa sample of commercial titanium dioxide

powder commonly known as “P25.”NIST standard reference materials

(SRMs) are typically samples of industri-ally or clinically important materials thathave been carefully analyzed by NIST.They are provided with certified valuesfor certain key properties so that they can

be used in experiments as a known refer-ence point.

Nanoscale titanium dioxide powdermay well be the most widely manufac-tured and used nanomaterial in the world,and, not coincidentally, it is also one of the most widely studied (FIG. 1). In theform of larger particles, titanium dioxideis a common white pigment. As nanoscaleparticles, the material is widely used as aphotocatalyst, a sterilizing agent and anultraviolet blocker (in sunscreen lotions,for example).

FIG. 1. The nanoscale crystalline structure

of titanium dioxide in NIST SRM 1898(color added for clarity).

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Impact

10

“Titanium dioxide is not consideredhighly toxic and, in fact, we don’t certify its toxicity,” said NIST chemist VincentHackley. “But it’s a representative industrialnanopowder that you could include in anenvironmental or toxicity study. It’s impor-

tant in such research to include measure-ments that characterize the nanomaterial you’re studying—properties like morphol-ogy, surface area and elemental composi-tion. We’re providing a known benchmark.”

The new titanium dioxide referencematerial is a mixed phase, nanocrystallineform of the chemical in a dry powder. Toassist in its proper use, NIST has devel-oped protocols for properly preparingsamples for environmental or toxicologi-

cal studies.The new SRM also is particularly wellsuited for use in calibrating and testinganalytical instruments that measure spe-cific surface area of nanomaterials by the

widely used Brunauer-Emmett-Teller gassorption method.

Marginal increase forecastin North American

lubricant market Although it is estimated that there will be a 3% increase in tonnage carried by private fleet operators in the US through2016, this is expected to translate to amarginal increase in commercial lubri-cant consumption according to a new lubricants study from Kline and Com-pany. On-highway activity saw a surgein the latter half of 2010 that continued well into 2011. Similarly, the lacklusterperformance of the construction indus-try between 2008 and 2010 has begun

to show signs of a rebound. However,increased service implementation of longer drain interval oils due to a higherpenetration of synthetics, growth in oilanalysis practices, and an overall increasein commercial vehicles’ mechanical effi-ciency, mean that commercial lubricantconsumption is expected to fractionally increase by a compound annual growthrate of just 0.4% to 1.0% to 2016.

Shell remains the leading supplierof lubricants in North America and ac-counts for an estimated 12% of the mar-ket share in 2011, followed by ExxonMo- bil, Chevron and BP.

With the growing realization of the benefits of synthetics and their con-sequent steady uptake, value is rising, while overall demand is being suppressedthrough inherently longer service intervals. Similarly, oil analysis—the labora-tory analysis of a lubricant’s properties,suspended contaminants and wear de- bris—is being increasingly performedduring routine preventive maintenance

to provide meaningful and accurate in-formation on lubricant and machinecondition. By tracking oil analysis sampleresults over the life of a vehicle, lubricantconsumption is optimized.

Re-refined engine oils are slowly mak-ing their way into the commercial auto-motive segment; however, a majority of respondents participating in a survey forthe research cited concerns about OEMapprovals of such grades and the possiblenon-availability on the highways, as majordeterrents. In particular, the US commer-

cial trucking industry generally appearsnot yet prepared to accept re-refined oils;

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Impact

with a majority of equipment/mainte-nance managers interviewed concedingthat reliability and logistics issues areprime considerations and impediments.

A number of farmers and farm co-operatives interviewed for this study

showed minimal interest in using re-re-fined oils, believing that lubricants madeout of re-refined basestocks are of aninferior quality. However, Tushar Raval,director of Kline’s energy practice, notesthe opportunity by saying, “An immedi-ate connect can be made by the way of marketing re-refined oils as ‘sustainable’

products and consequently more easily find favor from the farming community.

“Another way of successfully propa-gating the acceptance of these grades is

by way of approvals and recommenda-tions from OEMs, such as John Deere,”

Mr. Raval said.Natural gas vehiclescould be gaining traction

A new report from PIRA Energy Group says that the sheer volume of USrecoverable gas resources relative to ex-pected demand suggests that benchmark Henry Hub gas prices will remain deeply discounted relative to oil prices beyondthis decade. Furthermore, the lengthy period of low-cost gas relative to oil hastremendously broadened support for the

view that inexpensive North Americangas is here to stay. According to the re-port, by employing off-the-shelf technol-ogies, consumers could be able to accruesubstantial savings given the latent ex-pected price advantages of natural gas vs.diesel. Such savings can also be attainedin the transportation sector, particularly

with regard to the much discussed devel-opment of natural gas vehicles (NGVs)(FIG. 2). The report concludes that fu-ture gas demand in such NGVs has enor-mous upside potential, led by privatesector initiatives, with or without federal

government assistance. Adoption of natural gas into bothUS commercial trucking and all vari-eties of fleets is approaching a criticalthreshold, which ultimately could leadto enormous gas demand growth at theexpense of diesel fuel. In an overall highcase scenario, NGV gas demand would

be capable of reaching 14 Bcfd by 2030,suggesting that as much as 2.4 MMbpdof diesel fuel demand could be at risk.Liquefied natural gas (LNG) consumedin Class 8 trucks would be responsible

for approximately 70% of that total, 10Bcfd. Fleet vehicles typically consumingcompressed natural gas (CNG) wouldaccount for the additional 4 Bcfd. PIRA forecasts natural gas will capture a moremoderate, but also impressive, 7 Bcfdshare of the US on-highway transporta-tion fuels market by 2030.

FIG. 2. Natural gas vehicles, like this Honda

Civic, are starting to gain traction in the US.

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Innovations

ADRIENNE BLUME, PROCESS EDITOR

[email protected]

Invensys introduces newtechnology offerings

Software and technology provider In- vensys Operations Management recently released a program to help clients mod-ernize and improve the performance of aging control systems and other plantequipment. The program guides clientsin calculating modernization costs, re-ducing risk, deploying advanced tech-

nology, and approaching plant upgradesstrategically and systematically.

Under the program, Invensys will de-liver full-scope consulting, project man-agement, engineering, installation andmaintenance services, and products andsolutions that minimize the risk of operat-ing obsolete technologies. Invensys starts

with an assessment to understand thecompany’s business initiatives and issues.The input received is used to develop astrategic plan that meets the plant’s busi-ness and technology needs. As part of theassessment, Invensys also helps clients es-tablish return-on-investment targets.

The company’s hardware and softwareofferings address all operational areas of the plant, including instrumentation, in-put/output (I/O) and human/machineinterface (HMI), safety and critical con-trol systems, turbomachinery assets, pro-cess safety lifecycle components, cybersecurity systems and other assets.

In another development, Invensys hasextended its virtualization technology of-

ferings. Initially focused on the MicrosoftHyperV and VMware platforms withinits software product lines, the new In-

vensys offering now includes thin clientsupport and intelligent solutions for thecompany’s Foxboro I/A series distribut-ed control system (FIG. 1).

Intended to lower total cost of own-ership and promote successful projectdelivery, the new offerings will help cus-tomers cut implementation costs, reducerisks, shorten project schedules, improvescheduling integrity, strengthen the abil-

ity to respond to project changes, and im-prove global collaboration.

The hardware offerings are formulat-ed to maximize the advantages of virtual-ization technology. Along with intelligentmarshalling and engineering services, theofferings include a new range of serversspecifically selected and qualified as anoptimized virtual machine-hosting appli-ance, a new range of solid-state operatorclient terminals, thin client managementsoftware, a USB modular alarm annun-ciator keyboard, virtual machine-hosting

software, recommendations on cyber-security best practices, guest operatingsystem licenses, and specialized supportfor Invensys control and safety offerings.


Integrated chromatographyaids fuel producers

Bruker’s Chemical and Applied Mar-kets (CAM) division’s CompassCDSdata handling system (FIG. 2) networksgas chromatograph (GC) instrumentsinto closed-loop information systemsin industrial and applied environments.The system is capable of interfacing withmultiple middleware systems, such assupervisory control and data acquisition(SCADA) systems and laboratory infor-mation management systems (LIMS).This ensures an unbroken flow of infor-mation and rapid feedback of analyticalresults to support optimum processingand product validation. Additionally, by removing the need for human interven-tion, the risk for errors is reduced.

The CompassCDS product is builtaround a central administrative core,known as the “configuration manager.”There are several customized modulesthat are specific to the petrochemicalsindustry, including simulated distilla-tion, hydrocarbon analysis and PIONA+(paraffins, isoparaffins, olefins, naph-thenes and aromatics, plus oxygenates).

A simple graphical user interface allowsall operations to be carried out from only two screens, which enables ease of useand expedites training. Additionally, the

system’s added IntelliUpdate feature au-tomatically corrects both retention time

and timed events on chromatograms fol-lowing instrumental variation over time.


Largest German cellulosicethanol plant starts up

Swiss specialty chemicals company Clariant recently inaugurated Germany’s

biggest pilot plant (FIG. 3) in Straubing,Bavaria. The €28 million (MM) plant,

which is based on Clariant’s sunliquid

FIG. 1. Invensys’ virtualization system allows

the user to consolidate many PCs and servers

into a high-availability virtual host server.

FIG. 2. Bruker CAM’s CompassCDS system

networks gas chromatograph instruments withinfosystems.

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Ivs

echlgy, wll prce p 1,000merc s f celllsc ehl frmr 4,500 merc s f whe srw.The pl pl wll cfrm he ech-lgcl fesbly f he slq ech-qe, he prcess wll ler be se

srl-scle pl. Accrg ses, Germy p-elly hs r 22 MM merc sf srw h cl be se fr eergy prc, whch wl be sffce cver r 25% f he cry’scrre gsle reqremes. GermFeerl Mser Aee Schv cm-mee, “Ths pl clerly emsresh prcs rlly bse pe-rlem c be mfcre he smesr sg bmss. Ths ew plserves s mpr crb

ssble becmy.”Select 3 at www.HydrocarbonProcessing.com/RS

Software protectsagainst cyber attacks

Heywell’s Mgeme f Chge(MOC) s egre, - mleh rs p f DOC4000 ssessmesfwre leverges Web 2.0 echl-ges fcle frm flw cllbr. MOC ebles cresesfey cmplce, helps precgs hres f cyber cks sfey

hzrs pls, by effecvely mggchges pprvls. FIG. 4 llsres he

wrkflw prcess fr MOC.MOC ls ebles mprve hlg

f crcl sses, clg cme-e chges, ehce reglry cmpl-

ce, recs errr-pre mlMOC sks, hrze chgesh crese rsk.

The mle s specfclly esge mclly eec ll mchges, reccle MOC cses chges he m sysem, mclly geere reprs f -reccle chges, ll 45% lwer csh ml mehs. Ths ebles rpr-cse lyss esre bsesscy, c rece pelly sgfc fcl mpc prc.


Technology enables ethanolproduction breakthrough

As cres cmpes evleher spply ps mee grwg rs-pr fels em, hey wll ee

blce fr prres: sfe cle fel blescks, cs, eergy secry, glbl evrmel mpc. Celese

beleves h ehl prce sg Cel-ese TCX Techlgy (FIG. 5) s he besfel chce mee hese csers.

Ehl hs lrey ge ccepce ms glbl mrkes s hgh-ce,xc, begrble fel. Hwever,rl prc prcesses re ecmclly vble, s hey cmpee frrble l ypclly reqre gver-me mes r sbses.

Celese TCX Techlgy prcesehl cmmerclly vble, lw-cs mer, frm lclly vlble hy-rcrb resrces sch s rl gs cl, rher h frm cr r sgr

ce. Fr hese ress, rble lse r gverme sppr s reqre.Select 5 at www.HydrocarbonProcessing.com/RS

Yokogawa’s controllercertified as flow computer

Ykgw Elecrc Crp.’s STARDOMFCN ms crller (FIG. 6) wsrecely cerfe by Mesreme C-

fr se s flw cmper. The cerf-c s bse he eerm hhe crller hs he sme ccrcy s cvel flw cmper. Devces sb-

jec s pprvl re se mesre gs,elecrcy, mss vlme, hey reese br rge f crer cl-g esg, csrc, mrkg, cc-rcy selg meh.

Whle cvel flw cmpersmee ll meerg reqremes, here sw re wr embeg hs fc-ly prgrmmble lgc crl-

lers (PLCs) reme elemery s(RTUs), whch re vle fr her -rble csrc versle crlcpbles.

I cvel lgrsmer sgls, whch c be ffece

by se vrs he mbeemperre, he STARDOM FCN c-rller spprs fel gl cmmc- prcls sch s HART, Mbs, Foundation felbs fr se wh we rge f rsmers. Ykgw’spl resrce mger (PRM) ssemgeme sysem creses m-bly whle recg bh egeergme he cs f mrg wely srbe fcles.


SPECTRO wins ACHEMAInnovation Award

A he ACHEMA chemcl egeer-g bechlgy re shw Frkfr, Germy, Je, SPECTRO

Alycl Isrmes receve he I-

v Awr fr s SPECTROBLUEICP-OES specrmeer (FIG. 7).Irce 2011, he SPECTRO-

BLUE ICP-OES specrmeer s rgeefr evrmel lbrres eef qck ccre lyses f w-er, wsewer, sewge slge slsmples fr xc hevy mels. SPEC-TROBLUE’s r-cle, pcl plsmerfce vers he wy wh rsrem, mrkg vce specrm-eer echlgy.

Aher vve fere f SPEC-

TROBLUE s s mprve smple -rc. SPECTRO hs sgfcly

FIG. 3. Clariant’s cellulosic ethanol pilot plant

in Straubing is the largest in Germany.

FIG. 4. Honeywell’s MOC software helps

protect plants against safety threats.

FIG. 5. Celanese’s TCX Technology producesethanol from hydrocarbons.FIG. 6. Yokogawa’s STARDOM FCN controllerhas been certified for use as a flow computer.

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Innovations

17

shortened the path of the sample into theplasma, which decreases the duration of the analysis and reduces carryover effects.

SPECTROBLUE’s operating softwarealso includes new, user-friendly functions,such as a comprehensive Smart Analyzer

Vision software package and a Smart UserInterface that simplifies routine operation.Select 7 at www.HydrocarbonProcessing.com/RS

Mobile tool enablesportable pH reading

Sensorex has developed a mobile ac-cessory for pH measurements that is com-patible with Apple iPod, iPhone and iPaddevices. The patent-pending PH-1 pHmeter accessory (FIG. 8) measures and re-cords pH values in the lab or field for usein environmental, educational and indus-

trial applications.The PH-1 accessory plugs into the

standard Apple dock connector and ispowered from the Apple device, requiringno supplemental energy source. It uses aSensorex pH electrode to measure pH ina range of 0–14, with accuracy to 0.01 pH.It operates in ambient temperatures of 0°C–40°C and in solutions of 0°C–100°C.

The free Sensorex app displays pH,millivolts, ambient temperature and so-lution temperature in real time. The CE-marked device supports one, two, threeor more calibration points, and it sendsreadings by email for later analysis. Also,

when used with a GPS-enabled device,the pH meter application will recordmeasurements with both timestamp and

geographic coordinates, eliminating tran-scription errors and improving efficiency.


French consortiumeyes BioOil upgrading

Axens, IFP Energies nouvelles(IFPEn) and Dynamotive recently an-nounced completion of agreements forthe development, industrialization andcommercialization of a proprietary pro-cess to produce transportation fuels fromDynamotive’s BioOil pyrolysis oil. Theprocess is said to have competitive advan-tages compared to existing processes andcompeting technologies.

Dynamotive will provide pyrolysis oilto IFPEn for the development program,

while Axens will lead the development,

industrialization and commercializationof the upgrading technology. Laboratory-scale units have been developed and oper-ated in Canada and at IFPEn facilities inLyon, France, where Dynamotive’s BioOil

was upgraded to synthetic hydrocarbons.Dynamotive’s BioOil technology is

based on the application of fast pyroly-

sis (burning without oxygen) to biomass waste (agricultural and forestry) to pro-duce a high-quality, versatile and eco-nomic biofuel. BioOil can be further con-

verted into vehicle fuels and chemicals.Select 9 at www.HydrocarbonProcessing.com/RS

For a confidential C-level executive search or placement of management or sales

positions, please call Thomas Brinsko or Raul Hernandez in Houston at 281-538-9996 or

visit www.bicrecruiting.com.

Providing executive recruiting services to the energy markets.

Recruiting “A-level” candidates

for your C-level positions(Management & Sales positions also)

For more information on strategic marketing through BIC Alliance,

investment banking services through IVS Investment Banking

or custom books, event planning or speaker services through

BIC Media Solutions, contact Earl Heard or Thomas Brinsko at

(800) 460-4242, or visit www.bicalliance.com.

“BIC had efficient

processes and highly

qualified candidates, both

of which were instrumental

in making the investment

in a strategic position

an informed decision.”

— Bret Pardue,

CEO and President,

USA Environment

FIG. 7. SPECTRO Analytical Instruments was

awarded at ACHEMA for its SPECTROBLUEspectrometer.

FIG. 8. Sensorex’s mobile accessory for pH

measurements is compatible with a range

of Apple devices.


7/22/2019 gulfpub_hp_201210.pdf


Select 55 [email protected] at www.HydrocarbonProcessing.com/RS

Avantis Eurotherm Foxboro IMServ InFusion SimSci-Esscor Skelta Triconex Wonderware

© Copyright 2012. All rights reserved. Invensys, the Invensys l ogo, Avantis, Eurotherm, Foxboro, IMServ, InFusion, Skelta, SimSci-Esscor, Triconex and Wonderware are trademarks of Invensys plc, its subsidiaries or affiliates. All other brands and product names may be trademarks of their respective owners.

Real Collaboration. Real-Time Results.TM

Breaking through Heavy Oil Barriers

Facing a labyrinth of ever-changing feedstock and production demands? Invensys Operations Management helps you break through the barriers with our unique

Heavy Oils models, just one part of the SimSci-Esscor suite of refinery wide optimization

software solutions. For more information visit us at: iom.invensys.com/heavyoils


7/22/2019 gulfpub_hp_201210.pdf


Construction

HELEN MECHE, ASSOCIATE EDITOR

[email protected]

North America

Jacobs Engineering Group Inc. has a contract from Methanex Corp. toprovide engineering, procurement andconstruction services for a methanolproduction facility in Louisiana. Offi-cials estimate the construction value to

be $550 million. Jacobs is already executing site-specif-

ic engineering and construction manage-

ment for the 225-acre location in Geis-mar, Louisiana, from its offices in BatonRouge, with support for the disassembly from its Santiago, Chile, office. The plantis expected to be operational in the sec-ond half of 2014.

KBR has a general works contractfor phase-two construction at a raw gas-processing and compression facility nearDawson Creek, British Columbia, Can-ada. KBR’s Canadian subsidiary, KBR Wabi, will execute construction and relat-ed site support for the facility’s expansion,increasing the existing capacity to 100million scfd. The award follows KBR’s re-cent work—delivering pipe-rack fabrica-tion and module assembly for phase oneof the Dawson Creek plant.

A joint-development agreement, fo-cusing on bio-based butadiene, has beensigned by INVISTA and LanzaTech to de-

velop one-step and two-step technologiesfor converting industrial waste-gas carbon-

monoxide (CO) into butadiene. Initialcommercialization is expected in 2016.Initially, the focus will be on producing

butadiene in a two-step process from Lan-zaTech CO-derived 2,3-butanediol (2,3BDO). A direct single-step process willalso be developed to produce butadiene di-rectly through a gas-fermentation process.

INVISTA and LanzaTech will also jointly collaborate on developing toolsthat will extend this technology—oncedeveloped—to directly produce otherindustrial chemicals. These include ny-

lon intermediates, from CO containing waste gases, using LanzaTech’s gas-fer-

mentation technology and proprietary biochemical platform. INVISTA is build-ing internal biotechnical capability todevelop biological routes to its productsand feedstocks.

Praxair, Inc., has broken ground onits new air-separation unit in Memphis,Tennessee. With a capacity of 600 tpd,the new plant is scheduled to start up inthe second quarter of 2013.

INVISTA has selected its productionfacility in Orange, Texas, as the initiallocation to install its next-generation adi-ponitrile (ADN) technology. ADN is acritical intermediate chemical used in themanufacture of nylon 6,6.

The project to convert the Orange siteto the new technology is well underway,and INVISTA is expected to invest morethan $100 million at the facility in thenext 18 months.

The technology, a new butadiene- based chemistry, is said to improve prod-uct yields and ease of operations, whilerequiring a lower annual-maintenanceinvestment compared to existing tech-nology. Evidenced through operation of apilot-scale facility, also located in Orange,the technology also delivers significantair emission and waste reductions. Thecompany hopes to be in full production

by mid-2014.

Cheniere Energy Partners, L.P. has

completed all milestones and has issuedBechtel Oil, Gas and Chemicals, Inc., with a full notice to proceed on construc-tion of the Sabine Pass Liquefaction Proj-ect’s first two liquefaction trains. The firstliquefaction train is expected to start op-erations as early as 2015. The second liq-uefaction train is expected to commenceoperations six to nine months after thefirst train’s startup.

Flint Hills Resources is consideringspending more than $250 million to en-

able its West refinery in Corpus Christi,Texas, to process more Eagle Ford crude

oil, while extending its ability to reducecriteria air emissions. The company op-erates two Corpus Christi refineries: the

West refinery, with a capacity of about230,000 bpd, and the East refinery, witha capacity of about 70,000 bpd.

Flint Hills Resources expects to sub-mit the permit applications to the TexasCommission on Environmental Quality and the US Environmental Protection

Agency in the coming weeks.

South America A subsidiary of Foster Wheeler AG’s

Global Engineering and ConstructionGroup has a contract from Petrobras fora world-scale grassroots gas-to-chemicalscomplex—Complexo Gás-QuímicoUFN-IV—in Linhares, Espirito SantoState, Brazil. Foster Wheeler will provide

basic engineering design (BED), front-endengineering and design (FEED), as well astechnical assistance and training duringthe engineering, procurement and con-struction (EPC) phase through to success-ful completion of plant performance tests.

The BED and FEED will be includedin the company’s third-quarter 2012

bookings. The provision of technical as-sistance and training will be booked ata later date, after the FEED is complete,

when Petrobras advises that it is proceed-ing with the project’s EPC phase.

TREND ANALYSIS FORECASTING

Hydrocarbon Processing maintains an extensive

database of historical HPI project information.

The Construction Boxscore Database is a 45-year

compilation of projects by type, operating

company, licensor, engineering/constructor,

location, etc. Many companies use the historical

data for trending or sales forecasting. The

historical information is available in comma-

delimited or Excel® and can be custom sorted

to suit your needs. The cost depends on the size

and complexity of the sort requested. You can

focus on a narrow request, such as the history

of a particular type of project, or you can obtain

the entire 45-year Boxscore database or portions

thereof. Simply send a clear description of the

data needed and receive a prompt cost quotation.

Contact Lee Nichols at 713-525-4626

or [email protected]

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Construction

Foster Wheeler will act as integrator forthe entire complex, managing the overallBED and FEED, including managing theprocess licensors and Brazilian subcon-tractors. The BED/FEED phase is sched-uled for completion at the end of 2013.

The complex is expected to producein excess of 1 million tpy of ammonia andurea fertilizers, methanol, acetic acid, plusformic acid and melamine, helping to re-duce Brazil’s imports of these products.

EuropeClariant has inaugurated what is

said to be Germany’s biggest pilot plantfor producing climate-friendly celluloseethanol from agricultural waste. Locatedin Straubing, Bavaria, and supported by the Bavarian government and the Feder-

al Ministry for Education and Research,the futuristic project will produce upto 1,000 tons of cellulose ethanol fromaround 4,500 tons of wheat straw basedon Clariant’s sunliquid technology. Itrepresents an investment of around €28million. The sunliquid process is an in-novative biotechnological method thatturns plant waste products, such as grainstraw and corn straw, into second-gener-ation cellulose ethanol.

Marquard & Bahls, through its sub-sidiary Bomin, and The Linde Group,

will establish a joint-venture ( JV) com-pany to build infrastructure for liquefiednatural gas (LNG) in Europe’s maritimesector. The transaction is subject to the ap-proval of the relevant antitrust authorities.The 50/50 JV is due to start its operationsin the latter part of 2012, with its head-quarters based in Hamburg, Germany.

The JV will set out to establish anLNG supply chain and to provide reli-able, safe and environmentally friendly

fuel to ship owners and operators. Linde will contribute its vast experience incryogenics and its best-in-class engineer-ing know-how, while Bomin will supportthe JV with its excellent track record inmaritime bunker-fuel trading and op-erations. The new company will estab-lish operations in a number of key portsthroughout the so-called “emission con-trol areas” in Northwest Europe.

CB&I has an award from BASF for theengineering, procurement and construc-

tion management of a new butadiene-extraction plant in Antwerp, Belgium.

The contract, which is valued in excess of $50 million, is an essential part of the to-tal BASF investment amount, which will

be in the high double-digit million eurorange. The plant is scheduled to start upduring 2014.

Jacobs Engineering Group Inc. hasa five-year enterprise frame agreement(EFA) from Shell Global SolutionsInternational B.V. to provide engineer-ing and project management services toShell’s European downstream assets.

The contract has the options to be re-newed for an additional five years and/orto be extended to other Shell businessessuch as upstream, and beyond Europe tothe Middle East and Africa. Under theEFA, Jacobs will provide services rang-

ing from feasibility studies and smallplant modifications to discrete projectsfor Shell’s major refining and chemicalsites in Pernis, The Netherlands, and inRhineland, Germany.

UOP LLC, a Honeywell company,has been selected by Lukoil to providetechnology to produce blending compo-nents used to make high-octane gasolineand petrochemicals at Lukoil’s facility inNizhny Novgorod, Russia.

Lukoil will license an integrated suiteof Honeywell’s UOP technologies toproduce high-quality gasoline-blendingcomponents, propylene and other petro-chemicals.

The new units, expected to start up in2015, will produce more than 1 millionmetric tpy of gasoline-blending compo-nents and more than 170,000 metric tpy of propylene. In addition to technology licensing, Honeywell’s UOP and a num-

ber of its affiliates will provide engineer-ing design, catalysts, adsorbents, equip-

ment, staff training and technical servicefor the project.Honeywell’s UOP technology to be

used in this project includes: Honeywell’sUOP FCC process, to convert straight-run atmospheric gasoils, vacuum gasoils,certain atmospheric residues and heavy stocks recovered from other refinery op-erations into high-octane gasoline, pro-pylene and light fuel oils; Honeywell’sUOP HF Alkylation process to producea high-quality gasoline-blending com-ponent, typically referred to as alkylate;

Honeywell’s UOP Caustic Merox processto remove sulfur from liquefied petro-

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Construction

leum gas (LPG) streams; Honeywell’sUOP Huels Selective HydrogenationProcess (SHP) to minimize acid con-sumption in the alkylation unit, produce2-butene and maximize alkylate yields;and Honeywell’s UOP Butamer process

to convert butane to isobutane, a primary feedstock used to produce alkylate in theHF Alkylation process.

LANXESS has chosen BurckhardtCompression to deliver one process gascompressor for its chemical productionsite in Leverkusen, Germany. The com-pressor will be used to compress ethylenefrom 17 bara to 495 bara. In addition,Burckhardt Compression (Deutschland)GmbH has been awarded an order fromLANXESS to revamp two existing process

gas compressors.

A gas-to-liquids (GTL) project in Uz- bekistan was named OLTIN YO’L GTLat a formal ceremony in Tashkent involv-ing representatives from the three joint-

venture ( JV) companies: Uzbekneft-egaz, Sasol and PETRONAS.

The naming of the JV project fol-lowed a ceremony to mark the start of infrastructure development by the Gov-ernment of Uzbekistan at the proposedGTL plant site at Shurtan in the southof Uzbekistan. It also aimed at support-ing the project schedule to enable a finalinvestment decision, which is expectedduring the second half of 2013.

When commissioned, the 38,000-bpdplant will produce a combination of GTLdiesel and GTL naphtha and, in an im-portant development in the applicationof GTL fuels, GTL kerosine for the avia-tion sector.

Neste Oil has completed the first

phase of its project to build a pilot plantfor producing microbial oil. Plant con-struction is on schedule and on budget.The first phase will enable the growth of oil-producing microorganisms, and thefollowing phases will concentrate on raw material pretreatment and oil recovery.The goal is to develop the technology so that it is capable of yielding commer-cial volumes of microbial oil for use as afeedstock for NExBTL renewable diesel.Commercial-scale production is expect-ed by 2015 at the earliest.

The pilot plant is expected to be fully complete in the second half of 2012, and

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Construction

it represents an investment of approxi-mately €8 million by Neste Oil.

Microbial oil technology is attractive because of its efficiency and sustainabil-ity. Neste Oil has carried out pioneeringresearch in the field and has applied for

numerous patents covering its microbial oil technology. A number of partnershave been involved in this work, includ-ing Aalto University.

In May 2012, ThyssenKrupp Uhde won a front-end-engineering and designcontract for a single-train polypropylene(PP) plant based on LyondellBasell’s Spheripol process technology for Zap-SibNeftekhim L.L.C, a wholly ownedsubsidiary of SIBUR.

The 500,000-tpy plant is planned to

be constructed in Tobolsk, Russian. Theplant will produce a wide range of high-quality PP brands.

Evonik Industries has laid the foun-dation stone for a new, large plant toproduce functionalized polybutadienesin Marl, Germany. The plant, with a ca-

pacity of several thousand metric tpy, isscheduled for completion in mid-2013.The investment, in the company’s largestproduction site worldwide, is in the middouble-digit million euro range.

The new plant can make optimum use

of the existing infrastructure and raw ma-terial supplies, and utilize synergies withthe current polybutadiene plants in theMarl Chemical Park.

Middle EastKAR Group has announced the third

expansion of its Kalak refinery to 185,000 bpd. Process units and utilities are beingprovided by Ventech Engineers LLC of Pasadena, Texas. Ventech has providedmodularized crude-distillation units,naphtha hydrotreaters, catalytic reform-

ers, isomerization units and demercapta-nization systems, as well as gas plants andsupporting utilities to the project.

This is the refinery’s third expan-sion, and is a continuation of Ventech’smodular construction methods. The firstphase utilized 26 process modules to add20,000 bpd of refining capacity to KAR’s

existing 20,000-bpd plant. The subse-quent second phase provided an addi-tional 60,000 bpd of total refining capac-ity and was completed in 2011.

The third expansion consists of two30,000-bpd modular complexes at the

same site, as well as a 15,000-bpd con-densate-processing facility. Once thislatest phase is complete and operational,total capacity at the Kalak refinery will

be over 185,000 bpd, and it will report-edly remain the country’s sole producerof unleaded gasoline, as well as the largestprivately owned refinery in Iraq.

Construction has started in Abu Dha- bi, of what is said to be the largest Clausplant in the world. By the end of 2013,once construction is complete, Haldor

Topsøe will supply the plant with 380tons of the gas-treating catalyst TK-220.

TK-220 is a CoMo hydrotreatingcatalyst specifically developed for treat-ing tail gases derived from Claus or othersimilar units. The delivery is part of anagreement that Haldor Topsøe has made

with BASF.

Good thinking.Feedback from our users is what inspires us to keep making

CHEMCAD better. Many features, like this one, were added to

the software as a direct response to user need. That’s why we

consider every CHEMCAD user part of our development team.

Get the whole story behind this user-inspired feature and

learn more about how CHEMCAD advances engineering

at chemstations.com/GoodThinking.

Simultaneous heat transfer and

mass transfer model in column.

C H E M

C A D 6 . 5

N O W A V A I L

A B L E

Engineering advanced © 2012 Chemstations, Inc. All rights reserved. | CMS-1789 9/12


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Construction

Asia-Pacific

Jilin Qianyuan Energy Developmenthas selected Chemtex, along with Black & Veatch’s patented PRICO LNG tech-nology, to deliver a major liquefied natural

gas (LNG) facility. Expected to be com-pleted in late 201, the 500,000-Nm3/dplant will reportedly be the largest of itskind in Northeast China. It will be deliv-ered by the Chemtex/Black & Veatch teamusing a complete lump-sum engineering,procurement and construction package.

The new facility will liquefy inlet pipe-line natural gas. The LNG will be usedprimarily by trucks and other vehicles asan alternative fuel to diesel and petrol.

In addition to utilizing PRICO technol-ogy, the plant integrates a nitrogen-strip-

ping process. This will contend with highnitrogen levels in the pipeline feed gas. A special boil-off gas reliquefaction system

will also be installed to prevent unneces-sary fuel loss and increase plant efficiency.

GTC Technology US, LLC, is licens-ing its GT-BTX extractive distillation

process to produce high-purity aromat-ics at Reliance Industries’ Jamnagarrefining and petrochemical complex inGujarat, India. This license is part of aconsortium with CB&I Lummus Tech-nology to supply technology for a multi-

unit complex for benzene and paraxy-lene production.

Australia Pacific LNG has selectedtechnology developed by HoneywellProcess Solutions (HPS) AdvancedSolutions business to deliver a data con-solidation and reporting technology framework. The solution, built on Intu-ition Executive, will support the produc-tion, operations and asset-managementfunctions of its world-class coal-seam gas(CSG) to liquefied natural gas (LNG)

project. Origin, the upstream operatorof the Australia Pacific LNG project, isthe largest producer of CSG in Australia,supplying gas to power stations to pro-duce electricity with lower greenhousegas emissions.

Australia Pacific LNG’s operationalframework, built on Intuition Executive,

will support improved communicationand data management, cross functional

workflows and improved notification of key operational events to better analyze,prioritize, automate, and manage opera-tional tasks and abnormal situations.

Air Liquide has laid the first stoneof a new hydrogen plant through a long-term agreement with Zhejiang HuafonSpandex Co., Ltd. (Huafon) to supply hydrogen for its 120,000-tpy cyclohexa-none project located in Liaoyang Aro-matics and Fine Chemical Park, Liaoyangcity, China.

Under the agreement, Air Liquide willinvest in a new steam methane reformer(SMR) unit that will supply 1,000 Nm/hr of hydrogen, as well as steam to Hua-

fon via pipelines. This new unit, which isexpected to be commissioned by the endof 201, uses Lurgi’s latest technologiesproviding high reliability, world-classsafety and energy efficiency, and will bedesigned and manufactured by the AirLiquide engineering and constructionteam based in Shanghai.

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Construction

SIBUR Petrochemical India, a sub-sidiary of SIBUR, has started operationsin Mumbai, India. The company’s pri-mary focus is to construct a butyl-rubberfacility in Jamnagar. The plant, which

will operate at a capacity of 100,000 tpy,

is being built as a joint venture with Reli-ance Industries. The new subsidiary will work alongside Indian partners, as wellas provide support to SIBUR employeescoming to India to carry out installationand startup work at the new plant.

Synthesis Energy Systems, Inc.’s syngas production facility for its Yima

joint-venture ( JV) coal-to-methanolproject in Henan Province, China, com-pleted a test run of the first of three gas-ifiers currently under commissioning.

During the commissioning phase,each of the three gasifiers will be oper-ated under various test conditions to

vet the gasifier and support systems toprepare the facility for commercial op-eration. This test was the first for thisgasifier system operating on oxygenfrom the project’s air-separation unit.

Coal supplied by Yima was introducedinto the gasifier, which operated for sev-eral hours while the Yima JV team suc-cessfully gathered data that will help inpreparation for plant startup. The proj-ect will continue in the commissioning

phase for several more weeks and is ex-pected to move into commercial opera-tion later in 2012.

Intergraph has a contract with San-tos for the use of SmartPlant Enterprisefor Owner Operators (SPO), along withother SmartPlant Enterprise solutions.Santos will use Intergraph technol-ogy to manage its existing facilities andthose in its Gladstone liquefied naturalgas (GLNG) project in Queensland,

Australia .

Santos GLNG will use world-lead-ing technology to process coal-seamgas (CSG) into LNG. The project is apartnership between Santos (operator),PETRONAS, Total and KOGAS.

SPO enables Santos to address in-teroperability issues, while enhancingplant safety and reliability, quality and

productivity. In addition to SPO, San-tos has implemented SmartPlant 3D,SmartPlant Foundation, SmartPlant In-strumentation, SmartPlant Electrical,SmartPlant P&ID and Leica Geosys-tems laser-scanning solutions, and also

used the Intergraph Data ConversionCenter for converting P&ID drawingsinto intelligent data. Besides the GLNGproject, Santos will also use these designand engineering solutions for the entirelife cycle of its facilities for both green-field and brownfield projects, with plansto extend these solutions to its existingfacilities within the A sia-Pacific region.

CB&I has a contract with the HebeiHaiwei Group for the license and basic-engineering design of a grassroots pro-

pane dehydrogenation unit to be locatedin Jingxian, Hebei Province, China. Theunit will use the CATOFIN propane de-hydrogenation process from LummusTechnology, which uses Süd-Chemie’slatest CATOFIN catalyst to produce500,000 metric tpy of propylene. Theunit is expected to start up in 2015.

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CONSTRUCTION BOXSCORE UPDATE / ConstructionBoxscore.com

26OCTOBER 2012 | HydrocarbonProcessing.com

The above projects represent only a fraction of data updated monthly in the Construction Boxscore Database. For more information please go to www.ConstructionBoxscore.com or contact Lee Nichols at 713-525-4626 or [email protected].

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COMPANY CITY PROJECT EX CAPACITY UNIT COST STATUS YR CMPL LICENSOR ENGINEERING CONSTRUCTOR

ASIA/PACIFICChina Jilin Qianyuan Jilin LNG 500 Nm3/d U 2013 Chemtex Intl | Black & Veatch

Energy DevelopmentKyrgyzstan Socar Chuy Province Refinery 2 MMtpy 250 P 2013Thailand PTT Public Co Ltd Map Ta Phut Waste heat recovery unit None E 2013 FW Samsung EngIndia Reliance Industries Ltd Jamnagar Refinery (1) EX None 1000 P 2014 GTC, Inc FluorIndia GAIL (India) Ltd Pata Ethylene Dimerization 20 Mtpy U 2014 AxensIndonesia BP Papua LNG (3) BY 3.8 MMtpy 7000 U 2017Kyrgyzstan Undisclosed Chuy Province, Kara-Balta Refinery None P

CANADAAlberta OPTI Canada Inc Fort McMurray, Long Lake Sulfur Recovery (2) 620 LTPD U 2012 Shell | Fluor FluorSaskatchewan Consumers Coop Refineries Regina Cracker, FCC (2) EX 22 Mbpd C 2012 UOP Mustang | IAGSaskatchewan Consumers Coop Refineries Regina Crude Unit EX 30 Mbpd 1500 C 2012 UOP Mustang | IAG

EUROPEGermany Evonik Industries AG Marl Polybutadiene Mt U 2013Russian Federation NKNK Tatarstan Ethylene 1 MMtpd 40 F 2013 CB&IRussian Federation Sibur Tobolsk Ethylene 1.5 MMtpy F 2013 LindeRussian Federation Sibur Tobolsk Polyethylene (4) 1.5 MMtpy F 2013 INEOS TechnipRussian Federation Sibur Khimprom Tobolsk Polypropylene 550 Mtpy E 2013 INEOS Linde | VnipineftRussian Federation Tobolsk-Polimer Tobolsk Polypropylene 500 MMtpy F 2013 LyondellBasell | INEOS ThyssenKrupp | Linde-KCA Fluor | Linde-KCARussian Federation Haldor Topsøe Tyumen Hydrogen Purifier EX 7 MMtpy U 2013 UOPRussian Federation Lukoil Nizhny Novgorod FCC Gasoline Desulfurization 1.1 MMtpy U 2015 Axens | UOPGermany Lanxess Leverkusen Compressor RE None U Burckhardt Compression

LATIN AMERICASurinam Staatsolie Paramaribo Refinery EX 15 Mbpd 575 U 2013 CB&I Lummus Aker Solutions Saipem | HoneywellMexico Alpek Cosoleacaque Cogeneration 85 MW U 2014 Sener Sener

Colombia Ecopetrol Barrancabermeja Hydrocracker RE 80 Mbpd E 2016 Axens FW AxensMexico Pemex Tula Refinery 250 Mbpd 9000 E 2016 ICA Fluor

MIDDLE EASTSaudi Arabia Sadara Chemical Co. Jubail 2 Ind Zone Complex None 360 E 2014 TecnimontSaudi Arabia Sadara Chemical Co. Jubail Ind City Complex 3 MMtpy 20000 U 2016 Tecnimont ABB | LindeOman OOC/IPIC Duqm Petrochemical Complex 230 bpd 1500 P 2017 ShawIran NIORDC Shiraz Refinery 120 bpd 1300 PQatar RasGas Ras Laffan Gas Processing None E JGC

UNITED STATESTexas Mexichem/Oxychem Ingleside Ethylene Cracker 500 tpy F 2016

The above projects represent only a fraction of data updated monthly in the Construction Boxscore Database. For more information please go to www.ConstructionBoxscore.com or contact Lee Nichols at 713-525-4626 or [email protected].


7/22/2019 gulfpub_hp_201210.pdf


©2012 Air Products and Chemicals, Inc.

The world’s largest hydrogenpipeline network delivers...

The world’s most reliablehydrogen supply.

It’s the kind of massive project only a global leader would undertake.

Anticipating that hydrogen needs along the Gulf Coast of North America

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network. By building a 180-mile (290-km)-long pipeline that connects our

existing Texas and Louisiana systems, we’ve united 22 hydrogen plants and

600 miles (965 km) of pipeline, with a total system capacity of over one billion

SCFD (1.3 million Nm3/hr). So if an event disrupts operations on one side of

the Gulf, hydrogen can keep flowing from the other, giving our refinery and

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Hydro, Inc. l HydroAire, Inc. l Hydro East, Inc. l Evans Hydro, Inc. l Hydro South, Inc. l HydroTex Golden Triangle l HydroTex Dynamics, Inc.

HydroTex Deer Park, Inc. l CW Hydro, Inc. l Hydro Australia, Pty. Ltd. l Hydro Vietnam, Co. Ltd. l Safe-T Hydro, Inc.

Hydro Scotford, Inc. l Hydro Middle East, Inc.


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Reliability HEINZ P. BLOCH, RELIABILITY/EQUIPMENT [email protected]

Equipment life extension involves upgrades

Every plant wants to get more service life from site machin-ery. Since about 1990, quite a number of start-up consultingcompanies have formed to advise clients on equipment lifeextension. These companies use different approaches: someapply large-scale, computer-based statistical methods, whileothers blend traditional estimates with risk-based analysis. Allof these approaches have merit, but none of them can provideall of the answers with high precision. The key ingredients of any useful endeavor include reviewing the asset’s past failure

history, examining nondestructive testing (NDT) data, andupgrading the weakest link.

Failure history counts. Wherever failure history exists andthe failures’ root causes were analyzed, authoritative answerson remaining service life are possible. The same can be saidfor thoroughly evaluating NDT data, which can provide focusto determine remaining life.

On stationary equipment and piping, wall thickness is of great importance. Loss of material decreases the allowable pres-sure rating. Corrosion and erosion can lower the safety of theequipment; thus, continued operation becomes risky. Thick-ness changes often occur at locations, such as elbows, where flu-id flow changes direction. Changes in velocity such as at valvesor near restrictions are of high interest. Some can be investigat-ed with NDT methods, which certainly include X-ray imaging,among others. The extent of fluid-dependent corrosion can beestimated from coupons placed in piping and vessels.

Pumps. For pumps, failure history and past repair datamust be matched with a thorough understanding of upgrademeasures that have been taken by successful “best-of-class” or-ganizations. Advanced lube application will probably be partof it, as will the extension of oil replacement intervals now pos-sible by synthetic lubricants and advanced bearing housingprotection measures.

To what extent superior bearings (ceramic hybrids) are of value must be determined on a pump-by-pump basis. Perhapsa set of angular bearings with unequal contact angles should

be installed in your problem pumps. The symmetrical setsof angular contact bearings mentioned in the most widely used pump standard may not perform adequately. The ex-tent that superior sealing technology (dual seals, as shown inFIG. 1) provides more value must be determined on a service-

by-service basis. As a general rule, the industry’s v iew aboutdual seals deserves to be reassessed. Sealing technology hasmade considerable progress in the past two decades. Virtu-ally all present-day seals are cartridge-style configurations,and braided packing is being displaced by mechanical seals in

the hydrocarbon processing industry (HPI), as well as in thepower generation and mining industries.

However, not all manufacturers of mechanical seals usethe same acceptance test procedure for their products. A

widely applied industry standard stipulates using air as a testgas for mechanical seal tightness. Of course, these seals areultimately intended for safe containment of flammable, toxicor otherwise hazardous liquids. While the standard’s expec-tation is that leakage from these seals does not exceed 5.6gm/hr, recent tests showed that merely following this easy testing routine can actually allow orders of magnitude moreliquid to escape. It is, therefore, advisable to question seal

vendors on the matter and to purchase only products thatmeet the purchaser’s safety and reliability requirements. We

all want seals to leak no more than 6.5 gm/gr when first in-stalled on pumps.

FIG. 1. Dual mechanical seal in a slurry pump. The space between

the sleeve and the inside diameter of the two sets of seal faces

is filled with a pressurized barrier fluid—usually clean water.

Source: AESSEAL Inc., Rockford, Tennessee, and Rotherham, UK.

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http://slidepdf.com/reader/full/gulfpubhp201210pdf 32/105Hydrocarbon Processing | MONTH 201231

Reliability

Lubrication systems. Lubricant application and standby bearing preservation are especially important in humid coast-al climates and in dust-laden desert climates. Oil mist is theanswer. The settling of foundations and pipe supports should

be addressed. For steam turbines, the blade stresses and water

quality must be compared with those units in successful long-running installations elsewhere.

In gearboxes, the remaining service life is largely examined by tooth loading (stresses on tooth face) and temperaturemeasurements. In all instances, synthetic oils from the mostexperienced oil formulators will greatly extend gear life. Oiladditives are everything. They drive both cost and service life.Oil cleanliness is equally important.

Certain warehouse spares (gears, electric motors, etc.)should be upgraded, if important. If doing so, it is likely to speedup re-commissioning after an unanticipated future shutdown.

Compressors. For compressors, engineers should considerthe mentioned points. Valve technology and piston velocity are important comparison-worthy parameters on reciprocat-ing compressors. Onstream performance tracking and priorsealing technology are important for centrifugal compressors,etc. They determine seal system upgrade potential. Neveroverlook couplings and the work procedures used to attachcouplings to shafts. They tell a lot about remaining run length.

Consultants. Whether one ultimately receives life extensionguidance from individual consultants or from billion-dollarconsulting giants with applicable experience is of no conse-quence, as long as there is the one common thread: Deter-mining where upgrades are possible. Upgrades are critical toimparting longer life to existing equipment, and they can of-ten be accomplished at relatively low cost. Assessments of re-maining life should include detailed advice on how to upgrade

weak links, which implies:• The expert authoritatively spells out recommended up-

grade components• Recommended upgrade procedures are explained• Facilities recommended to do the upgrading are defined.In short, the entity involved in advising you on equipment

life extension must understand the feasibility of component up-grades. Component upgrading is one of the keys to life exten-

sion and deliverables that should be contractually agreed upon with the upgrade provider. Be sure that the consulting company you’ve asked to give advice on equipment life extension in-cludes these deliverables.

HEINZ P. BLOCH resides in Westminster, Colorado. His

professional career commenced in 1962 and included

long-term assignments as Exxon Chemical’s regional

machinery specialist for the US. He has authored over 520

publications, among them 18 comprehensive books on

practical machinery management, failure analysis, failure

avoidance, compressors, steam turbines, pumps, oil-mist

lubrication and practical lubrication for industry. Mr. Bloch

holds BS and MS degrees in mechanical engineering.

He is an ASME Life Fellow and maintains registrationas a Professional Engineer in New Jersey and Texas.

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IntegrationStrategies

BARRY YOUNG, CONTRIBUTING [email protected]

Recent trends shape the future of DCS

Several trends have already impacted the distributed con-trol system (DCS) market and are likely to continue over thenext few years. These include both product- and technology-related trends and general industry trends.

More intelligent I/O. The DCS input/output (I/O) subsys-tem is responsible for inputting hundreds or often thousandsof different process measurements and other inputs into thesystem, and outputting control signals to a large number of

valves, actuators, motors and other plant final-control ele-ments. I/O represents one of the most significant parts of theDCS. Traditionally, I/O is a significant cost element. How-ever, DCS suppliers are working to reduce both the cost andcomplexity of their I/O systems by incorporating more intel-ligence and programmability into the devices.

Shift in I/O type. Fifteen years ago, the traditional processanalog input came from a sensor producing a 4-mA to 20-mA analog signal, and the typical analog output was a 4-mA to20-mA signal. Discrete signals involved various combinationsof voltages and currents. Each signal type had a dedicated typeof circuit board for the individual signals.

Today, in a greenfield plant, most of the I/O supplied is onsome type of bus network. Brownfield plants are also installingmore bus I/O. However, with the large installed base of tra-ditional 4-mA to 20-mA I/O, the transition is very slow. Majorexpansions or revamps in brownfield plants consider bus I/O

when the sensors and final control elements are also part of theproject. There is also a growing trend to adding more wirelessI/O and associated field devices, particularly for process andequipment monitoring applications.

Need for network consulting services. As the lines be-tween automation and IT are blurring with increasing usage of

commercial off-the-shelf (COTS) technology, the network in-frastructure of the DCS and the network architecture for plantinformation are becoming increasingly more intertwined. Endusers now often rely on the expertise of suppliers for consultingto set up these networks in a safe and secure manner.

Virtualization.DCS suppliers started incorporated server vir-tualization a few years ago. Common uses of this technology include engineering development and simulation for training.

Virtualization is not appropriate for all parts of the DCS. Some-times, the dedicated hardware will perform a given task betterthan a virtual server. A good example is the real-time processcontroller in a DCS, where speed, determinism and high reli-

ability are major design considerations for the operation andsafety of the plant. Conversely, a virtual server performing many

applications on one box can be a good choice for offline appli-cations such as control configuration, simulation and training.

Cyber security. With more open and interoperable, largely COTS-based automation systems, cyber security is becomingmore important as end users struggle with potential risks, bothinternal and external to the DCS. Most suppliers now addressthis threat with active programs, either inhouse or throughpartnerships. As part of a “defense-in-depth” cyber-security

strategy, network fire walls and strategically placed switches arerequired to help prevent the propagation of external viruses andintrusions. Internal threats from disgruntled employees or oth-er internal access points must be addressed with such things asUSB locks and software to monitor internal automation systemnetwork activity. Furthermore, network maintenance practicesthat are common in the IT world—such as automatic softwareupdates, anti-virus updates and bug fixes—must be modifiedfor the mission-critical, 24/7 industrial environments in whichDCSs typically operate.

Mobility. Just as people today find it hard to live without theirsmartphones in their daily lives, increasingly, process operatorsand production supervisors are relying on the ability to “accessdata anywhere, anytime” to do their job functions. DCS suppli-ers address this trend by supplying tablet technology for rovingoperators and smartphones for alerts and condition monitor-ing. This trend toward increasing mobility will grow in impor-tance in the future.

Cloud computing. There has been much talk in the industry about developments underway to move selected DCS applica-tions “to the cloud,” a reference to moving applications to re-mote, Internet (public) or intranet (private) servers. However,the control-automation industry is very conservative by nature,

and, presently, this trend is just talk. ARC believes that, ulti-mately, selected DCS applications will migrate to private and, insome cases, even public “clouds.” For now, end users are wary.

BARRY YOUNG has over 25 years of professional

experience in the process control and industrial

automation industry. Prior to joining ARC, he served as

a project manager for New England Controls, where he

helped design and implement automation solutions for

a variety of high-profile clients in the life sciences,

utility, pulp and paper and other industries. Prior to

New England Controls, he handled a variety of

responsibilities within the global Invensys/Foxboro

Company organization. Mr. Young has a BS degree

in management engineering from Worcester

Polytechnic Institute, and has completed MBA courses

at Bryant University. He is a member of the Project Management Institute.

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| Special Report

PROCESS CONTROL AND

INFORMATION SYSTEMSFor as long as hydrocarbon processing industry (HPI)facilities have been processing crude oil, natural gasand intermediates, there have been instruments in placeto assist plant operators in measuring, recording andcontrolling pressures, flows, levels, temperatures and otherprocess variables. Much has changed since the early daysof the HPI. With the application of digital control andcomputer-integrated manufacturing, facilities have beenable to automate control of processing units, directlyanalyze product streams and initiate action from a central

control room. Since the 1980s, technology developments infield instrumentation design, software, simulation modelsand more have provided even greater opportunities tofurther implement process monitoring and control and,ultimately, optimize plant operations. The goal for anyprocess control project is to increase profitability; tothis end, plant optimization and process automation arediscussed in this month’s Special Report.

Photo courtesy of ABB Process Automation.

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Special Report Process Control and Information SystemsA. G. KERN, Consultant, Houston, Texas

Update hydrocracking reactor controlsfor improved reliability

At present, hydrocarbon pricing pays strong dividends forhydrocracking (HC), which leverages low-cost hydrogen (H2 ),sourced from today’s abundant natural gas supply, into high-val-ue liquid fuels. Among hydroprocessing (HP) units, HC unitshave the greatest H2 uptake, with a typical liquid volume swell of

10%. This earns in the range of $100 million (MM) per year fora 30,000-barrel-per-day (bpd) HC unit based on volume swellalone, in addition to the usual value upgrade of HC conversion.

As a result, hydrocrackers—which are already one of thehydrocarbon processing industry’s most demanding processcontrol challenges—are being pushed to greater limits. HCreactors operate at elevated temperatures and pressures, mak-ing safety a constant concern. Recovering from temperatureupsets can take hours, and recovering from a complete depres-surization takes days. Reactions are exothermic, meaning thateven minor disturbances in feed, heater or quench controls canrapidly escalate to an urgent situation. For these reasons, HCcontrols have always demanded vigilant attention to designdetail, management of change, and operability. Any oversightscan result in, or fail to prevent, depressurization events. Key improvements, on the other hand, can bring large gains in re-finery profitability and reliability.

For the past two decades, hydrocracker process control strat-egy has focused on installing automatic depressurization sys-tems and multivariable predictive control (MPC). While thisequipment has brought important gains, experience shows thatit leaves many gaps in excursion control and depressure pre-

vention. This article presents an updated hydrocracker controlmodel that robustly addresses traditional hydrocracker controlchallenges, overcomes outdated hydrocracker control para-

digms, and allows hydrocrackers to operate safely, reliably andprofitably under today’s demanding conditions.

HC process and economics. FIG. 1 shows a common hydro-cracker configuration. Heated oil and excess H2 enter a verticaldownflow reactor with multiple fixed catalyst beds. The cata-lyst promotes cracking and hydrogenation of larger hydrocar-

bon molecules, such as gasoils, cycle oils and coker oils, intolighter, more valuable molecules, such as diesel, jet fuel andnaphtha. The overall reaction is exothermic, so temperatureincreases as flow passes through the bed.

Between beds, cold H2 quench gas is introduced to cool thereaction mix. In this way, the reactor is a succession of crack-

ing beds followed by quenching (FIG. 1 depicts three beds, butoften there are more). The overall objective is to achieve the

desired amount of cracking (or “conversion”), which is borneout in the downstream fractionation section product spreads.

Maximizing conversion means operating at one or moreof the quench constraints. These include a maximum quench

valve position, chosen to ensure ample reserve quench should

an exothermic excursion occur, and a maximum bed tempera-ture rise, which indicates high cracking severity and increasedrisk of a rapid onset excursion.

Recent price trends in crude oil and natural gas have shiftedHP economics. The price of natural gas has declined, while theprice of crude oil and liquid fuels has greatly increased. H2 con-sumed through a hydroprocessing complex swells the liquid

yield, effectively converting a low-cost feedstock into a high- value product.

Among HP units, HC has the greatest H2 uptake, typically around 1,700 standard cubic feet (scf) of H2 per barrel (bbl),

with a resulting liquid volume swell of 10%. Therefore, thegross profit margin from volume swell alone is in the range of $100 million (MM) per year for a 30,000-bpd HC unit. This is

based on H2 sourced from natural gas at $4/thousand scf, and valuing product fuels at $120/bbl.

Past strategies and present gaps. Over the past 20 years,hydrocracker process control strategy has focused on instal ling

Quench H2

CatalystBed 1

CatalystBed n

CatalystBed 2

Heater control

Combined eed (H2 and oil) rom heaters

Bed 1quench

Distribution

Separator

Fractionation

Recycle H2

Flare

Manualdepressure

Feed/efuentexchangers

Support

Contact anddistribution


PCSEP

HCDEPR

TCIN-2

TCIN-n

LCSEP

TCIN-1 RO

TCIN-1A

FIG. 1. Simplified HC reactor piping and instrumentation diagramwith “as-purchased” controls.

7/22/2019 gulfpub_hp_201210.pdf


Process Control and Information Systems

automatic depressurization systems and MPC. While these areimportant, experience now shows that they leave many gaps inexcursion control and depressure prevention.

Auto-depressure controls serve to vent reactor systems toflare in the event of an uncontrolled exothermic excursion,to halt the reaction and prevent vessel temperatures from ex-

ceeding metallurgical limits. Temperatures during an exother-mic excursion sometimes increase tens of degrees in as many seconds. Industry history shows that manual depressure sys-tems are often not used according to written procedures and

that personnel at all levels—managerial, supervisory and op-erational—can have difficulty balancing production goals withsafe use of manual depressure systems.1 This illustrates why auto-depressure—made possible by more reliable thermocou-ple-based temperature-measurement systems and improvedalgorithms for excursion detection and temperature-measure-ment quality handling—has become essential.

The difficulty with auto-depressure controls is that they tendto act much sooner than traditional, manually initiated systems,and depressuring is to be avoided whenever possible, except asa final layer of safety. Depressuring a reactor brings the unwel-come prospects of prolonged restart, impact on other refinery units, large economic losses, thermal and mechanical stressesto the reactor and associated equipment, environmental flar-ing violations, and potential harm to the company image in thecommunity and in the industry. The necessary message thatoften fails to accompany auto-depressure projects is the needfor better excursion control to avoid reaching auto-depressureconditions in the first place.

MPC technology has brought improvements in reactor bed temperature balancing, weighted average bed temperature(WABT) control, and coordination between reactor and frac-tionator sections (conversion control). However, MPC lacksthe speed, reliability and control features necessary to adequate-

ly respond to most hydrocracker disturbances before they resultin an excursion, or to contain an excursion before it leads to de-pressure, or to do so in a manner that minimizes overall impacton reactor temperatures and resulting lost production.

Excursion scenarios. Hydrocracker operators are alwaysaware of the many potential excursion initiators. On the otherhand, when designing controls (and even during hazard analy-sis), there is a common tendency to downplay the likelihood,severity and actual history of many excursion scenarios.1 For ahydrocracker (or for any critical process control), an effective

approach is for a multidisciplinary team to consider each sce-nario and the most appropriate control system response. Com-mon excursion scenarios include:

• Loss of oil feed. A feed pump trip normally results in astrong excursion unless quickly quenched, because theoil stops moving through the bed and instead “cracksin place,” never reaching the quench zone.

• Heater operations. Adding burners, fuel gasupsets, draft or oxygen upsets, etc., can cause feedtemperature spikes, triggering an excursion.

• Maldistribution. Bed inlet maldistribution cancause erratic quench controller behavior, especially if a single measurement point is used for control or if

inter-bed redistribution internals are not functioningproperly. Maldistribution of flow through the catalyst bed cre-ates localized low flow conditions and “hot spots” where excur-sions can take hold.

• Production changes. Although operating proceduresare designed to implement changes conservatively and safely,excursions commonly occur during changes to feed rates, feedtype or temperature (i.e., conversion).

Additional potential excursion triggers are listed in Refer-ence 1. Complex refineries with a variety of feed and producttypes can be subject to these hazards on an essentially continu-ous basis. Understanding these causes helps build better con-trols; however, the control design must also provide effectiveexcursion control, regardless of the cause.

Layers of control. FIG. 2 is a hydrocracker reactor controlmodel that addresses safety, depressure prevention, and excur-sion control, along with normal operating objectives and op-timization. The overlapping of layers indicates robust reliabil-ity. For example, excursions may be contained and controlled

by Layer 4, 3 or 2 before ever reaching Layer 1 (depressure).In addition, Layers 4 and below are implemented in the base-layer control system, thereby maximizing responsiveness, reli-ability and operability.

• Auto-depressure on high temperature is becoming estab-

lished as an industry best practice. Key design decisions include whether to implement auto-depressure in the safety instru-mented system (SIS) or the distributed control system (DCS);

whether to depressure on high temperature rate-of-change (inaddition to high absolute temperature); and how to robustly handle low-quality temperature singularities among the bedoutlet thermocouple arrays to avoid unnecessary or nuisancedepressurization events.

• Auto-quench causes the quench valves to open on highexcursion temperature to avoid reaching the depressure limit.It may also trigger preemptively on feed pump trip and initiateheater minimum fire logic. Auto-quench design is a balancingact: it should be robust, like a safety function, but without be-

ing so heavy-handed as to result in an extended recovery time;it must trigger early enough to avoid reaching depressure, but

1. Auto-depressure

2. Auto-quench

3. Excursion control

4. Bed outlet control

5. WABT and rate control

6. Conversion control

S a f e t y

E x c u r s i

o n c o n t

a i n m e n t

N o r m a l

o p e r a t i

o n

O p t i m i z

a t i o n

FIG. 2. HC reactor control model showing “layers of control.”

Auto-quench is a DCS control, but it can

be one of the most important functions

in a refinery, since it is the final layer

of depressure prevention.

7/22/2019 gulfpub_hp_201210.pdf


without triggering unnecessarily; and it should not interfere with, or be defeated by, quench controls in manual mode. Al-though auto-quench is a DCS control, conceptually it can beone of the most important functions in a refinery, since it is thefinal layer of depressure prevention.

• The excursion control layer is designed to handle excur-sions as routine control disturbances, when possible, to mini-mize their impacts. This renders most excursions as non-events,such that they go largely unnoticed, except perhaps by the DCSoperators. In the past, operators remained alert to take manualcontrol in the event of an excursion, but with excursion con-trols, operators learn to keep them in the correct mode to en-sure reliable automatic response. As one operator noted, “Theseare controllers that work for us, and not the other way around.”

The excursion control layer comprises a number of tradi-tional advanced regulatory control (ARC) techniques applied

to the bed inlet, bed outlet and heater controllers. An importantaspect is converting the Bed 1 quench valve (“TC-IN-1A” inFIG. 1) to a bed outlet temperature controller (“TC-OUT-1A”in FIG. 3) and coordinating its action with heater control. Thiscritical valve is often configured problematically (as in FIG. 1),so that it does not respond to an excursion and, when used, cancause the heater(s) to counter with increased firing.

• In retrospect, operating an exothermic reactor without bed outlet control defies common sense, although it is a com-mon practice, especially when MPC is switched off, detuned,clamped or over-constrained. Even if the excursion controlfeatures are absent, outlet control at least helps prevent many gradual process variations from reaching excursion thresholds.

It also brings increased stability to bed outlet temperatures, WABT and conversion. However, simple outlet control—sans

the excursion control features, including MPC—usually willnot contain an excursion once it begins.

• MPC-based WABT control, when implemented in thenew model (FIG. 3), would write to the bed outlet controller set-points rather than to the bed inlets, as is traditional. The bedoutlet controllers provide base-layer stability and excursioncontrol, while MPC provides traditional WABT control andconstraint management. As an alternative, WABT control can

be implemented as a custom algorithm, providing greater flex-ibility in how the constraints are managed. This also facilitates a

Find out what’s new in Washers at www.HYTORC.com/Washer

Since 1968

Regular Washers improve Torque and Tension Accuracy(ASME & TUV)

Quench H2

Auto-quench

Customor model-

based

Model-based

Conversioncontrol

WABT andrate

control

CatalystBed 1

CatalystBed n

CatalystBed 2

Heater control

Bed 1 quench

Combined eed (H2 and oil) rom heaters

Distribution

Separator

Fractionation

Recycle H2

FlareAuto/manualdepressure

Feed/efuentexchangersSupport



PCSEP

HCDEPR

TCIN-2

TCout-1A

TCout-1

TCWABT

TCAQ

ACCONV

TCout-1

TCIN-n

TCout-n

LCSEP

TCIN-1

RO

FIG. 3. HC reactor piping and instrumentation diagram

with upgraded controls.


7/22/2019 gulfpub_hp_201210.pdf



variable WABT ramp rate that can be both faster and safer dur-ing startup and recovery operations, capturing extra hours of on-target production. Since the base-layer controls handle sta-

bility, this custom WABT algorithm is similar to, and no morecomplex than, a traditional heater pass balancing control.

• Conversion control involves moving the WABT set-points based on fractionation section product spreads. MPC isa good choice for handling the long response times involved,although a rudimentary custom algorithm can also be used. A limitation is that feed quality changes are the primary distur-

bance, and they are often much “bigger than the handles,” since WABTs can only be moved gradually and within limits. Anotherkey consideration is a smart-conversion calculation and sched-uler, so that fractionator disturbances are not back-propagatedto the reactor section.

Metrics. Excursions are commonly quantified as the difference between real-time reactor bed temperatures and recent (heav-ily filtered) values. The excursion value reflects any short-termtemperature rise; i.e., the severity of an excursion. At steady-state, this value will be zero, and at operating conditions (if procedures are carefully followed and no excursions occur), it

will always be less than the prescribed maximum hourly rate of change; e.g., less than around 5°F.

Since modern hydrocracker reactors may have a dozen ormore thermocouples per bed, a common practice is to calculatethe highest temperature of each bed for monitoring and alarm-ing, for ease of operation, and to avoid alarm floods when ex-

cursions occur.FIG. 4

is an example of the long-term trend of the highest excursion temperatures for each bed of a two-stagereactor. The vertical axis shows excursion severity (for example,increments of 5°F).

Excursions below a severity of 1 reflect routine daily opera-tion. Excursions with a severity between 1 and 2 may occur dai-ly, weekly or monthly, depending on the quality of operation.Excursion controls should take effect at this level. Excursionsgreater than a severity of 2 are increasingly serious and, in many cases, warrant near-miss investigations to prevent recurrence.These investigations often lead to the types of control improve-ments described here.

FIG. 4 provides a meaningful metric of progress and of on-

going quality of operation. As controls are upgraded, the fre-quency and severity of excursions decreases. As with any safety

metric, frequent, minor excursions indicate the increased likeli-hood of a full-blown excursion and potential depressure event.

A graph like that shown in FIG. 4 is a good candidate for vis-ibility on a large control-room screen, as a means of sustainingimprovement and awareness.

Recommendations. A guiding tenet in the evolution of thesecontrols was to utilize quench, heater and other controls as ad- vantageously as possible under all circumstances, to containexcursions and avoid reaching auto-depressure conditions.This led to many creative and sensible ideas. The main chal-lenge was not in the difficulty of designing new controls re-flecting these ideas, but in overcoming entrenched paradigmsabout the old controls, even though they were outdated or notsensibly configured in many cases, such as the conflict betweenthe Bed 1 quench and heater controls, and the lack of reliable

bed outlet control.Control layers 2 through 4 were implemented with stan-

dard DCS functionality, bringing cost and engineering ad-

vantages. Another practical benefit is operability, since thesecontrols present to the DCS console operator and behave asconventional cascaded controls, requiring minimal new con-cepts and training.

MPC is often considered a comprehensive solution for thetypes of control concerns raised here; however, none of the crit-ical excursion control, depressure prevention or auto-quenchfunctions are of the type provided by MPC. For design or haz-ard and operability study (HAZOP) purposes, it is usually bet-ter to view MPC as a gradual constraint pusher, rather than asa reliable disturbance handler. This distinction is important onany process, but especially for hydrocrackers, where a robust re-sponse can make the difference between an online reactor and adepressured reactor, in a matter of minutes.

Process control could benefit by borrowing from safety sys-tem practice and convening a multidisciplinary team to review critical process upset scenarios and arrive at the most appropri-ate and advantageous automatic control response. While many processes do not have the rapid downside potential of HC reac-tors, the general principles of maximizing on-target productionand avoiding safety function thresholds under upset conditionsmake this approach a good practice for any refinery unit.

The traditional practice of operating high-pressure, high-temperature, exothermic reactors without reliable, nonlinear

bed outlet temperature control is a paradigm that industry

should proactively remedy. The auto-quench, excursion con-trol and bed outlet layers should join auto-depressure as indus-try best practice for all hydrocrackers.

LITERATURE CITED

1 EPA Chemical Accident Investigation Report, Tosco Avon Refinery, Martinez,California, November 1998.

ALLAN KERN has over 35 years of process control experience

and has authored dozens of papers on multivariable control,

inferential control, safety systems and distillation control,

with a focus on practical process control solutions and

effectiveness. He is a professional control systems and

chemical engineer, a senior member of ISA and a graduate

of the University of Wyoming. Mr. Kern is a consultant, and

he can be contacted at [email protected].

FIG. 4. Improvement in excursion control.

7/22/2019 gulfpub_hp_201210.pdf


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Special Report Process Control and Information SystemsJ.-M. BADER and G. ROLLAND, Axens,

Rueil-Malmaison, France

Use a systematized approach of good practicesin pygas hydrogenation via APC

As illustrated in FIG. 1, steam crackers produce many ba-sic building blocks for the polymer industry, along with ar-omatic-rich gasoline (pygas). When naphtha is used as thefeed for cracking furnaces, pygas yields increase significantly.TABLE 1 shows the typical pygas yield and composition fornaphtha cracking. Pygas is a large contributor to benzeneproduction capacities.

Before the pygas can be routed to downstream units (aro-matics extraction, etc.), unstable compounds such as diolefinsand styrenics must be removed. Also, olefins and sulfur must beeliminated to ensure that final products will meet their specifi-cations. This pygas treatment is achieved through hydrogena-tion steps. However, if the pygas treating is not optimized, thenother undesired processing operations—including hydrogenflaring, reactor channeling, poor use of the second beds, andother issues—have a greater possibility of occurring.

Optimizing control. Advanced process control (APC) offersa solution to systematize implementing best practices, avoidmis-operation, and generate substantial benefits. The follow-ing case study describes the operational improvements andsteps necessary when applying APC. This case study will ap-ply actual plant data to demonstrate and quantify the benefitsattainable from APC installations.

PROCESS A case study will describe the industrial results obtained

with the two-stage pygas hydrogenation process (PGH), as

shown in FIG. 2. This PGH unit includes a first-stage process(GHU-1) to improve the stability of the raw pyrolysis gaso-line by selectively hydrogenating diolefins and alkenyl com-pounds, thus making it suitable for further processing in the

second stage. The reaction is carried out mainly in the liquidphase on a specific catalyst in a fixed-bed reactor.

The selected operating conditions maximize conversion of the diolefins and alkenyl aromatics, while minimizing the for-mation of heavy products by polymerization. These operatingconditions minimize aromatics loss.

In the second stage of PGH (GHU-2), the C6–C8 heartcut is further processed to prepare a feedstock suitable for

H2 + CO

C5 – C10

200° +

C2

C3

C4

High-purity hydrogenMethanation

C2 hydrogenation

C3 hydrogenation

C4 hydrogenation

Pygas hydrogenationC5 – BTX –C9+

Fuel

Ethylene

Propylene

Butene, butadiene

Feed Steamcracker

FIG. 1. Pygas production and other products rom a steam cracker.

H2Pygas

feed

C5

C9+ C6 – C8 A

Q

Q

D

Rx2

Rx1

FIG. 2. Pygas hydrogenation low scheme.

TABLE 1. Typical naphtha cracker pygas (C5–200°C) yieldand composition

Composition, wt%

Paraf ns + naphthenes 11.8

Olefins 5.5

Diolefins 18.1

Benzene 28

Toluene 13.9

Xylenes 7.2

Styrene 3

C9+ aromatics 12.5

Total aromatics 64.6

7/22/2019 gulfpub_hp_201210.pdf



aromatics recovery, by selectively hydrogenating the olefinsand removing sulfur via hydrodesulfurization (HDS). The re-actions are conducted through a series of specific catalysts infixed-bed reactors. The operating conditions are selected toprevent aromatics losses by hydrogenation and to minimizeheavy product generated by polymerization.

HYDROGEN NETWORK

For APC of the hydrogenation processes, the hydrogennetwork plays a major role, and it needs to be studied care-fully. Both pygas-treating stages consume hydrogen. Severalconfigurations are possible to supply hydrogen to the pygasreactors, as shown in FIG. 3:

• High-purity hydrogen option• Low-purity hydrogen option• First-stage purge in the second stage.One concern that cannot be ignored is that other facility

processes are also hydrogen users, such as selective hydrogena-tion of C2 , C3 and C4 streams. In a situation of low-hydrogen

availability, these processes have priority. As a consequence,pygas can reach a situation in which the first stage is tempo-rarily operated with insufficient hydrogen, which has negativeconsequences on process performance and catalyst life. Whenexcess hydrogen is available, it is important to reduce wasteful

hydrogen flaring and to improve pygas operation by utilizingall available hydrogen. Efficient pygas operation can ensurethat the best use is made of available hydrogen.

POSSIBLE OPERATING IMPROVEMENTS

There are four key areas that have the potential to deliver op-

erational improvements. These areas are: improving first-stageproduct quality, reducing the risk of channeling, maximizingsecond-bed usage, and optimizing global hydrogen usage.

Improving first-stage product quality. The product enter-ing the second stage must be hydrogenated to the correct levelto prevent polymerization of any remaining diolefins or alkenylaromatics in the second-stage reactor, which is operated at ahigher temperature and in the vapor phase. If the hydrogena-tion process lacks suff icient hydrogen or has a low temperatureprofile, there will be a high tendency to form gums at the inletof the second-stage reactor, thus generating unacceptable pres-sure drop and performance reduction.

A good indicator of the hydrogenation of diolefins or alke-nyl aromatics is the styrene content of the first-stage reactorproduct. Normally, the styrene specification is set at 1,500ppm to efficiently protect the second-stage catalyst. In addi-tion, reasonable catalyst cycles are followed.

FIG. 4 presents a statistical distribution of the styrene con-tent at the outlet of the first-stage reactor without APC. The

C2 hydrogenation

H2 purge

Pygas feed

H2 network

High-priorityH2 consumer

To flare

C3 hydrogenation

C4 hydrogenation

To BTX extraction

1ststage

2ndstage

FIG. 3. Hydrogen network summary.

Styrene distribution, ppmwt

800 800 1 ,000 1 ,100 1 ,300 1 ,500 1 ,700 1 ,800 1 ,900 2 ,000700600500

Large giveawayOf specs

On specification

FIG. 4. Typical styrene statistical distribution in a first-stage reactoroutlet (ppmwt) from an online analyzer.

Rx1

FC

FC

Product to 2nd stage

Pygas feed

Quench

H2

Liquid load

FC = Manipulated variableLiquid load = Controlled variable

Diluent

FIG. 5. Diluent flow adjustment in first-stage reactor.

Reducing thechannelling

No APCAPC on

75 80 85 90First bed temperature of first-stage reactor, °C

Feed flow

95 100

Temperature profile in first bed o first-stage reactor

FIG. 6. Improving from bumpy to smooth temperature profilewith APC.

7/22/2019 gulfpub_hp_201210.pdf



histogram is characterized by a small number of off-specifica-tion values that could have damaged the second-stage catalyst.

Also, a large proportion of product was well below the requiredspecification. This over-quality is translated as a cost or give-away due to the unnecessarily high reactor temperature in thefirst stage that would reduce the catalyst cycle.

Reducing channeling by appropriate diluent flow. Inthe first-stage reactor, the flow entering the reactor is mainly in liquid phase, and it is constituted of fresh pygas feed, dilu-ent cooled and recycled from the first-stage reactor outlet andhydrogen makeup, as shown in FIG. 5. If the diluent flow is toolow, then the hydraulic loading of the catalytic bed may be-come too small, and thus possibly cause channeling.

If the diluent flow is too high, then the velocity in the reac-tor may be excessive. More importantly, it will lower the aver-age bed temperature, thus a higher inlet temperature will berequired to maintain performance. The higher operating tem-perature will negatively impact the stability of the catalyst.

The total flow to the first-stage reactor (fresh feed + dilu-ent), also called “liquid load,” must be adjusted to an optimaltarget value close to the design value to produce the most con-tinuous temperature profile. This condition is illustrated inFIG. 6. With an inappropriate liquid load, the irregular tempera-ture profile reveals the occurrence of channeling.

Maximizing second-bed usage by quench flow. In bothpygas reactors (first and second stage), there is usually a quenchinjection between the first and second beds, to control the reac-tor temperature profile. The quench flow is often kept too high

by panel operators to prevent temperature runaways.In the first-stage reactor, as illustrated in FIG. 7, the conse-

quences of excessive quench flow are a lower bed ΔT, whichresults in lower hydrogenation levels in the second bed. Thisleads to increased styrene content in the product. To com-pensate for this case, the first-bed temperature is frequently increased, which is detrimental to catalyst life cycles. APC ob-

jectives for the first-stage reactor include the balance of the hy-drogenation between the first and second reactor beds.

Optimizing hydrogen usage by minimizing flaring. Thisprinciple is described in FIG. 8. The hydrogen-network purge tothe flare is piloted by a hydrogen-network pressure controller.If the valve of this pressure controller is not fully closed, thenhydrogen is wasted and sent to flare. In this case, it is possibleto increase hydrogen flow to the pygas unit, until the pressure

controller valve is fully closed, thus optimizing usage of allavailable hydrogenIn reality, the hydrogen-network pressure-control strategy

implemented in the distributed control system (DCS) can bemuch more complex than presented in FIG. 8. Using in-depthknowledge of DCS capabilities, a new method was developedto minimize hydrogen loss and further increase the hydrogenmakeup for the pygas unit without affecting the network pres-sure. This approach uses pressure controller parameters (set-point, process value, valve opening, etc.) and dynamic modelsderived from step-test data. The benefits from this approachare to deliver more hydrogen to the pygas unit and thus im-prove hydrogenation performance.

APC STRATEGY

This novel approach on APC strategy was successfully ap-plied to optimize industrial pygas process operations. It incor-porated several key control methods to improve the hydroge-nation process:

1st stage reactor 2nd bedΔT

Styrene in product

Quench flow steps

FIG. 7. Effect of quench flow changes (during 14 hours) in the secondbed of first-stage reactor.

C2 hydrogenation

H2 purge

Pygas feed

H2 network

To flare

C3 hydrogenation

C4 hydrogenation

To BTX extraction

1ststage

2ndstageFC = Manipulated variable

H2 available = Infered controlled variable

PC

FC

Send all flaredH2 to pygas

H2 available

FIG. 8. Using hydrogen network information to maximize hydrogen

supply to pygas.

Feed qualityestimation

Diluent Quench Diluent Quench

Reactormodel

1st stage 2nd stage

Periodical manualcatalyst activity update

Lab data

Reactormodel

BI indexaromatics

Lab datađƫ05.!*!đƫ.đƫ!*/%05

05.!*!diolefins

.

FIG. 9. Inferential model to maximize hydrogen management whileminimizing styrene content.

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Maximize feed. Common practice is to place an intermediateproduct tank between the steam cracker and the pygas unit.The volume of this tank can usually absorb one day’s produc-tion of pygas. The inventory of this tank should be minimizedto reduce the risk of polymerization of unsaturated compo-nents present in the raw pygas, until downstream constraints

have been saturated.

Use all available hydrogen. Optimize the global hydrogenmanagement.

First-stage reactor. The first target is to do ultra-deep hy-drogenation of diolefins and alkenyl aromatics, by controllingthe styrene content, as measured by an online analyzer, in thefirst-stage product. The next step is to stabilize reactor opera-tion by controlling the reactor liquid load at an ultimate levelto avoid channeling.

Hydrogen partial pressure is maximized to promote hydro-genation by increasing the reactor pressure while maximizing

the dissolved hydrogen fraction in the liquid phase. The pro-cess is operated to ensure a minimal gas purge flow to preventconcentration of inert species in the hydrogen recycle gas.(This is applicable if the unit is equipped with a recycle-gascompressor.) The temperature profile is optimized, using re-actor inlet temperature, diluent and quench flow to preventtemperature runaway, to balance reactor ΔT between the two

beds, and to maximize catalyst cycle length.

Fractionation. APC needs to identify the right compromise between the quality of the separation and energy savings.

Second-stage reactor. The first target is to perform com-plete hydrogenation of olefins and sulfur removal by control-ling the bromine index (BI) and sulfur content of the reac-

tor effluent. The next step is to minimize hydrogenation of aromatics by avoiding unnecessarily high-temperature processconditions. Finally, stable reactor operation will be achieved by the control of reactor ΔT and hydrogen-recycle gas density.

PYGAS INFERENCE AND OPTIMIZER

The pygas inferential model proposed for APC, as shownin FIG. 9, is based on highly evolved kinetic models that enableonline styrene content and BI estimation, and, consequently,reactor optimization. Laboratory analyses of the first-stage ef-fluent are used to estimate the first-stage feed quality (styrenecontent, bromine number and density). The first-stage reac-tor model integrates the estimated feed quality and measured

reactor operating conditions, continuously inferring the first-stage product quality: styrene, diolefins and bromine number.FIG. 10 illustrates the prediction of the styrene compared withonline analyzer measurement.

The second-stage reactor model integrates estimated feedquality and measured reactor operating conditions, continu-ously inferring the second-stage product quality. FIG. 11 illus-trates the estimation of the BI in the effluent of the second-stage reactor. Using spot-detailed analyses and collection of operating conditions, APC users can generate the best tuningparameters to fit the current operation, thus allowing “real-time” control moves to improve performance.

Styrene inferred

Styrene online

analyzer

FIG. 10. Styrene estimation in first-stage effluent by first-stage

reactor model.

Quench flow

BI inferred

Inlet temperature

FIG. 11. BI estimation in second-stage effluent by second-stagereactor model.

1st stageoptimizer

MVAC multivariable controller

Pygasinference

Reactor temperature optimal targetReactor quench flow optimal target

StyreneBromine index

Temperatures Pressure Reboiler Flows

FIG. 12. APC architecture to optimize pygas hydrogenation.

FC

FC

TC

Product to 2nd stage

Pygas feed

Quench

H2

ΔT B2

TC = Manipulated variableStyrene = Controlled variable

Diluent

FC

Styrene

Rx1

FIG. 13. Simplified APC variables used for simulation example.

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Recommended APC architecture. All APC components are embedded in an APC server connected to the DCS archi-tecture, as depicted in FIG. 12. The controland optimization application consists of these modules:

• MVAC module: State space multivariable predictive controller (MVPC)• Pygas inference• First-stage optimizer.The application provides one-min-

ute cycles for MVAC (the MVPC) and60-minute cycles for the optimizer. Con-troller execution time was determined by the process dynamics.

APC PERFORMANCE

Here is a simple example of APC po-tential, illustrated by the application to a real pygas unit opti-

mization project. The control matrix components are present-ed in FIG. 13. The inputs or manipulated variables (MVs) are:

• Feed flow to be maximized when available to reduce tank inventory

• H2 flow used as long as available to prevent flaring• Reactor inlet temperature to control styrene content,

but minimized when possible to lengthen catalyst cycles• Quench flow to control styrene content.The outputs or controlled variables (CVs) are:• Styrene in product, which should stay below the maxi-

mum limit• Reactor second-bed ΔT, which should stay below the

maximum limit. When APC in turned ON, the styrene analyzer is at 1,300

ppm, below its 1,500-ppm maximum limit, and the reactorsecond-bed ΔT is at 65°C, below its 73°C maximum limit. Asfar as the operation is concerned, quench flow is too high, re-sulting in excessive cooling of the second bed. When the reac-tor inlet temperature is too high, a styrene giveaway occurs.More feed is available; the intermediate tank is not empty; andadditional hydrogen is available, but is flared.

APC actions on the process, as plotted in FIG. 14, can besummarized as making use of all available hydrogen to re-duce styrene at the first-stage reactor outlet and thus reduc-ing quench flow as far as the second-bed ΔT allows. These

conditions will also reduce styrene content. Simultaneously,the reactor inlet temperature is reduced and feed flow is maxi-mized within the constraints of the maximum styrene contentlimits. By better operation of the second bed, and using the10% additional hydrogen available, this APC system was ableto increase production by 10%, while decreasing reactor inlettemperature by 4°C.

APC with inferential modeling has been successful ly ap-plied to pygas hydrogenation units. The overall benefits are:

• On-specification product without giveaway • Ability to treat more feed : +10%• Reduction of first-stage reactor inlet temp.: –4°C• Catalyst run length maximization: +4 months/

current• Reduction of aromatics hydrogenation: –10%

• Reduction of H2 waste to flare: –10%

• Energy savings: 5%The lengthening of the catalyst run length limits downtime

for both the pygas unit and upstream units such as the steamcracker. An additional benefit observed by the operating staff

was, with the ease of setting targets and the confidence thatthe APC system would meet these targets, they were free toconcentrate on other plant activities.

BIBLIOGRAPHY

Bader, J.-M. and S. Guesneux, “Advanced process control optimization increasesMTBE plant productivity,” Hydrocarbon Processing, October 2005.

Bader, J.-M. and S. Guesneux, “Use real-time optimization for low-sulfur gasolineproduction,” Hydrocarbon Processing, February 2007.

Tona P. and J.-M. Bader. “Efficient System Identification for Model Predictive

Control with the ISIAC Software,” (ICINCO), Sétubal, Portugal, 2004.Grosdidier P. and J.-M. Bader, “Supervisory Control of an FCC unit through

Sequential Manipulation,” Instrument Society of America, 1996.

ACKNOWLEDGME NTS

The authors express their gratitude to Joël Chebassier, Orionde, for his con-tribution to this article and also to the customers for making this article possible.

This article is a revised and updated version from an earlier presentation at the American Fuels and Petrochemical Manufacturers (AFPM) Annual Meeting, March11–13, 2012, San Diego, California.

JEAN-MARC BADER is project manager at Axens’ Performance

Programs Business Unit. His background is in energy

engineering with over 23 years of experience in APC projects

(design, development, implementation and maintenance) for

refineries, petrochemicals and chemical plants (including ADU,FCC, CCR, alkylation, hydrotreating, ethylene, ammonia,

blending), with several APC tools, on various DCS. He joined

Axens in 2001, after several years with Elf and Total. His responsibilities include

proposal and project management for APC projects. He graduated with honors

from I.N.S.A. engineering school.

GILDAS ROLLAND is a deputy product line manager—

hydroprocessing and olefins for Axens. He started his career in

1998 at IFP Energies nouvelles as a process engineer in the

R&D department. In 1999, he joined the process design

department of the North American office in Princeton, New

Jersey. In 2001, he moved back to Axens’ head-office where he

served successively as start-up and tech service advisor,

specialist in olefins technologies including R&D activities related to technology

and catalyst improvement. Mr. Rolland was appointed to his current position in

2010. He is a graduate of the Ecole Centrale de Lille (E.C.Lille) and holds amaster’s degree in refining and petrochemicals from the IFP School.

FIG. 14. Eight-hour closed-loop APC simulation example.

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Special Report Process Control and Information SystemsM. J. KING, Whitehouse Consulting, Isle of Wight, UK

Why don’t we properly train control engineers?

While there are managers in the process industry that seetraining control engineers as a “no-brainer,” these are very much in the minority. They may send staff on courses cover-ing configuration of the distributed control system (DCS) andimplementation of multivariable predictive control (MPC),

but some managers seem to miss the point that engineers alsoneed to develop expertise in basic control techniques. It ap-

pears to be a case of not knowing what they don’t know—i.e.,there is a lack of appreciation of what a fully trained engineercan achieve. Without an injection of expertise, so-called “ex-perienced” staff lack the knowledge to pass on to new recruits.

Of the engineering disciplines relevant to the process indus-try, process control is probably the least well-taught at universi-ties. Often handled by lecturers with backgrounds having littleto do with chemical engineering, the courses are laden withcomplex mathematical techniques that have little relevance tothe industry. While all graduates need additional training toadvance their careers, this is particularly true for those destinedto work in the field of process control.

Process control engineers have an immediate impact on theprocess. Today’s systems permit the engineer to move fromidea to commissioning with little involvement of other staff.Most other engineers develop recommendations that are re-

viewed with others, move on to designs that are also reviewed,and work with others during commissioning. Control engi-neers are more akin to process operators in the way they work.Operators are well-trained, so why aren’t control engineers?

Questions to consider. The following 10 questions are de-signed to expose common gaps in a reader’s knowledge. If youare a control engineer, be honest in answering them:

1. Have all of the controllers been configured with the

best choice of a proportional/integral/derivative (PID) al-gorithm? For example, am I aware that most systems supportthe option to have proportional action based on the process

variable (PV), rather than on error? Do I believe that this al-gorithm is inferior because it gives a slow response to setpoint(SP) changes, or do I know that, for many controllers, apply-ing this option with the correct choice of tuning can reduce,

by a factor of three, the time that it takes the process to recoverfrom a disturbance? (See FIG. 1.)

2. Am I using trial-and-error as the main tuning method? Am I aware that this increases, by a factor of around 50, the timetaken to properly tune a controller? Do I know that, becauseof the time required, the controller is unlikely to ever be prop-

erly tuned? Am I aware that there are over 200 tuning methodspublished for PID control, and that most—if not all—of them

have some major deficiency? Does my chosen method properly compromise between a fast return to SP and the movement of the manipulated variable (MV)? (See FIG. 2.) Is this method de-signed to be used with the chosen version of the PID algorithm?

3. Do I know that applying derivative action can greatly im-prove controller performance if the process deadtime is largecompared to the lagtime? (See FIG. 3.) Am I reluctant to use it

because it makes tuning more complicated? Do I abandon itsuse if the measurement is noisy, or do I know how to solve thisproblem? Do I know how to resolve the spiking problem thatderivative action causes with regard to discontinuous signals?

4. Is maximum use made of the surge capacity in the plant?(See FIG. 4.) Are vessel levels maintained close to SP, or arethey allowed to approach alarm limits to minimize down-stream flow disturbances? Are level gauges ranged to maxi-mize vessel working volume? Do I know that nonlinear algo-rithms such as “error squared” and “gap control” can be usedto more fully exploit surge capacity?

SPPV (proportional-on-error)PV (proportional-on-PV)

FIG. 1. Response to a load change.

PV (limiting MV overshoot)PV (ignoring MV)SPMV (acceptable overshoot)MV (unacceptable overshoot)

FIG. 2. Taking account of MV overshoot.

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5. Are filters being used mainly to reduce the visual impactof noise on trended variables? Filters can significantly reducethe controllability of the process and may not be necessary inall cases. Do I know that I should instead check what impactthe noise has on the final control element (usually a control

valve)? Do I know of other readily available filtering techniques

that cause less distortion to the base signal? Am I aware of theimportance of eliminating noise at the source, particularly withlevel measurements, and how this can be achieved?

6. Am I aware of other algorithms that can outperformeven an optimally tuned PID algorithm? Do I know that thesecan be easily implemented in most DCSs?

7. Do I know that most MPC packages provide bias ratherthan ratio feedforward? In many cases, performance can besubstantially improved by implementing ratio feedforward atthe DCS level. Do I know how to properly tune the dynamiccompensation in such controllers? Do I know of the benefitthat ratio feedforward gives in automatically maintaining op-timum PID tuning in all of the unit’s controllers as the feedrate is changed?

8. Do I apply density compensation to fuel gas flow control-lers to display flowrates in standard volumetric units (e.g., Nm3/hr or standard cubic feet per minute)? Do I know that this wors-ens the disturbance caused by changes in gas heating value?

9. Are my inferential property calculations automatically updated using laboratory data? Am I aware that, in most cases,

this can cause the inferential to become less accurate?10. Have I been persuaded to locate my compressor con-trols in specialist hardware rather than in the DCS? Do I know

that, if I apply the correct tuning method, this may not be necessary?

How did you do in the test? If it has exposed evenone area where your knowledge is incomplete, thenchances are that there is an opportunity to improveprocess performance that will capture benefits far ex-ceeding the cost of effective training.

Training costs. What does it cost to train a controlengineer, and what are the economic benefits? In ad-

dition to the time spent on learning how to config-ure the DCS and how to apply the chosen MPC, a control en-gineer will need around three weeks of further training. Thistraining should cover basic control techniques, “conventional”advanced control, process-specific techniques, inferentials, etc.Such courses can cost $1,000 per day. Factoring in travel andliving expenses, the total price of training could be $20,000. A manager might view this as costly, but it is insignificant com-pared to the benefits to be achieved through additional training.

For example, a control engineer typically will be responsiblefor control applications that are capable of capturing in excessof $500,000 per year. Commissioning a project of this value justtwo weeks sooner would be enough to justify the training. If maintaining existing applications (for example, over a two-yearperiod), then a 2% increase in their utilization would generatethe same savings. Also, if the company relies on external special-ists during implementation, then reducing the involvement of atop-grade consultant by two weeks would yield similar savings.

While such benefits apply to operating companies, simi-lar benefits can be achieved by those companies offering ad-

vanced process control (APC) implementation and processengineering services. With only minor differences betweencompeting technologies, the main criterion in selecting an

APC implementation company is the expertise of the engi-neers it offers. Winning even one more contract by demon-

strating a higher level of expertise more than justifies the costof developing that expertise.Similarly, plant owners are increasingly expecting engineer-

ing contractors to be more aware of the importance of good basic control design. Too many processes with inherent con-trol problems exist, along with missed opportunities that couldhave been avoided at negligible cost, if considered at the pro-cess design phase.

Which course should an engineer choose? More thanany other engineering subject, process control training requirespractical, “hands-on” exercises. Most engineering disciplines

work with steady state. It is relatively easy to demonstrate

steady-state behavior in a computer slide presentation. How-ever, it is not so easy to show parameters changing over time.

SPPV (PID)PV (PI)

FIG. 3. Use of derivative action.

Averaging controlTight control

Vessel level

Downstream flow

FIG. 4. Use of surge capacity.

Winning even one more contract

by demonstrating a higher level

of expertise more than justifies the cost

of developing that expertise.

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49

Student-friendly, dynamic simulations take far more time to build; it can take 50 hours or more to develop the material cov-ered in one hour on the course. The ratio for the preparationof more conventional teaching material is likely less than 10:1.More effective courses are necessarily more costly. This is par-ticularly true if they are presented by the more experienced—

and, therefore, usually more highly paid—engineer. The valueof a course should be assessed on what impact the participantcan have on process profitability upon returning to work. He orshe should return with several ideas that can be put into prac-tice immediately.

Presenting the course on a manufacturing site provides theopportunity for practical exercises to be carried out on real con-trollers. The resulting improvements have a noticeable impacton process performance, and they greatly increase the confi-dence of the engineer to implement other ideas.

Who should present the course? It might be easier to an-swer this question by identifying potentially poor choices. The

DCS vendor is best placed to instruct staff in the use of the sys-tem. However, vendors are generally more effective at explain-ing the “how” than the “why.” For example, they can describethe multiple versions of the PID algorithm available in theirsystems, but they are generally less adept at explaining wheneach algorithm should be used.

Similarly, the MPC suppliers will be able to describe how toeffectively design, implement and monitor their technology, butthey will not go into detail about the basic controls that should be in place before step-testing is undertaken. While MPC sup-pliers are concerned that such controllers operate well, they generally place less demanding criteria on their performance.

With a few notable exceptions, most academic institutionstreat process control as a highly theoretical subject. Theircourses tend to be cheaper because the tutor’s time and the fa-cilities have already been paid for; however, their usefulness isoften questionable.

Should the course be held in-company? There is thetemptation, particularly if only one or two engineers needtraining, to send them on an open-access course. It costs thesupplier more to run these types of courses than it does to runin-company courses since open-access courses must be mar-keted to a wide client base, there is a greater administrativeload, and the course facilities must be rented.

For the customer, an open-access course may be the lesscostly option, even with the inclusion of travel and living ex-penses. Also, engineers may have the opportunity to develop valuable contacts in other organizations. However, the follow-ing points should be considered:

• An in-company course opens up the opportunity for oth-ers to attend; the most successful APC projects are those in which the entire staff is involved.

• Plant supervisors, process engineers and productionplanners normally do not attend open-access process con-trol courses; however, they will usually sit in on at least partof an in-company course. An in-company course provides a valuable opportunity for these personnel to develop an aware-

ness of technology and the role they can play in its successfulimplementation.

• An in-company course can be customized to closely match the company’s needs.

• Some material included in an open-access course may not be relevant; it may assume less previous knowledge, and itstiming may be inconvenient.

When should training take place? Training budgets, likemany expenses that are perceived as optional, are often the firstto be cut when the economic climate is poor. However, this isprecisely the time when control engineering expertise should be developed. The likelihood is that no major APC projects will be approved, and so releasing engineers for training does notdisrupt their schedules.

Furthermore, engineers will have time to identify and ex-ploit the many zero-cost improvements revealed by the training. Also, when major investments are again considered, the basicprocess control layer will already be ready to receive APC—therefore, substantially shortening its commissioning.

MYKE KING is the author of Process Control: A Practical Approach,

as well as the director of Whitehouse Consulting. Previously, he

was a founding member of KBC Process Automation. Prior to

that, Mr. King was employed by Exxon. He is responsible for

consultant services, assisting clients with improvements to basic

controls, and with the development and execution of advanced

control projects. Mr. King has 35 years of experience in such

projects, having worked with many of the world’s leading oil and petrochemical

companies. He holds an MS degree in chemical engineering from Cambridge

University, and he is a Fellow of the Institution of Chemical Engineers (IChemE).

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Special Report Process Control and Information SystemsA. J. SZLADOW, REDUCT & Lobbe Technologies Inc.,

Richmond, British Columbia, Canada

Consider automated fault detection systemsto improve facility reliability

Automated fault detection and diagnosis systems (AFDDSs)are well established in many consumer and industrial sectors.1 The conventional limit-value based (high/low alarms) faultdetection and diagnosis systems have the advantage of simplic-

ity and reliability. Yet, they also have a major weakness. Thesesystems can only react to the deterioration of system condi-tions, and they do not provide sufficient time and informationto detect and diagnose anomalous conditions proactively. TABLE

1 summarizes the relative advantages of AFDDS vs. standardFDDS control. This article addresses how to implement an

AFDDS in a refinery, and discusses the advantages and key is-sues with AFDDS.

AFDDS APPLICATIONSThere are numerous publications on fault detection and di-

agnosis in electrical systems, including application of statisticaland soft computing methods. However, very little of the knowl-edge and experience gained from AFDDS application from oth-er industrial sectors has been applied to the refining industry. A literature review regarding methods applied in AFDDS in heavy industry lists 367 references.1 None of the 367 listed referencesrefers to applications found in petroleum refining.

In 1995 and 1997, similar literature reviews identified over250 applications of intelligent systems including, AFDDS inheavy-industry operations.2 Again, the majority of the applica-tions addressed process control and optimization, scheduling,and design for productivity and product quality. Less than 10%of the applications described fault detection and diagnosis sys-tems, and most cases were not automated; they primarily pro-

vided decision support to process operators and engineers.The number of AFDDSs applied appears to be related to theautomation level of the site plant and the risks associated withunsafe operating conditions. The aerospace sector has a very high level of AFDDS applications due to the risk associated

with this sector and corresponding levels of regulation. Giventhe listed considerations and that very few AFDDSs have beenimplemented in oil refineries, we will discuss AFDDS applica-tion in petroleum refining and also review systems implement-ed by industry to manage process and equipment failures.

Examples. There are very few published references to the ben-efits of AFDDS within the petroleum sector, as summarized in

TABLE 2. A report by Berra indicates that one client gained sav-ings from the reduction of unplanned shutdowns on the order

of $7.5 million with the application of predictive diagnosis incritical refinery process units.3

An EPRI report examined present adoption of control tech-nologies in California refineries and the move to use of distrib-

uted control systems (DCSs), multivariable, neural networksand future self-learning tools as shown in TABLE 3.

4 Such pro-gression of technological changes has a large potential benefit.But, this progression will require investment.

Following the methodology outlined in the EPRI report,Table 4 shows the avoided maintenance cost for refineries “be-fore and after” implementation of advanced control technolo-gies. We assign any reduction in maintenance costs to AFDDS.TABLE 4 depicts three levels of technology implementation:

1. Present level with advanced technologies2. Application of marketable (present available cost-effec-

tive) technologies3. Application of “technical potential” (future cost-effec-

tive) advanced technologies. A large difference (double) between marketable and techni-

cal potential technologies indicates possible gains in technol-ogy capacity through research.

Cost reduction. The maintenance cost was estimated at 7% of the total operating cost (Salomon 2006), which yields a benefitof over $1.3 million/yr from increased penetration of availabletechnologies and a further $1.7 million/yr from implementingfuture (hybrid and self-learning) technologies (see TABLE 4).The annual total reduced maintenance cost is estimated at over$3 million for an average refinery.

TABLE 1. Standard controls vs. AFDDS

Issue Standard control AFDDS

Alarm detection Reactive Proactive/Prognosis

Alarm management Non-deductive Deductive notification

Personnel guidance Little Significant

Inputs Largely from sensors Sensors and expert

knowledge

Corrective action Operator initiated

Automatic

Automatic

Used by Operating personnel Operating, maintenance,

engineering and safetypersonnel

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The lost production due to unscheduled shutdowns is typi-cally reported to be between 10% to 20% of operating costs.5 As-suming a potential 50% reduction in unscheduled shutdowns,etc., from installing an AFDDS, the estimated annual benefits

would exceed $3 million for an average refinery. However, toachieve this level of benefits, an AFDDS would have to be ap-plied on half of the following unit operations and processes:

1. Unit operations: Distillation, absorption columns, fur-naces, heat exchangers and compressors.

2. Unit processes: Fluid catalytic cracking (FCC), catalyticreformer, hydrocracking, delayed coking, hydrotreating and al-

kylation. About six AFDDS models would be required to gainthe benefits listed.

AFDDS PERFORMANCE

Heavy industry has used advanced process control (APC) sys-tems for optimization projects and has given much less attentionto AFDDSs. However, depending on the level of automation,

benefits from managing abnormal process and equipment condi-tions can increase reliability; the benefits often exceed the gainsfound through process optimization. For example, for a large con-tinuous operation, such as a refinery, process optimization cantypically yield a 3% improvement in productivity.6 In contrast, a

well-implemented AFDDS may yield up to a 5% improvement in

profitability. This is because management for reliability improve-ment goes beyond fault avoidance by providing the ability to:

1. Handle large disturbances and control variables at theiroptimal values

2. Ensure and upgrade dynamic process models, includingfactors omitted in initial implementation

3. Explain the behavior of controllers and, when needed,correct controllers to meet planned targets

4. Provide advice on alarm management, including early detection of problems before more serious problems develop.

As summarized in TABLE 5, it is possible to classify fault de-tection and diagnosis methods into quantitative using models

based on first principles, qualitative using models describinglumped system responses, or process history methods matchingfault patterns derived from historical data.7–9 The methods aresimilar and, yet, different from each other. They can identify therelative strengths and weaknesses from methods when buildingdiagnostic methods for fault detection and diagnosis (anomaly detection, disturbance detection and controller diagnostics)and supervisory control (controller tuning, control reconfigu-ration and online optimization). AFDDS not only address typi-cal maintenance functions such as better root-cause analysis oroptimized inspection frequencies, but, in 7 out of 10 cases, they also address processing issues.

Safety and reliability. Improving operational safety andmeeting regulatory requirements are critical to industry opera-tions and businesses. For example, AFDDSs have been appliedfor safety and regulator reasons in the automotive and aero-space sectors. This article does not discuss using AFDDSs toenhance safety and meet regulatory requirements in refineries.It is assumed that, where needed, the refining industry wouldimplement such systems as required.

Higher reliability due to AFDDS results in a more energy efficient and profitable facility. However, AFDDS-driven en-

ergy savings are often indirect through less production waste,reduced plant outages, less plant startups and/or shutdowns,and more optimal equipment/process performance through

better control systems management, etc. All lead to reduced netenergy consumption per product unit made, or higher overallplant energy efficiency.

RELIABILITY FOCUS

A simple focus on benefits/cost analysis does not reflect thetrue opportunities created by AFDDS technology. For such ananalysis, it may not include technologies that can be adoptedeasily and will later lead to significant learning and a significantcost reduction. Therefore, broader adoption criteria, such as

those listed in TABLE 6 can provide better guidance as to the best AFDDS projects and development directions to support.

TABLE 2. Summary of methods used and process units

studied

Reference ES MPC NN PCA FL SI Process

Wang11 v Distillation

column

Vedan12 v FCC

Huang13 v Coker

Yang14 v v FCC

Yamamoto15 v v FCC

Pranatasta v FCC

Patan v CC

Pranatyasto16 v v FCC

Gouku17 v Refinery

Du18 v FCC

Wilson19 v Utility

ES—Expert systems

MPC—Model predictive controlNN—Neural networks

PCA—Partial component analysis

FL—Fuzzy logicSI—Semantic interace

TABLE 3. Present state of adoption of control technology

in California refineries

Present control technology

Sub-section

of the refinery, % Whole refinery, %

Move to DCS 90 90

Move to multivariable 40 0

Move to neural network 5 0

Future sel-learning control 0 0

Source: EPRI, 20044

TABLE 4. Avoided maintenance costs of Canadian refineries

depending on the level of automation

Level of automation

Avoided cost,

$ million

Current level with the use o advanced control technologies 0

Application o “marketable” (cost-efective today)

advanced control (AFDDS) technologies

> 1.3

Application o “technical potential” (cost-efective

in the uture) advanced control (AFDDS) technologies

> 1.7

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However, in each technology stage, there are niches or spe-cialized markets that often experience adopting new technology much sooner. Some general criteria for applications of AFDDSsin oil refineries sector should be sought, explored and emphasizedto commercialize AFDDSs at a faster rate in areas such as FCC.

Implementing an AFDDS requires a high investment inknowledge of refining operations, plant controls and automa-tion, information technologies and software, advanced technol-ogies for data analytics and visualization, plant-wide informationsystems, etc. The market size of the petroleum refining industry,therefore, is critical for the private sector to justify investment of the large amount of resources and manpower required.

A more detailed discussion of the barriers to the introduction

of advanced control technologies in the refinery sector and otherheavy industry sectors can be found in the literature.10 The prog-ress in AFDDS is not likely to come from a large breakthroughin science and technology, but from incremental improvementin the cost of AFDDS and the gradual acceptance by industry.

TABLE 6 shows the estimated potential benefits and costs foran AFDDS, and a few observations are evident:

1. Because of the large difference between an average AFDDS cost (about $200,000) and the cost of improving plantdigital infrastructure ($500,000 to $1.5 million), it is the plant’sexisting infrastructure (or required improvement in infrastruc-ture) that drives the benefit/cost ratio for implementating an

AFDDS at any plant/refinery.

2. Assume that in all AFDDS cases, some infrastructure willhave to be updated. In spite of that, in all cases, benefit/cost ra-

tios of > 0.4 (with approximately 1 most likely) and paybacks of less than two years (about one year most likely) were projected.

In the final analysis of AFDDS adoption, one has to ask: What if the oil refining industry or a large industrial segmentdoes not adopt AFDDS technologies? It is difficult to predictthe future of a specific industry, but strong conclusions can bemade based on what is known about the role of technology inindustry growth:

1. Technical progress is the most important factor in eco-nomic growth, and, typically, it accounts for more than half of growth in developed countries.

2. Industries that use advanced technology are more pro-ductive and profitable and have higher wages.

3. Industries that use advanced technologies have higher job growth.

4. New technologies revitalize old industries, e.g., steel, au-tomobile, textile, etc.

TABLE 5. Summary of fault detection and diagnosis methods

Quantitative methods Qualitative methods History methods

Given required measurements can distinguish

known rom unknown aults

Can provide explanation or ault propagation Fault rules can be used where undamental

principles are lacking

Can detect aults or systems with process

and measurement noise

Can generate and recognize ull set o aults Have been demonstrated to perorm well in

terms o robustness to noise and resolutionso parameters

Efectiveness is determined by sensor data

and system knowledge

May have poor resolution due to ambiguity o

qualitative reasoning

Easy (time and cost) to implement

Approximation o disturbances can create

modeling errors

Resolution problems can be addressed with

quantitative inormation

Poor ault generalization rom historical

data only

Complex systems modeling may generate

spurious solutions because o computational

complexity

May have di culty with multiple aults

depending on algorithm used

Limited by a finite set o data

TABLE 6. Summary of potential AFDDS benefits and costs,

millions of dollarsCost element Petroleum

Plants Average benefit Average cost1

Reduction in maintenance cost 1.4 1.1–2.1

Reduction in cost o outages 3.11.1–2.1

Total reduction and cost 4.52

Benefit/cost ratio 2.1–4 (1.5–2.8)3

1 Based on six AFDDSs models per plant2 Inline with $4 to $6 million reported by Stout21 and Kant20

3 Based on reduction in cost o outages only

TABLE 7. Examples of industry-wide AFDDS adoption criteria

Overall Detail Comments

Must represent

a orward step

Potential or learning by

doing and/or research

Cross-cutting potential

Customization

requirements

Doesn’t have to

be new AFDDS

technology

Have clear adoption

issue

AFDDS barriers

Host plant expertise

Lack o support/

sponsorship

Securing technical

expertise

Business ownership

Innovative financing

options

Clear and doable

Technology is easy—

People are hard

Supports areas

o major interest

Relevance or impact

on oil refineries sector

Proponent expertise

A niche application

Identification o

applications relevant

to the sector’s

strategic investments

will accelerate AFDDS

adoption and increase

capacity

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Also, industry-wide AFDDS adoption criteria can be for-mulated, as shown in Table 4. Failure to implement AFDDS orslow progress to adopt is likely to result in a loss of opportuni-ties as measured by productivity within the petroleum refiningindustry.

LITERATURE CITED

1 Chiang, L. H., E. L. Russel, and R . D. Braatz, Fault detection and diagnosis in indus-trial systems, Springer, 2001.

2 REDUCT and Lobbe, Technologies, “Application of Intelligent Systems toincrease productivity, quality and energy efficiency in heavy industry,” and“Advances in the application of Intelligent Systems in heavy industry,” CANMETTechnology 1995 and 1997.

3 Berra, J., “The digital refinery: A look at the future of automation,” NPRA Computer Conference, 2002.

4 EPRI Report 1007415, Using advanced control and power technologies to improve thereliability and energy efficiency of petroleum refining and petrochemical manufacturing in California, 2004.

5 White, D., “The 21st century refinery: Impact of modeling and predictive analyt-ics,” NPRA Technical Forum on Plant Automation, 2007.

6 Gosh, A. and D. Wall, “Abnormal conditions management–The missing link between sustained performance and costly disruptions,” ARC Advisory Group,

March 2001.7 Venkatasubramanian, V., R. Rengaswamy, S. N. Kavuri and K. Yin, “A review of process fault detection and diagnosis, Part III: Process history based method,”Computers & Chemical Engineering, 2003.

8 Venkatasubramanian, V., R. Rengaswamy and S. N. Kavuri, “A review of pro-cess fault detection and diagnosis, Part I: Quantitative model-based methods,”Computers & Chemical Engineering, 2003.

9 Venkatasubramanian, V., R. Rengaswamy and S. N. Kavuri, “A review of processfault detection and diagnosis, Part II: Quantitative models and search strategies,”Computers & Chemical Engineering, 2003.

10 Szladow, A., “Developing intelligent systems for heavy industry: The adoption of

intelligent technologies,” PCAI, Vol. 17.6, 2005.11 Wang, X. Z., et al., “Learning dynamic fault models based on a fuzzy set covering

method,” Computers & Chemical Engineering, Vol. 21, No. 6, 1997.12 Vedam, H. and V. Venkatasubramanian, “PCA-SDG based process monitoring

and fault diagnosis,” Control Engineering Practice , Vol. 7, No. 7, 1999.13 Huang, B., et al., “Fault diagnosis of an industrial CGO coker model predictive

control system,” IEEE Canadian Conference, 1999.14 Yang, S. H., B. H. Chen and X. Z. Wang, Engineering applications of Artificial

Intelligence, Vol. 13, No. 3, 2000.15 Yamamoto, J., et al., “Application of a cooperative control system to residue fluidcatalytic cracking plant using a knowledge based system and model predictivemultivariable control,” IECON 2000.

16 Pranatyastos, T. and S. J. Qin, “Sensor validation and process fault diagnosis forFCC units under MPC feedback,” Control Engineering Practice, Vol. 9, No. 8, 2001.

17 Gofuku, A., and Y. Tanaka, “Display of diagnostic information from multiple view-points in anomalous situation of complex plants, systems, man and cybernetics,”IEEE International Conference, 1999.

18 Du, D., et al., “Expert System for diagnosis and performance of centrifugalpumps,” 1996.

19 Wilson, D., A. Jumenez and J. Souza, “An on-line advisory system for optimizingrefinery utilities systems,” NPRA Technical Forum on Plant Automation, 2006.

20 Kant, R., and K. Pihlaja, “Abnormal situation prevention (ASP) in complex sys-tem,” NPRA Plant Automation Conference, 2006.

21 Stout, J., “Reliability and operations management applications in olefins plants,”

AIChE Spring National Meeting, Houston, April 2001.

ADAM J. SZLADOW is president of REDUCT & Lobbe Technologies. He has over 30

years of experience in the development and application of advanced technologies

in energy and heavy industry. He held management and research positions in utility

industry, energy development companies and government research laboratories.

Dr. Szladow was chairman of the Business Committee of the National Advisory

Council to CANMET, Natural Resources Canada; and a member of the Minister’s

National Advisory Committee, Natural Resources Canada. He holds a PhD in

materials sciences and chemical engineering from Pennsylvania State University,

and has authored over 70 scientific publications including patents.

Dew Point • Humidity • Oxygen

Michell Instruments, Inc319 Newburyport Turnpike, Suite 207, Rowley, MA 01969

T: 978 484 [email protected]

measure moisture contenton-line in hydrocarbon

gases and liquids for

improved process control

Michell Hygrometers


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Special Report Process Control and Information SystemsV. YADAV, P. DUBE, H. SHAH and S. DEBNATH,

Indian Oil Corp., Ltd., Mathura, Uttar Pradesh, India

Optimize desulfurization of gasolinevia advanced process control techniques

At Indian Oil Corp.’s (IOC’s) Mathura refinery, a selectivedesulfurization unit was commissioned to reduce the sulfurcontent of fluidized catalytic cracked (FCC) gasoline—a blend-ing component for finished motor spirit (MS). The objective of

this new unit was lowering the sulfur content of FCC gasolinefrom 500 ppmw to 100 ppmw, thus meeting Euro IV productspecifications for the refinery-gasoline blending pool. However,along with desulfurization, some undesirable olefin saturationreactions occurred, resulting in octane losses for the productgasoline. As per design, the octane loss in the desulfurizationreactors is 1.3 units. With Euro IV specifications in place, theoctane loss negatively impacted the refinery’s economics.

This refiner applied an advanced process control (APC)solution to minimize octane loss. The objective of the desul-furization unit’s APC program is to maximize sulfur content inthe gasoline while still complying with Euro IV specificationsand other process operating constraints. The control philoso-phy depended on sulfur estimations of the stabilizer-bottomproduct. An inferential property was developed for online es-timation of the sulfur content, and it was used as a controlled

variable in the multivariable predictive controller (MVPC).This case history describes the development of the inferential

models used in open-loop and closed-loop applications, labora-tory and analyzer update mechanisms, and APC model genera-tion. With APC, it was possible to increase the sulfur contentin product gasoline by 10 ppm–12 ppm, along with an averageoctane gain of 0.11 units; all improved therefinery’s bottom line.

FCC GASOLINEDESULFURIZATION PROCESSIOC’s Mathura refinery implemented

a new gasoline desulfurization process. Itis a two-step selective hydrotreating meth-od. This processing unit consists of threemajor operations:

• Selective hydrogenation unit (SHU)• FCC-gasoline splitter (FCCGS) unit• Hydrodesulfurization (HDS) unit.In the first step, FCC gasoline is treat-

ed in the SHU, which selectively convertsdi-olefins into olefins and light mercap-

tans into heavier sulfur-containing com-pounds. In the second step, the SHU

reactor effluent is separated into light-cut naphtha (LCN),heart-cut naphtha and heavy-cut naphtha (HCN) in the FC-CGS unit. In the third step, the heavy fraction from the splitter

bottom, containing high-sulfur content material, is processed

in the HDS unit. This processing step converts heavy sulfurcompounds into hydrogen sulfide (H2S). In addition, signifi-cant saturation of olefins occurs along with the HDS reactions.Saturating olefins reduces the final research octane number(RON) and is an undesirable condition.

ADVANCED APC OBJECTIVES AND DESIGNIn the Mathura refinery application, the control objectives

are achieved by utilizing MVPC in conjunction with support-ing predictions provided by an inferential property predictionpackage (IPPP). Supporting calculations are required to sup-plement existing process measurements. MVPC applicationsincorporate process models that permit forward-feed distur-

bance rejection and intermediate variables feedback, as well asconstraint control. In configuring the controller, there is onemain controller. The objectives for the main controller are:

• Maximizing stabilizer-bottom product sulfur level withinpermissible limits, so that the upper limit of the total rundownsulfur for the desulfurization unit is maintained per Euro IV gasoline blending. Minimizing RON loss is also achieved.

• Minimizing steam consumption by the stabilizer section• Maintaining safe unit operations.

306-E-01A306FIC0104

306-P-01A/B

306-E-01B 306TIC0270

306-E-02

307-R-01

306FIC0202

306FIC0101

306FI0105

To FCCGSU gas feed

FCCU debutanizer flow

306LIC103

306TI0263

306-V-04

306-V-05

To FCCGSU liquid feed

Flow of SHUgasoline recycle

306FIC0203

Steam

Manipulated variablesControlled variablesDisturbance variables

Controller: MainCON

Sub-Controller: SHUCON

306-V-01

FIG. 1. Block diagram of the sub-controller for the selective hydrogenation unit.

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To achieve these objectives, a main controller (MAIN-CON) and two sub-controllers are used:

• Selective hydrogenation unit—SHUCON

• Hydrodesulfurization unit—HDSCON.Note: The stabilizer section of the HDS unit is considered partof HDSCON.

Sub-controller objectives. Before the APC installation,the SHU was operated to maintain stable flow to the reactor.Flow from the FCCU debutanizer (hot feed—70% of total)

was routed to a feed-surge drum. A recycle stream (HDS stabilizer bottom stream) from a nitrogen-blanketed storage (cold

feed—30% of total) was also sent to the feed-surge drum. Unitoperators manually controlled the level of the SHU feed-surgedrum by adjusting the recycle stream.

To maintain the SHU reactor inlet temperature, feed fromthe surge drum is heated by the SHU feed-effluent exchangeron the tube side by exchanging heat from the SHU effluent. Theresulting mixture is heated in the SHU preheater using steam.

After the APC installation, the control objective was tokeep steady flow to the SHU feed and maintain the surge-drumlevel by adjusting the FCCU debutanizer flow as a disturbance

variable (DV) and adjusting the recycle stream. The controlobjective is to maintain a stable SHU RIT, by manipulating theeffluent exchanger bypass flow and steam flow to the SHU pre-heater under allowable limits. The process equipment to bemanaged via the APC included:

• SHU feed-surge drum (306-V-01)• SHU feed-effluent exchanger (306-E-01A/B)• SHU preheater (306-E-02).TABLE 1 summarizes the sub-controller design for the selec-

tive hydrogenation unit. The SHUCON sub-controller was de-signed to manage steady flow to the SHU reactor while consid-

ering the debutanizer flow (hot feed) as a DV. The SHU feed/effluent exchanger bypass flow, along with steam to the SHUpreheater, is used to control the SHU reactor-inlet temperature.FIG. 1 shows the same sub-controller (SHUCON) for the SHU.

HDS unit sub-controller. Before the APC implementation,

the HDS unit was operated by controlling the sever-ity conditions of the reactors. The unit operator con-trolled HDS reaction (first-bed inlet temperature andsecond-bed inlet temperature) based on daily sulfurlevels in the stabilizer bottom product and rundownproduct. Sulfur levels were determined by analyzersand lab testing. The fuel gas was cascaded with first-

bed inlet temperature, and the quench flow was cas-caded with second-bed inlet temperature. To maintain stablereflux flow to the stabilizer, unit operators adjusted the stabi-lizer reboiler temperature and reflux pressure by continuousmonitoring of the light-end flow to the column.

Post-APC operations. The HDS reactor is set by the APC based on sulfur levels of the stabilizer bottoms. The IPPP esti-mation is done on a 15-second basis. Also, the APC will maxi-mize the sulfur level within given operator limits, thereby by adjusting the reactor severity. The stabilizer-bottom reboilertemperature is controlled by APC and facilities minimizing thesteam consumption by the reboiler. However, the reflux flow tothe stabilizer is also controlled by APC, along with stabilizer-

bottom re-boiler temperature. The process equipment man-aged via APC includes:

• HDS reactor (307-R-01)• HDS heater (307-F-01)• HDS feed-effluent exchanger (307-E-01 A/B/C/D)• Stabilizer section (307-C-02).TABLE 2 summarizes the sub-controller design for the HDS

unit. FIG. 2 shows the same sub-controller (HDSCON) for theHDS unit.

Models.As shown in FIG. 3, the simple first-order process models were not providing tight control on the HDS reactor-inlet tem-peratures. In response, a ramp transfer function block was added

into the model, along with the first-ordertransfer function block. The exothermicreaction in the reactor behaves in a “ramp”manner (unbounded runaway even in the

case of a bounded input disturbance).Due to “ramp” behavior of the process, fastaction is required in manipulated variables(MVs), such as fuel-gas flow and quenchflow, to quickly control the exotherm (by controlling the first-bed and second-bedinlet temperatures) before they rise toohigh. The inherent instability of the reac-tor was countered via a ramp block, plusthe normal first-order block, to relate theMVs and DVs with the inlet temperatures.For a step change in DVs, this combina-tion predicts an unbounded response in

the inlet temperatures—thus, moving theMVs quickly to reject the disturbance.

307TI0607.PV

307TI0630.PV

STABBTM_SULFURPV(RQE)

307-F-01 307-C-02

307FIC1003.PV

307TI0642.PV

307TIC0635.PV

307FIC0605.SP306FIC0502.PV

307-E-04

307-V-04

307-E-05

307-E-06

307TI1014.PV

307AI1001.PV

307-V-06307PIC1003.SP307FIC0684.SP

To rundown

Steam

307-E-01

307-E-01

307-E-01

307-R-01

20TI0804.PV 307FI0606.PV

Manipulated variablesControlled variablesDisturbance variables

Controller: MainCON

Sub-Controller: HDSCON

FIG. 2. Block diagram of the sub-controller for the hydrodesulfurization unit.

The objective of the desulfurization unit’s

APC program is to maximize sulfur content

in the gasoline while still complying with Euro IV.

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SUPPORTING CALCULATIONS

IPPP DEVELOPMENT

To calculate the sulfur content of the FCC feed inlet, severalpredicted values were considered. By using the flowrate and sul-fur quantity of all streams listed in TABLE 3, the total sulfur valuecan be calculated at the FCCU feed inlet. The calculation used to

estimate the sulfur content is:=(79FC803.PV ϫ S1ϫ density) + (79FC802.PV ϫ

S2ϫ density) + (79FC801.PV ϫ S3ϫ density) +(7FC6701.PV ϫ S4ϫ density) + (12FIC100.PV ϫS6 (if crude_select.op=1)ϫ density)

or (MRA.12FIC100.PV ϫ S7 (if crude_select.op = 2)ϫ density)

or (MRA.12FIC100.PV ϫ S8 (if crude_select.op = 3)ϫ density) + ((2FC0708.PV ϫ S5)/1000) /(79FC803.PV + 79FC802.PV + 79FC801.PV +7FC6701.PV + 12FIC100.PV + 2FC0708.PV)

where S1–S8 are sulfur values that are entered by the operator.

Sulfur content of FCC gasoline splitter. Feed to FCCGSUis compensated by two streams—hot feed from the debutaniz-er (306FI0105.PV) and cold feed from recycle (306FIC0101.PV). Calculations to estimate sulfur at FCCGSU feed are:

= ((DSU_SULFUR.PV ϫ 306FI0105) + (STABBTM_ SULFUR ϫ 306FIC0101.PV-5.5*)) / {(306FI0105)+ (306FIC0101-5.5*)}

where DSU_SULFUR.PV and STABBTM_SULFUR are theIPPP sulfur estimations.

*5.5 is the flow correction since the control valve has a zeroerror.

IPPP applications. Several IPPP models were developed forthe FCC gasoline desulfurization unit and include:

• FCCDSU hot feed sulfur estimation• HDS feed sulfur estimation• Stabilizer bottom sulfur estimation.

FCCDSU feed sulfur. This model used several inputs:

Tag name Tag description

FCCUFD_SULFUR.PV Sulfur at FCCU (calculation)19TRC153.PV FCCU main fractionator

top temperature

20TI99.PV FCCU debutanizer bottomtemperature.To estimate the sulfur content of DSU feed, the following

linear equation is used:

P = Ax1 + Bx2 + Cx3 + Bias

where: P = DSU_SULFUR.PV (FCCDSU feed sulfur in hot feed)

A = Coefficient 0.041417x1

= FCCUFD_SULFUR.PV B = Coefficient 1.6497x2 = 19TRC153.PV C = Coefficient 5.736500

x3 = 20TI99.PV Bias = –1067.4

FIG. 3. First-order process model response to reactor inlet temperaturecontrol. FIG. 4. Quality and process improvement achieved through APC IPPP.

TABLE 1. APC variables for the sub-controller for the selective

hydrogenation unit—SHUCON

Description Interface point

Manipulated variables:

Flow o SHU gasoline recycle 306FIC0101.SP

SHU eed/ef uent excahnger bypass 306FIC0202.SP

Steam flow to SHU pre heater 306FIC0203.SP

Disturbance variables:

FCCU debutanizer flow 306FI0105.PV

Flow to SHU rom surge drum 306FIC0104.PV

Controlled variables:

Feed surge drum (306-V-01) level 306LIC0103.PV

SHU reactor (306-R-01 B) inlet

temperature

306TIC0270.PV

SHU pre-heater inlet temperature 306TI0263.PV

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58

HDS feed sulfur. This model used several inputs:

Process inputs usedTag name Tag descriptionGSUFD_SULFUR.PV Feed to FCCGSU (calculation)20PI0802.PV FCCGSU top pressure20FC0306.PV FCCGSU light cut draw flow

20FC0404.PV FCCGSU heart cut draw flow

The following linear equation is used:

P = Ax1

+ Bx2

+ Cx3

+ Dx4

+ Bias

where: P = HDSFD_SULFUR.PV A = Coefficient 1.097890x

1= GSUFD_SULFUR.PV

B = Coefficient –272.28299x2

= 20PI0802.PV C = Coefficient 7.0273x3 = 20FC0306.PV

D = Coefficient 3.291770

x4 = 20FC0404.PV Bias = 598.81

Stabilizer-bottom sulfur. This model used several inputs:

Process inputs usedTag name Tag descriptionHDSFD_SULFUR.PV HCN sulfur (HDS feed sulfur

IPPP estimation)

TABLE 3. Process monitoring points used to estimate sulfur

level for the FCC feed inlet

Description Tag name

OHCU bottom rom tank 79FC803.PV

LS VGO rom tank 79FC802.PV

BH VGO rom tank 79FC801.PV

OHCU bottom hot eed 7FC6701.PV

HOT eed rom AVU 12FIC100.PV

DHDS VGO flow 2FC0708.PV

AVU crude select tag* crude_select.op

*The sulur quantity or each o the flow was operator entry.

AVU crude select tag is a digital tag pulled rom the AVU having three values.

Tag value Crude type Sulfur quantity, ppm

1 Bombay High 4,000

2 High Sulur 30,000

3 Nigerian 6,000

Description Densities

OHCU bottom rom tank 0.875

LS VGO rom tank 0.9

BH VGO rom tank 0.9

OHCU bottom hot eed 0.875

HOT eed rom AVU 0.9

DHDS VGO flow

AVU crude select tag

TABLE 2. APC variables for the sub-controller for the HDS unit—

HDSCON

Description Interface point

Manipulated variables:

Fuel gas flow 307FIC0684.SP

HDS reactor 2nd bed quench 307FIC0605.SP

Stabilizer bottom steam pressure 307PIC1003.SP

Disturbance variables:

HDS eed rom GSU 307FI0606.PV

Stabilizer light end eed rom GSU 306FIC0502.PV

HDS reactor 2nd bed bottom

temperatue

307TI0630.PV

HDS eed temperature at GSU 20TI0804.PV

HDS eed sulur HDSFD_SULFUR.PV

Controlled variables:

HDS reactor 1st bed inlet (307R01) temp 307TI0642.PV

HDS reactor 2nd bed inlet (307R01) temp 307TIC0635.PV

Feed ef uent exchanger inlet temp 307TI0607.PV

Stabilizer (307-C-02) bottom temp 307TI1014.PV

Reflux flow to the stabilizer 307FIC1003.PV

Online stabilizer bottom sulur 307AI1001.PV

Stabilizer bottom sulur (inerred) STABBTM_SULFUR.PV


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307TI0642.PV HDS reactor 1st bed inlettemperature

307TI0630.PV HDS reactor 2nd bed bottomtemperature

307TI1014.PV Stabilizer bottom temperature.To estimate the sulfur content of HDS feed, the following

linear equation is used: P = Ax1 + Bx2 + Cx3 + Dx4 + Bias

where: P = STABBTM_SULFUR.PV A = Coefficient 0.115679x1 = HDSFD_SULFUR.PV

B = Coefficient –3.90x2 = 307TI0642.PV C = Coefficient –3.59673x3 = 307TI0630.PV

D = Coefficient –0.341067x4 = 307TI1014.PV Bias = 1067.5

From FIG. 4, the quality estimation using the IPPP has goodagreement with the actual sulfur content as measured fromunit and lab analyzers. TABLE 4 summarizes the economic func-tions and RON improvement possible with APC.

PROJECT MILESTONES

Implementing APC on the HDS unit has yielded substantialtangible and intangible benefits. While the annual monetary gain is of the order of Rs. 39 lakhs, significant improvement

via process control and optimization was achieved as measuredthrough tighter control of the SHU and HDS reactor inlet tem-peratures. More accurate estimation of the stabilizer-bottomsulfur inferential was possible, which facilitated proper controlaction via the APC. With tighter control and action via APC,adjusting and preferentially lowering the reactor-inlet tempera-tures were possible. The effect of crude changes in the atmo-spheric and vacuum distillation unit is also incorporated intothe model. The resultant sulfur changes in the FCC feed aretransmitted via means of intermediate calculations and inferen-

tial estimations to the final stabilizer-bottom sulfur prediction.Operators now have more confidence when implementingcontrol and optimization strategies. This has resulted in betteroperations of the refinery. Accordingly, APC was successfully implemented and is yielding expected benefits.

LITERATURE CITED

1 Perry, R. H., Chemical Engineers Handbook, Sixth Ed., New York, McGraw Hill,1984.

2 Levenspiel, O., Chemical Reaction Engineering, Third Ed., Singapore, John Wiley and Sons, 1999.

3 Stephanopoulos, G., Chemical Process Control, Dorling Kindersley (India) Pvt.Ltd., 2007.

SHYAMAL DEBNATH is the chie technical services manager atIndian Oil Corp. (IOC) Ltd.’s Mathura reinery. His primarily

responsibilities include providing technical services or

strategic initiatives and advanced process control (APC).

Mr. Debnath has more than 25 years o experience in unit

operations, strategic initiatives (process and projects),

research, troubleshooting and APC or all the major process

units at various IOC reineries. He holds an MS degree in chemical engineering

rom Indian Institute o Technology, Kharagpur, India.

HITESH SHAH is a senior technical services manager with Indian

Oil Corp. (IOC) Ltd.’s Mathura Reinery. His primary

responsibilities include providing technical services or strategic

initiatives and APC. Mr. Shah has more than 14 years o

experience in strategic initiatives, planning and coordination,

and APC. At present, he is working as a senior technical services

manager at IOC’s Gujarat reinery. Mr. Shah holds an MS degreein chemical engineering rom Indian Institute o Technology, Bombay, India.

PRASHAT DUBE is a senior process engineer at Indian Oil Corp.

(IOC) Ltd.’s Mathura Reinery. He is primarily responsible or

providing technical services or APC implementation and

maintenance. Mr. Dube has ive years o experience in APC

or all major process units at the Mathura Reinery and holds

a BS degree in chemical engineering rom Indian Institute

o Technology, New Delhi, India.

MS. VARSHA YADAV is a senior process engineer at Indian Oil

Corp. (IOC) Ltd.’s Mathura reinery. She is primarily responsible

or providing technical services or APC implementation and

maintenance. Ms. Yadav has three years o experience in APC

or all major process units at the Mathura Reinery and holds

a BS degree in chemical engineering rom Regional Institute

o Technology, Raipur, India.

TABLE 4. Economic benefit and octane conservation possible

through APC

Economic unction name Maximization o sulur

Speed actor 0.10

Economic coef cients

MAX_AI 10

STEAMMIN 10

MAX_SULFUR 10

MINFG 100

MINRIT1 0

MINRIT2 0

RON improvement

RON improvement ater MVPC

implementation rom the rundown

stream (MS) o HDS unit

0.114

1 unit o RON improvement corresponds

to (1 metric ton o MS processed)

Rs. 91.30

Annual processing o eed (MS) in the

HDS unit (not considering the heart

cut drawn rom FCCU-GS)

376,487 metric ton

Estimated annual benefit due to

MVPC application in HDS unit

Rs. 39,32,517.86

≈ Rs.39. 32 Lakhs

(Rupees thirty nine lakhs thirty

two thousand five hundred

and seventeen only)

Sulur in the stabilizer bottom

MS stream improved

15 ppmw

Sulfur in the rundown MS improved 11 ppmw

Targeted benefits due to RON improvement

Targeted annual benefit due to

MVPC application in HDS unit

Rs. 24.46 Lakhs

Targeted sulur improvementin the rundown MS

10 ppmw

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Refining Developments

P. K. NICCUM, KBR Inc., Houston, Texas

Maximize diesel productionin an FCC-centered refinery, Part 2

Part 1 of this article, published in September, presentedseveral methodologies for maximizing the production of high-quality diesel in a refinery that relies on fluid catalyticcracking (FCC) as its principal means of heavy oil conver-sion. Part 2 focuses on the selection of FCC catalysts, meth-

ods for hydroprocessing light cycle oil (LCO) from the FCCunit, and the production of diesel fuel from FCC byproducts,among other topics.

FCC catalyst selection. Some catalyst recommendationsapply to both high-severity and low-severity FCC operations.Low-hydrogen-transfer FCC catalyst is recommended formaximizing refinery diesel production, as this type of catalyst

will generally produce a higher-yield and higher-quality LCOthat can be hydroprocessed, while increasing the yield of FCColefins that can be oligomerized. Similarly, active matrix func-tionality improves LCO yield and quality.

H2 transfer reactions strip H2 from saturated LCO mole-cules (such as naphthenes) and transfer it into gasoline boiling-range olefins. The net impact of these H2 transfer reactions isthat the LCO becomes more aromatic (lower cetane numberand more dense), the gasoline becomes more saturated (lowerolefin content and lower octane), naphtha yield increases, andLPG olefin yield declines.

In FCC operations intended to maximize gasoline produc-tion, the H2 transfer reactions provide a net benefit due to theincreased gasoline volume resulting from the saturation of the gasoline olefins before they catalytically crack into LPGolefins. The negative impact of H2 transfer activity on LPGolefins, and on naphtha yields and naphtha octane, has been

widely documented, while the negative impact on LCO quality has been less publicized.In high-LCO-yield FCC operations where LCO quality,

gasoline octane and LPG yield considerations are more im-portant than sheer gasoline volume, H2 transfer reactions arecounter-productive. Refer to TABLE 1 for an example of how therare-earth content of FCC catalyst can impact FCC yields andproduct qualities.1

The base catalyst can also be used in combination with aZSM-5-containing catalyst additive to further preserve the gas-oline octane and C3/C4 olefins at low conversion levels. TheZSM-5 additive is applicable to maximizing olefins productionfrom high-severity FCC operations.1, 5 The data in TABLE 2 pro-

vide an example of how a ZSM-5 additive can change the yieldsand product qualities in a moderate-severity FCC operation.2

In low-severity, high-LCO-yield FCC unit operations,ZSM-5 additives have also been shown to convert higher-boil-ing FCC products into both gasoline and LPG. Two examplesof the impact of ZSM-5 additions in low-severity FCC opera-tions are shown in TABLE 3. These data show that the cracking

of heavier molecules in the low-severity FCC products by theZSM-5 results in a loss of total cycle oil (302°F–698°F) pro-duction, along with increases in both 302°F true-boiling-point(TBP) gasoline and LPG production.3

Based on a large sampling of pilot plant product from runshaving an average conversion level of 40% and a 0.5-wt%ZSM-5 crystal addition, the average Research Octane Number(RON) changes were as follows:

• Increase of 2.4 numbers for the initial boiling point (IBP)to 302°F gasoline

• Increase of 3.3 numbers for the IBP to 410°F gasoline.Low-equilibrium catalyst micro-activity testing (MAT) ac-

tivity is often employed when maximizing LCO production. Active-matrix FCC catalysts are also recommended for LCO

TABLE 1. FCC pilot plant comparison o yields and product

qualities with diferent catalysts*

Catalyst

Higher-rare-earth

REY catalyst

Lower-rare-earth

USY octane catalyst

Conversion, vol% 72.5 72.5

Yields

H2, wt% 0.02 0.02

C1 + C2, wt% 1.28 1.13

C3, vol% 1.9 1.4

C3=, vol% 6 7.6

C4s, vol% 13.6 15.1

Gasoline, vol% 59 58

LCO, vol% 18.1 19.5

640°F residue, vol% 9.4 8

Coke, wt% 4.6 4

Gasoline octane, RON + 0 86 90.4

Gasoline octane, MON + 0 78 80

LCO gravity, °API 18.4 20.1

LCO aniline point, °F 62 75

*Constant pilot plant feedstock and operating conditions: 23.9°API VGO, 40 weight hourly

space velocity (WHSV), 4 catalyst:oil weight ratio (C/O), and temperature of 950°F.

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maximization, as they enable the cracking of LCO boiling-rangealiphatic side chains from high-molecular-weight feed compo-nents. In addition to increasing LCO yield, the aliphatic sidechains that report to the LCO boiling range improve LCO ce-tane. The active matrix also contributes to cetane improvements because matrix cracking does not possess the higher H2 transfer

characteristic of a zeolite. Refer to TABLE 4 for representative dataconcerning the impact of changing the catalyst matrix activity.4

Maximize LCO endpoint. The maximization of LCO end-point is a common operating strategy for increasing LCO pro-duction at the expense of low-value FCC slurry oil. In many FCC operations, concern for coking in the FCC main frac-tionator bottoms circuit limits the LCO endpoint. A numberof FCC operating parameters influence the propensity of the bottoms circuit to suffer coking problems:

• Bottoms circuit temperature• Bottoms circuit liquid residence time• Concentration of unconverted paraffins in the slurry oil.In high-conversion FCC operations, the slurry oil is more

aromatic and can be held at higher temperatures and longerresidence times without coking. Some of the slurry oil quality

data that FCC operators monitor as indicators of coking ten-dency are gravity and viscosity. The more aromatic slurry oilproduced by high-conversion FCC operations will allow theunit to operate with lower API gravities while respecting bot-toms viscosity targets selected to avoid fractionator coking.

FCC product considerations. Changes in FCC crackingseverity directly impact FCC product yield distribution andqualities. In the FCC pilot plant example presented in TABLE

5, the VGO is of average quality as an FCC feedstock, and thecatalyst is a low-rare-earth catalyst with some matrix activity.The pilot plant runs covered reactor temperatures and conver-sion levels ranging from low to high, relative to industry norms.

The pilot plant data show the tradeoffs between LCO pro-duction and quality, and the production and quality of FCCnaphtha. As shown in TABLE 5, even without adjusting the LCOcutpoints, the LCO yield changes by a factor of almost 2 by adjusting the FCC reaction severity. At the same time, amongthe runs presented in TABLE 5, the gravity of the LCO increases by about 11°API as the operating severity is lowered.

FIG. 1 summarizes the positive relationship between increas-ing LCO production rate and LCO quality, as observed in a

TABLE 2. Efect o ZSM-5 additive on yields and product

qualities in FCC pilot plant*

Catalyst

Octane-barrel

FCC catalyst

Catalyst with 4%

ZSM-5 additive Delta

Conversion, vol% 68 68 NA

Yields

H2, C1+ C2, wt% 2.38 2.49 0.11

C3, vol% 2 1.9 −0.1

C3=, vol% 6.8 7.4 0.6

C4=, vol% 6.1 6.9 0.8

iC4, vol% 4.2 4 −0.2

nC4, vol% 1.1 0.9 −0.2

Total LPG 20.2 21.1 0.9

Gasoline

(450°F TBP), vol%

57.6 56.8 −0.8

LCO, vol% 18 17.9 −0.1

Bottoms, wt% 14 14.1 0.1

Coke, wt% 3.9 3.8 −0.1

Gasoline octane,

RON + 0

90.2 91.6 1.4

Gasoline cetane,

MON + 0

79.2 79.6 0.4

*Constant pilot plant eedstock (27.0°API VGO) and operating conditions (960°F).

TABLE 3. FCC plant data showing efect o ZSM-5

additive on yields and product qualities

Low-conversion FCC operation Plant A Plant B

Catalyst system

REY zeolite with

ZSM-5 additive

REY zeolite with

ZSM-5 additive

Incremental yields from ZSM-5 addition

Dry gas, wt% +0.3 –

LPG, vol% +2.4 +2.9

Gasoline (302°F IBP), vol% +4.8 +3.3

Total cycle oil (302°F–698°F) –3.2 –6.7

Bottoms (698°F+) –4.5 +0.2

Coke, wt% – +0.2

TABLE 4. FCC pilot plant study results

Catalyst matrix surface area Low High

Conversion 69.5 69.7

Gasoline (C5 at 421°F)

Yield 53 53.1

RON 87.7 90

MON 77.8 78.5

Paraf ns/olefins/napthenes/

aromatics (PONA)

36/23/15/27 26/36/14/24

LCO (421°F–602°F)

Yield 16.3 19.2

Cetane index 24.5 28.5

API 21.8 23.8Carbon NMR

Aromatic carbon, % 49.5 45.9

Aliphatic carbon, % 50.5 54.1

Bottoms (602°F+)

Yield 14.2 11.1

Gravity, °API 13 7.6

Carbon NMR

Aromatic carbon, % 39 57.4

Aliphatic carbon, % 61 42.6

Viscosity at 210°F, cst 7.87 5.8

Viscosity at 100°F, cst 116.4 68.14

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larger sampling of the same pilot plant study data. Conversely,FIG. 2 and FIG. 3 show a very direct and negative correlation

between LCO yield and FCC naphtha octane. FIG. 2 demon-strates that, irrespective of the indicated FCC reaction tem-perature, FCC naphtha motor octane will suffer as LCO yieldincreases. FIG. 3 shows that the negative impact of increasing

LCO yield on the olefin-dependent RON can be mitigated tosome extent, if a high FCC reaction temperature is maintained.The data in TABLE 5 also provide examples of how chang-

ing FCC reaction severity can impact LPG yield and naphthaoctane. Comparing the low-conversion and high-conversioncases, the data show that the low-conversion case produces lessthan one-half the LPG and 3 to 4 numbers lower octane thanthe high-conversion case.

TABLE 5 also provides an example of the degradation of LCOas a potential feedstock for upgrading into diesel as the FCC

conversion is increased; the LCO H2 content decreases from10.7 wt% to 8.8 wt% as the FCC conversion level is increasedfrom 59 wt% to over 76 wt%.

Hydroprocessing options. Processes for the upgrading of LCO range from mild hydrodesulfurization to full-conversion

hydrocracking. FIG. 4 depicts some of the chemistry responsible for improving the cetane, density and aromatics content of the LCO. For the purposes of this article, three upgrading pro-cesses (hydrotreating, aromatics saturation and mild hydro-cracking) are described as representative examples of some of the processes being used today.5

LCO hydrotreating. Mild hydrotreating of LCO will re-duce its sulfur content significantly, but this will only modestly improve the product qualities related to aromatic content. Inexamples presented in TABLE 6, LCO in a 10% concentration, in

TABLE 5. FCC pilot plant data showing impact of changing operating severity

Low conversion Medium conversion High conversion

FCC feed properties

Gravity, °API 22.5 22.5 22.5

50 vol% boiling point, °F 851 851 851

Aniline point, °F 176 176 176

Sulfur, wt% 0.55 0.55 0.55

CCR, wt% 0.89 0.89 0.89

FCC pilot plant operating conditions

Riser temperature, °F 940 979 1,020

Feed temperature, °F 416 485 337

Catalyst-to-oil ratio, wt/wt 6.6 6.7 11.4Micro Activity Test (MAT) 67 67 67

Rare-earth oxides, wt% (FCC E-Cat property) 0.6 0.6 0.6

FCC pilot plant yields

Dry gas, wt% 1.23 2.08 3.5

C3 LPG, wt% 2.97 4.26 7.27

C4 LPG, wt% 5.98 7.88 11.57

Gasoline (C5 at 430°F), wt% 43.21 46.98 46

LCO (430°F–680°F), wt% 27.42 24.47 16.01

Slurry oil (680°F+), wt% 13.6 9.06 7.66

Coke, wt% 5.59 5.27 7.99Conversion, wt% 58.98 66.47 76.33

FCC pilot plant product qualities

C3 LPG olefinicity, wt% 83.8 83.8 85.7

C4 LPG olefinicity, wt% 66.7 68.5 67

Naphtha gravity, °API 56.6 57.2 55.9

Naphtha octane, RON/MON 91.7/81.1 92.9/81.6 95.6/84.4

Naphtha PONA, wt% 27.2/49.5/11.8/11.5 25.7/49.1/10.9/14.3 31.3/36.8/10.5/21.4

LCO gravity, °API 22.2 17 11.3

LCO H2 content, wt% 10.7 9.9 8.8

Slurry oil gravity, °API 6 −0.8 −7.4Slurry oil H2 content, wt% 9 7.8 6.7

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a mixture including straight-run gas oil (SRGO), is hydrotreat-ed. Two options are presented, with the latter representing ahigher degree of desulfurization and greater aromatics reduc-tion. These examples demonstrate that it is possible to includeabout 10% LCO in the diesel pool by hydrotreating the LCO/SRGO mixture.

Aromatics saturation. To accommodate larger concen-trations of LCO in the diesel pool, more complete aromatics

saturation and cetane improvement are required. These goalscan be achieved through varying degrees of ring saturation andring opening, as shown in FIG. 4. TABLE 7 shows what is possibleutilizing a two-stage aromatics saturation unit to process 100%LCO.5 The drawback of ring saturation is high H2 consumption.

Mild hydrocracking. Another alternative is to rely on ring

opening with mild hydrocracking to move some of the aro-matics out of the LCO boiling range into gasoline, as shown

TABLE 6. Processing a 10% LCO blend with ULSD catalyst systems

Operating pressureFeed: 90%

SRGO/10% LCO

Product

CoMo NiMo

Medium High

Density, kg/m3 880 863 853

Sulfur, wppm 15,300 50 10

D86 T10, °F 543 534 523

D86 T50, °F 586 579 570

D86 T90, °F 660 657 649

IP91 monoaromatics, wt% 16.7 22.6 21.4

IP91 PNA, wt% 15 9.2 2.8

IP91 total aromatics, wt% 31.8 31.8 24.2

Cetane number 47 51 52.5

H2 consumption, Nm3/m3 NA 37 72

TABLE 7. Two-stage LCO aromatics saturation

100% LCO Product

Operating mode Two-stageOperating pressure Medium

Density, kg/m3 960 859

Sulfur, wppm 7,300 < 10

Total aromatics (FIA), vol% 79.1 2.5

Cetane index, D976 24.1 40.2

Cetane number < 20 44.9

Delta cetane number NA 25+

Liquid yield, vol% NA 115.7

H2 consumption, Nm3/m3 NA 473

LCO quality

5

10

15

20

25

30

10 20 30LCO yield, wt%

G r a v i t y ,

° A P I

940°F

980°F

1,020°F

FIG. 1. Relationship between increasing LCO production rate

and LCO quality.

940°F

980°F

1,020°F

FCC naphtha quality

80

81

82

83

84

85

10 15 20 25 30 35

LCO yield, wt%

N a p h t h a M O N

FIG. 2. Relationship between FCC naphtha quality (MON)

and LCO yield.

90

91

92

93

94

95

96

10 20 30LCO yield, wt%

N a p h t h a

R O N

940°F

980°F

1,020°F

FCC naphtha quality

FIG. . Relationship between FCC naphtha quality (RON)and LCO yield.

2H2

1

2

3

3H2Diesel

Diesel

Diesel

3H2

C5H11 C5H11

Aromatic saturation

HydrocrackingSelective ring opening

H2 H2

FIG. 4. Three reactions to upgrade LCO quality.

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in FIG. 5.5 This approach can provide substantive LCO quality improvement with lower H2 consumption. TABLE 8 providesan example of coprocessing LCO along with straight-run dis-tillate and other cracked products.5

Creating diesel from FCC byproducts. Two processing op-tions with limited application to date are the creation of syn-thetic diesel from FCC olefins and the extraction of aromaticsfrom FCC naphtha. These options can be integrated into theoverall processing scheme, along with the other options de-scribed earlier.

Reprocessing of C3–C9 olefins into distillate. Olefins can

be used to produce good-quality diesel with oligomerizationprocesses. For example, an oligomerization unit distillate yieldfrom a C3–C9 olefin feed was reported to be 78% distillate witha byproduct gasoline yield of 19%, based on a zeolite catalyst,as shown in TABLE 9. After hydrotreating to saturate the olefins,the distillate was reported to have a cetane number of 52 to 54,zero sulfur and less than 2% aromatics.6

Therefore, for FCC-based refineries working to maximize die-sel production, oligomerization of olefins-containing FCC lightgasoline and LPG may provide viable investment opportunities.

FCC naphtha extraction. Extractive techniques are avail-able for separating a middle boiling fraction of FCC gasolineinto a higher-octane, aromatics-rich fraction and an olefins-

and paraffin-rich fraction.7 A recently granted patent describesa combined FCC/extraction process wherein an aromatics-

rich, higher-octane fraction of FCC gasoline can be producedas a gasoline product, while a paraffinic/olefinic naphtha frac-tion can be produced for recycle to an FCC riser for the pur-pose of producing propylene and other olefins.8

This FCC naphtha extraction concept and oligomeriza-tion technology can be used together, as shown in FIG. 6, tomaximize the production of synthetic diesel from FCC olefins.The combination can be especially useful in the context of ahigh-LCO-yield, low-severity FCC operation because the low-

severity FCC naphtha will have a higher olefins content thanthe more aromatic, more paraffinic naphtha from a high-sever-ity FCC operation. Thus, the non-aromatic naphtha raffinatefrom a low-severity FCC operation will make a better-quality oligomerization feedstock—or a better-quality FCC recyclestream—for the purpose of increasing lighter FCC olefins pro-duction, as olefins are easier to crack than paraffins.

Refinery diesel balance. With all the processing optionspresented in this article, an obvious question is, “How muchcan the refinery diesel production be increased if many of theseoptions are applied in a retrofit of an existing refinery?” Theanswer depends on the specifics of the application. TABLE 10

shows estimated results from isolated examples provided inthis article, giving insight into the question.

N-parafn

Mononaphthenes

Selective ringopening

AromaticsaturationAromatic

naphthene

Monoaromatics

Dinaphthenes

Diaromatics

C e t a n e n u m b e r

-20

0

100 150 200

Molecular weight250 300

20

40

60

80

100

FIG. 5. Hydrocarbon comoponents and cetane number. Solvent

Rafnate: parafns + olefins

Extract: sulur + aromatics

Aromatics

MCNFCC naphtha

LCN

HCN ULS gasoline blending

Severe HDS

HDS

HDSOlefinoligomerization

unit

FCC C3 /C4 LPG

FCC recycleH2 H2S

H2 H2S

Diesel

LPG

Naphtha

FIG. 6. Production of diesel from FCC LPG and FCC naphtha.

TABLE 8. ULSD and mild hydrocracking on feed blend containing 10% LCO and 35% coker diesel*

Property Feed ULSD product MHC product MHC product

Density, kg/m3 866 842 829 822

Delta density NA 24 37 44

Sulfur, wppm 8,000 < 10 < 10 < 10

SFC aromatics (total), wt% 42.4 23 13.2 14

Mono 30 20 12.8 13.5

PNA 12.4 3 0.4 0.5

Total product cetane index, D4737 36.8 43.8 46.2 46.8

Delta cetane index NA 7 9.4 10

Chemical H2 consumption, Nm3 /m3 NA 116 150 155

Incremental 379°F minus, vol% NA 1.1 10 20

*For MHC cases, diesel product is 2 to 3 cetane numbers higher than total product.

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Takeaway. Assuming demand for diesel continues to increasefaster than growth in gasoline, a number of reactions can beexpected from the refining industry:

• The loss of virgin diesel to the FCC unit will diminishthrough crude distillation unit improvements

• FCC gasoline endpoint will be minimized

• Hydrocracking and hydrotreating units designed to up-grade LCO quality will proliferate• Low-H2 -transfer, higher-matrix-surface-area FCC cata-

lyst will be used to improve LCO yield and quality, while in-creasing LPG olefins production and naphtha octane

• In some cases, ZSM-5 catalyst additives will be used tofurther increase LPG olefins production and octane, but inlow-severity FCC operations, this may come at the expense of some LCO yield.

For refiners that also place high value on propylene produc-tion, high-octane gasoline, and minimization of refinery bottomsproduction, the high-severity FCC route to making more diesel

will gain favor through the oligomerization of C4 and higher FCC

olefins while continuing to hydroprocess the LCO production.If a refiner has a more singular focus on the production of

diesel, the low-severity, traditional FCC route to increasingdiesel can be optimized and economically favored, with someenhancements:

• The loss of LCO in slurry oil product or recycle will di-minish through the use of dedicated slurry distillation hardware

• Some of the stripped slurry oil may be recycled to theFCC reactor to produce more LCO and help maintain FCCheat balance, while HCO recycle may also be advantageous

• Low-severity FCC operations will rely on increasing feedtemperature and, in some cases, direct firing of the regenera-tor with a liquid or gaseous fuel using technology designed to

minimize damage to the catalyst• FCC-produced LPG and naphtha olefins will be convert-ed into diesel blending stock using oligomerization processes.

An ultimate vision for maximizing diesel production in aspecific FCC-centered refinery may also include a selectivecombination of elements:

• Extraction processes will separate aromatics-rich frac-tions of FCC gasoline from fractions enriched in olefins andparaffins. The aromatic fraction can be used for BTX produc-tion or high-octane motor fuel; the non-aromatic fraction can

be recycled to the FCC reactor for the production of more ole-fins (diesel precursors), or the olefins in the non-aromatic frac-tion may be directly oligomerized into diesel.

• FCC C4s and FCC light naphtha can be recycled to an ul-tra-high-severity FCC riser to increase propylene and aromaticnaphtha yields, without diminishing LCO production.

A case-by-case analysis based on refinery-specific data isneeded to accurately contrast the costs and benefits associated

with the application of various options for increasing diesel pro-duction from the FCC-centered refinery. The performance of the study requires both refinery-wide and FCC-specific expe-rience and related modeling capabilities. In the final analysis, itis simply a question of economics; technologies are available tomaximize diesel production from the FCC-centered refinery.

LITERATURE CITED

Complete literature cited available online at HydrocarbonProcessing.com.

TABLE 9. Product yields and properties from oligomerization

of olefins

Feed composition 82% C3–C9 olefins

Product yields (based on feed olefins), vol%

Gasoline 19

Distillate 78

Distillate qualities after mild hydrotreating

Boiling range, °F (IP 123/84) 388–676

Density, kg/m3 at 20°C 787

Cetane number 52 to 54

Aromatics content, wt% < 2

Sulfur content, wt% 0

Viscosity, cst at 104°F 2.55

TABLE 10. Examples of refinery diesel increases

Vol% of refinery crude input (assuming 27% crude oil to FCC unit

and LCO hydroprocessing to maximize diesel in all cases) Low-severity FCC Moderate-severity FCC High-severity FCC

Change FCC severity (assuming constant MAT and no recycle) 0.9 – –2.5

Minimize diesel in FCC feedstock 3.2 3.4 3.6

Lower FCC naphtha endpoint 5.1 5.3 4.6

Change FCC catalyst formulation

(increase FCC catalyst matrix activity and reduce H2 transfer activity)

1.3 1.3 1.3

Refractionate slurry oil (recover 30 vol% LCO from slurry) 1.1 0.7 0.6

Oligomerize C3–C5 olefins 3.1 3.7 5.1

Oligomerize C6+ naphtha olefins 3.8 4.3 2.6

Total increase in diesel production, vol% 18.4 18.6 15.3

PHILLIP NICCUM joined KBR Inc.’s fluid catalytic cracking (FCC)

team in 1989, following nine years of FCC-related work for a

major oil company. Since that time, he has held various FCC-

related positions at KBR Inc., including process manager,

technology manager, chief technology engineer of FCC, director

of FCC technology, and now process engineering manager.

Mr. Niccum’s professional activities have included engineering

management, process engineering, project engineering, marketing, and

licensing. Areas of technical strength include FCC unit design, precommissioning

and startup, troubleshooting and economic optimization of FCC unit operations.

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Optimize sulfur recovery from dilute H2S sources [S–69]

CORPORATE PROFILES

CB&I [S–75] Enersul Limited Partnership [S–77] Foster Wheeler [S–79] Shell Global Solutions [S–80]

COVER PHOTO A sulfur recovery unit designed and operated by the Ponca City Refinery. Phillips 66 developed this

selective partial oxidation catalytic (SPOC) combustion technology for sulfur recovery. The technology, developed and extensivelytested by Phillips 66, is now exclusively licensed worldwide as a flameless Claus process by GTC Technology as GT-SPOC™.

SULFUR 2012

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transer assurance, technology review, training and education.

Hyperion Systems Engineering Public Ltd. is a company incorporated under the laws o the Republic o Cyprus and is the holding company

o the Hyperion Systems Engineering group with registered subsidiaries in Greece, China, Russian Federation, Singapore, Kingdom o Saudi

Arabia, Kingdom o Bahrain, India, United Kingdom and the United States. The company is also certified to the ISO 9001:2008 standard and

is audited/registered or ethical commercial practices by TRACE International.

For more information visit hyperionsystems.net

26–28March 2013

EMGasConference.com

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SULFUR

OPTIMIZE SULFUR RECOVERYFROM DILUTE H2S SOURCESM. P. HEISEL, ITS Reaktortechnik GmbH, Pullack, Germany; and

A. F. SLAVENS, WorleyParsons, Monrovia, California

With the recent emergence of “sweeter” fuel sources such as uncon-ventional gas and biofuels, the sulfur industry is challenged in providingeconomical solutions to desulfurize gas streams with low hydrogensulfide (H2S) content. Historically, the sweetening of such gases wasprimarily accomplished by using liquid redox processes.a These estab-lished, sweetening processes treated the raw gas stream directly anddid not require an amine treating step, thereby reducing the total capitaland operating costs of the facility.

Liquid redox processes are capable of scrubbing the H2S to verylow levels and meeting typical treated-gas specifications, as proven byseveral hundred units that are in operation. However, these facilitiesoften suffer from very high operating costs, low availability and a low-quality sulfur product, which usually must be disposed rather than soldas product. The inherent nature of these problems is discussed here:

• High operating costs are a result of the process chemistry, espe-cially consumption of the expensive chelating agents required to keepthe direct oxidation catalyst in solution. Consequently, chemical costsrange from $100 to $150 per ton of produced sulfur.

• The product sulfur contains some chelating agent and, therefore, isa low-quality material. As a consequence, no revenue from sulfur salescan be expected. More important, additional costs associated with

landfill disposal can be incurred.• Low process availability results from two primary steps, as shown

in FIG. 1. In the scrubber (1), sour gas is contacted by liquid solventand thus forming the solid sulfur, which often leads to plugging in thecolumn or in downstream vessels and pipes. In the re-oxidation vessel(5), foaming and sulfur froth can occur, thus reducing availability.

New technology. A newly developed process applies a totally differ-ent approach.b This process first oxidizes H2S selectively in the gasphase over a robust and low-cost catalyst. To increase sulfur recoveryefficiency above what was achievable in the selective oxidation step,the process subsequently applies the sub-dewpoint principle. It is a well-known Claus tail-gas treatment technology that takes advantage of the

improved Claus equilibrium at lower operating temperatures (below thesulfur dewpoint) in the catalytic reactors. The process can achieve sulfurrecovery efficiencies exceeding 99% when treating in low H2S-contentgases, such as shale gas, coalbed methane and biogas. The processis inexpensive and easy to operate; it generates no byproducts, andthe sulfur recovered is of premium quality. The direct oxidation processis capable of treating raw gas streams containing H2S plus hydrogen,light hydrocarbons, oxygen and/or inert gases. FIG. 2 shows a flowdiagram of the new direct oxidation process.

Process description. The feed gas to the sulfur recovery unit (SRU) ismixed with a stoichiometric quantity of air to convert the incoming H2Sto elemental sulfur via direct oxidation. The gas mixture is sent through

a preheater to the first reactor. This reactor is different from conven-tional Claus reactors: it contains two sections. The upper section at

the gas inlet is a conventional fixed-bed reactor with a direct-oxidationcatalyst. In this reactor section, part of the feed H2S is oxidized intoelemental sulfur according to Eq. 1. In parallel, some sulfur dioxide(SO2) is formed. The second section in the lower part of the first reactorcontains a Claus catalyst with an embedded heat exchanger, whichis designed to remove the heat of reaction from the catalyst bed. Theheat removal within the catalyst bed shifts the equilibrium of the Clausreaction (Eq. 2) toward more sulfur formation, substantially improving

conversion efficiency.

Direct oxidation of H2S2 H2S + O2 = 2/x Sx + 2 H2O + heat of reaction (1)

Sour gas Vented air

AirSulfur

Catalytic solution

1

2

3

4

5

6

LP flash gas

Purified gas

FIG 1. Typical process flow diagram of a liquid redox process.1

Feed gas

Air

Selectiveoxidationreactor

Sub-dewpointreactor

Reheat

4-way valveSulfurseparator

Air blower

Purified gas

Sulfurcondenser

Sulfur pit

Recycleblower

(optional)

Preheat

4-wayvalve

C01 Air blower, E01 Preheat, V01A/B 4-way valves, R01 A/B Reactors with internal cooling, E02 Sulfur condenser,D01 Sulfur separator, E03 Reheat, P01 Sulfur product pump, C02 Recycle blower (optional)

FIG. 2. Typical process flow diagram of new direct oxidationprocess for H2S.

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SULFUR

Claus reaction2 H2S + SO2 = 3/x Sx + H2O + heat of reaction (2)

where x = 2, 4, 5, 6, 8 sulfur molecules of different sizes, accordingto temperature.

The heat exchanger applied is a thermoplate stack with large clear-ances, as shown in FIG. 3. The space between the thermoplates is filled

with catalyst. As this heat exchanger type is not yet so well known withinthe sulfur industry, it will be discussed in more detail later.

A sulfur condenser is located downstream of the first reactor. Asecond reactor, identical to the first reactor, follows the sulfur condenserbut operates at lower temperature. This shifts the chemical Claus equi-librium to even more sulfur formation. The reactor outlet temperaturesrange from 100°C to 125°C, i.e., possibly even below the sulfursolidification point.

When operating below the sulfur dewpoint, the sulfur formed viathe Claus reaction accumulates on the catalyst. Thus, the catalystdeactivates slowly and must be regenerated. The regeneration isaccomplished by switching the second reactor into the first reactorposition. In the first reactor position, the inlet temperature approaches

320°C, which desorbs sulfur and regenerates the catalyst. The formerfirst reactor is switched at the same time into the second, cooler reactorposition. This procedure is repeated typically once every 24 hours.Treated gas from the second reactor is sent to the consumer, e.g., aspurified biogas or natural gas.

Process capabilities. The new direct oxidation process can be appliedto a number of plants such as for:

• Biogas purification• Offgas treatment from chemical processes rich in methane, carbon

dioxide and hydrogen• Natural gas purification.

Pure, bright yellow elemental sulfur is produced. The process opera-tion is fully automatic, with manual control only required during startupand shutdown, similar to a conventional Claus plant. The first commer-cial unit was installed in 1993 and is still in operation.

The high sulfur-recovery rate (SRR) in the new oxidation processresults from removing the heat of reaction, which shifts the chemicalequilibrium to more product formation. FIG. 4 illustrates the effect onSRR, where the SRR is depicted as a function of the outlet temperaturefrom the second reactor.

In addition to high-sulfur recovery efficiency, the internally cooledreactors provide other benefits. The internal heat exchangers are self-controlling. Boiler feedwater (BFW) feeds the inside of the thermoplate;the BFW always has a temperature corresponding to the generated

steam pressure. On the outside, i.e., between the thermoplates, thecatalyst and reaction gas release heat. The greater the gas flow, thehigher the heat of reaction, which is the temperature difference betweenthe gas and BFW. With the higher temperature ⌬, the heat of reaction isautomatically removed by internal cooling. As a consequence, the tem-perature at the outlet of the reactors is constant within a narrow range,and is independent of fluctuations in gas volume and gas composition.Accordingly, this process is intrinsically stable, easy to operate and hashigh reliability. Actually, all normal operations are fully automatic, thusvery little operator attention is necessary.

Commercial unit. The first commercial plant applied a two-reactor pro-cess configuration; it was started up in December 1995 in the Nynäs

refinery in Sweden (FIG. 5). This unit processes amine-acid gas andsour-water-stripper gas. The plant has proven to be very reliable, easy

Solid sulfur

S R R ,

%

Liquid sulfur

99.2

100 105 110 115 120

Temperature, °C125 130 135 140

99.3

99.4

99.5

99.6

99.7

99.8

99.9

100.0

FIG. 4. Sulfur recovery rate as a function of outlet temperatureof the second reactor for rich feed gas with 85% H2S. FIG. 5. Sulfur recovery plant in the Nynäs refinery in Sweden.

FIG 3. Top view of a thermoplate heat exchanger for a reactorduring construction in the shop.

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HydrocarbonProcessing.com

HPI

MARKETDATA

2013Available October 15thGeopolitics, emerging markets and new technology are transforming the

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SULFUR

to operate, and requires very little maintenance. Availability is alwaysbetter than 99.5%/yr. The refiner claims that this plant is the most reli-able within the whole refinery, even after more than 15 years of opera-tion. It achieved the required SRR and reached optimal values of up to99.85%, even with aged catalysts. In operation at low load conditions(at 6:1 turndown), the SRR dropped by only 0.1%.

Thermoplates for internal cooling of catalytic reactors. Internallycooled catalytic reactors have been successfully used in many applica-tions. They are applied primarily for selective reactions, where rigoroustemperature control is required, or in reactions where the chemicalequilibrium is strongly temperature dependent. In the past, straight-tubereactors, with the catalyst inside the tubes, have typically been used. In

a few cases, spiral-wound tubular heat exchangers have been appliedwith the tubes submerged in the catalyst.

However, these reactor types have features that are not comple-mentary to the operations. Primarily, the heat exchangers’ fabricatedgeometry often forces conditions on the catalytic reactions that arenot optimal. For example, the straight-tube reactors had to be builtslim and high to avoid excessive thermal stress on the tube sheets,which resulted in a high pressure drop, high linear gas velocity andmechanical stress on the lower catalyst particles. The spiral-woundheat exchangers avoid these disadvantages to some degree, but theyrequire many manufacturing steps and precise fabrication skill. Theyare typically more expensive.

Both types of reactors cannot be built onsite, and, therefore, one

must observe transportation limitations. This also limits throughputcapacity. In view of ever-increasing plant sizes, this condition becomesincreasingly more important. All of these features for tubular reactorsare detrimental for sulfur recovery, which may explain why internallycooled reactors have not been used widely in sulfur recovery previously.The catalytic reactors incorporated in the new-generation direct oxida-tion process use thermoplates as heat exchangers, thus eliminating allof the listed disadvantages. The basic element of a thermoplate heatexchanger is the thermoplate itself, as shown in FIG. 6.FIG. 6. Schematic of a thermoplate heat exchanger.

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SULFUR

A thermoplate consists of two metal sheets welded together alongtheir edges and point-welded across their surfaces. This is accomplishedwith precise fabrication machinery that facilitates the manufacturing oflarge surface area exchangers at low cost. The plates are expandedby injecting high-pressure liquid between the metal sheets, which openschannels for the cooling medium, as shown schematically in FIG. 6.

The expansion generates the typical cushion shape, and the point andseam welds of the thermoplates are gap free. Multiple thermoplates arecombined to form a heat exchanger package, which is then inserted ina shell to complete the heat exchanger.

For application in a reactor, the catalyst is poured into the spacingbetween thermoplates, as shown in FIG. 3. Vertical plane walls areformed by the thermoplates and allow easy filling of the catalyst particles.

Several thousand such thermoplate heat exchangers have been builtand installed worldwide. They are in service in even the most severeapplications, such as condensing phosgene, which is not only highlytoxic, but is also very corrosive when in contact with water. Singleheat exchangers with several thousands square meters of exchangersurface area have been installed and operated. The thermoplate heat

exchanger is considered a proven technology. These exchangers arecompact and light weight, have low pressure drop, and provide highheat exchange coefficients; they are ideal for sulfur-recovery reactors.

The outer and inner fluid channels are completely separated fromeach other by seam welds. As in contrast to other plate-heat exchangers,there is no contact between adjacent thermoplates; each thermoplateis self-contained and no forces are transferred to the next plate. Thecatalyst particles are insulated and do not experience mechanical stress.

The distance between plates, file height, pitch of the point welds,

dimensions and number of thermoplates can vary widely. Therefore,thermoplate reactors can be optimally tailored to each sulfur recoveryapplication.

Options. The new direct oxidation process is an economic methodfor sulfur recovery from low-H2S content gases. It converts H2S in a

gas catalytic process directly to elemental sulfur. The sulfur recoveryefficiency, which depends on the feed-gas composition, is greater than99%. The reaction takes place in two identical fixed-bed reactors withinternal cooling by thermoplate heat exchangers, which maintain theoutlet temperatures of the reactors within a narrow range, thus maintain-ing a constant SRR. This process has proven to be easy to operate, veryreliable and with low maintenance costs. As one customer commented,“Our biggest problem with this process is that the operators tend to for-get about it, because it requires so little of their time and attention.”

LITERATURE CITED

1 www.prosernat.com/en/processes/gas-sweetening/sulfint-hp.

NOTES

a Liquid redox processes include LO-CAT, SulFerox and Sulfint.b SMARTSULF is a new sulfur oxidation process.

Michael Heisel, PhD, is general manager of ITS Reaktortechnik GmbH. He hasmore than 30 years of experience in sulfur recovery plant design, star tup, validationand troubleshooting.

Angela Slavens is vice president and global director of sulfur technology for WorleyParsons. She has more than 15 years of experience in the oil and gas industry, primarilyin the field of sour gas treating and sulfur recovery.

26–28 March 2013EMGasConference.com

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CB&I COVERS THE ENTIRE PROJECT

LIFECYCLE, CONCEPT TO COMPLETION

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From humble beginnings nearly 125 years ago, CB&I has continuallyexpanded its capabilities to serve the energy and natural resource indus-tries. Today, CB&I engineers and constructs some of the world’s largestenergy infrastructure projects. With premier process technology, provenEPC expertise and unrivaled storage tank experience, CB&I executesprojects from concept to completion.

We offer a comprehensive range of capabilities that span the entireproject lifecycle:

CB&I’s Project Engineering and Construction business sector buildsupstream and downstream oil and gas projects, LNG production andregasification terminals, and a wide range of other energy relatedprojects.

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Safety is a core value at CB&I and we are proud to have one of thebest safety records in the industry. Throughout our organization, everyemployee worldwide is committed to safe work practices. Our award-winning safety program promotes a culture of involvement and dedica-tion with a goal of zero incidents for everyone involved in our projects.

CONTACT INFORMATIONCB&I2103 Research Forest DriveThe Woodlands, TX 77380 USATel: +1 832 513 1000Fax: +1 832 513 [email protected]

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ENERSUL LIMITED PARTNERSHIP

ENERSUL LIMITED PARTNERSHIP

TRUSTED EXPERIENCE. PROVEN EXCELLENCE.

Enersul Limited Partnership headquartered in Calgary, Alberta, hasbeen the world leader in the sulphur forming and handling industry forover sixty years. With a complete array of operational, technical, andsupportive offerings, Enersul has the unique ability to provide completesulphur solutions, customizable to fit any production requirement.

OPERATIONAL SOLUTIONS

Enersul’s Operational Solutions has a depth of experience unmatchedin the field. Long-standing relationships with sulphur producers haveestablished Enersul’s reputation as a leader in reliability, safety, andenvironmental consideration.

Having taken complete operational control of the sulphur require-

ments of a variety of projects enables Enersul to innovate their offer-ings to meet the needs of the real world. Lessons learned by Enersul’sinternational project teams are applied across every aspect of Enersul’sproducts and services.

TECHNICAL SOLUTIONS

From when molten sulphur leaves the SRU to transportation loadingfor its final destination, Enersul provides customizable technical solutionsfor every step of the process. Each technology has been designed tomeet the strictest safety and environmental standards with a dedicatedfocus to functional reliability and standard setting end-product quality.

H2S DEGASSING

In response to the need for a compact and efficient sulfur degassingprocess, Enersul developed the HySpec™ H2S degassing process.These processes has been specifically designed to quickly, effectivelyand economically reduce the H2S content of liquid sulfur to 10 ppmor less. The in-line, continuous flow design of the HySpec™ processeliminates the need for large molten sulfur pits typically required withtraditional batch-type degassing systems.

This concept allows for easy retrofitting of existing facilities, reducingthe capital cost of degassing system installations. Due to its modular andcompact design, a HySpec™ unit can be installed with only minor tie-insand minimal disruption to ongoing operations.

LIQUID SULPHUR SOLUTIONS

Enersul develops systems to pipe, store, filter, cool, and load moltensulphur. Safety, the environment, and reliability are constant consider-ations applied to flexible executions to meet any specific plant produc-tion requirements or shipping schedule.

SULPHUR FORMING

The GXM1™ has a forming capacity of 1250 tonnes per day. It iscompletely self-contained: a compact design with a rotating drum, acooling water system, a wet scrubber, vibrating screens and conveyors.Operation is simple so on-time performance is high, labor requirementsare minimal, and costs for repair, maintenance and utility consumptionare kept low.

The GXM3™ is the first SinglePass™ granulation technology and the

only portable sulfur forming unit on the market. This patent pending tech-nology was developed for use on sites with smaller plant footprints and

for clients that require smaller production rates. It arrives 90% assembled,with most of the system checks already completed, thus saving on con-struction and commissioning time and costs. Each unit can produce upto 400 tonnes of high quality granules per day.

Enersul’s WetPrill™ product is known for its low friability, lowermoisture content and high bulk density as compared to other wet prillproducts. The WetPrill process units can be scaled for operations rang-ing from 100 to 2500 tonnes per day with higher throughput achievedwith multiple process lines.

SOLID SULPHUR HANDLING AND STORING

Enersul provides a variety of conveyor systems to safely and efficiently

handle formed sulphur designed to reduce end-product degradation.Transfer points are kept to a minimum, drop distances are minimized,and covered or non-covered handling systems are designed to ensureformed sulphur retains the high quality only available from Enersul’spatented forming technologies.

TRUSTED EXPERIENCE. PROVEN EXCELLENCE.

Enersul specializes in one thing, the safe, reliable, and environmen-tally friendly forming and handling of sulphur. Over 60 years of innova-tion with a focus on end-product quality, and the ability to customizetechnical and operational solutions to any plant requirement meansthe worlds sulphur needs can rely on Enersul’s Trusted Experience andProven Excellence.

CONTACT INFORMATION

7210 Blackfoot Trail SECalgary Alberta Canada T2H 1M5Phone: (403) 253-5969Fax: (403) 259-2771

E-Mail: [email protected]

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What you can do

with atouch of blue.

You can… Enhance the efficiency of your overall sulfur recovery to achieve peakoperating and environmental performance with our SRU technology.

Lower burner operating temperatures with our proprietary acid gasburner technology, ultimately extending the operating life of theburner and reducing operating and maintenance costs.

Maintain environmental compliance with sulfur recovery efficienciesup to 99.9+% to meet the most stringent environmental regulations.

Replace your burner in an existing plant.

Our high performance technology, coupled with our focus onaftermarket support and training, delivers the result you need.

Visit www.fwc.com/touchofblue for more information on our sulfur recovery technology.

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FOSTER WHEELER

OPERATING, ENVIRONMENTAL SOLUTIONSWITH SULFUR RECOVERY TECHNOLOGY

SULFUR RECOVERY TECHNOLOGY Foster Wheeler’s proprietary and proven sulfur recovery technology

brings clear advantages to our refinery customers. The technology pro-vides cost-effective designs with enhanced operability features. Includedin the proprietary technology is a Claus unit burner that is capable ofdestroying ammonia up to 25 mole % in the SRU feed, and providinglow level oxygen enrichment up to 28 mole %. The units typically deliveroverall sulfur recovery efficiencies ranging from 96% to 99.9+% depend-ing on the configuration of the claus and tail gas treating sections.

OUR EXPERTISE

Our personnel employed at the new Foster Wheeler Salt Lake Cityoffice are knowledgeable in the design of sulfur block units, includingClaus units, tail gas treating units and tail gas incinerators. Our sulfurexpertise also includes sour liquid or gas amine absorbers, amine regen-erators, sour water strippers, sulfur condensers, waste heat boilers, sulfurstorage, sulfur degassing, and sulfur pit vent disposition. Other areas ofproficiency include hazardous waste incineration, natural gas process-ing, general refinery units, and mining and chemical plants.

OUR SCOPE OF WORK Coupled with the small footprint, our design offers reduced piping

runs that are completely free draining. Lower corrosion and reducedpressure drop are clear benefits from the reduced pipe routing, which

also results in lower Capex and enhanced operability and maintenance.The footprint of our claus units is minimized by combining the waste

heat boiler and sulfur condensing tube bundles in a common shelloperating at steam pressures matching the refinery steam system, andproviding the steam required for the claus unit operation. The mechanicalexpertise required for reliable and safe design of the waste heat boilerand sulfur condenser tubesheets, as well as the partitioning of the con-denser passes in the boiler plenums, has been developed through many years of experience. Steam pressures ranging from 50 psig to 600 psigare available, and each plant is designed to be self-sustaining in steamusage during normal operation. These proven, innovative designs helpto set our technology apart from the rest.

GLOBAL REACHOur sulfur technology is currently operating all over the world, includ-

ing North America, South America, Europe, and Asia. Recently, weperformed basic engineering of sulfur recovery units for four refineries inSouth America and one in the Middle East, each with an MDEA aminetail gas treating unit followed by tail gas incineration.

The sulfur recovery technology compliments Foster Wheeler’s heavyoil conversion technologies including delayed coking, and full EPCcapabilities. We are also known in the chemicals, petrochemicals andpolymers market. From consultancy and small process unit revamps tolarge integrated grass root complexes, we deliver comprehensive solu-tions that meet your requirements.

We are truly a global engineering and construction contractor, and

power equipment supplier adding value with technically advancedservices, reliable facilities and equipment.

Reach your peak operating and environmental performance withFoster Wheeler’s Sulfur Recovery Technology! Foster Wheeler developssolutions to meet your Sulfur Recovery needs.

CONTACT INFORMATIONFoster Wheeler USA

10876 S River Front Parkway, Suite 250South Jordan, UT 84095

Phone: 801 382 6900

Fax: 801 382 6901Email: [email protected]

www.fwc.com

585 N. Dairy AshfordHouston, Texas 77079

Phone: (713) 929-5500

Fax: (713) 929-5170

Email: [email protected]

New Burner Showing Double Air Barrel

3 Catalytic Reactor Beds 200LTPD Sulfur Recovery Unit

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SHELL GLOBAL SOLUTIONS

PRESSURISING THE SHELL SULPHUR DEGASSERHow a small modification to enable pressurised degassing operationscan substantially cut emissions and enhance safety

KEES VAN DEN BRAND, Senior Process Engineer, Gas Treating & Sulphur Processes,Shell Global Solutions International BV

Shell Global Solutions has designed a small modification to its sul-phur recovery and degassing configuration that can unlock major cutsin sulphur emissions and also enhance safety. The inexpensive adjust-ment enables compliance with the stringent World Bank standards.

The conventional Shell sulphur degassing process, a well-estab-lished technology with more than 330 applications worldwide,removes hydrogen sulphide (H2S) and polysulphides (H2Sx ) from the

liquid sulphur produced in Claus sulphur recovery units and sendsthem to the incinerator. However, burning these sulphur compoundsincreases sulphur dioxide (SO2) emissions, so Shell Global Solutionshas investigated the possibility of recycling these gases to the frontend of the Claus unit.

In the past, Shell has evaluated reducing SO2 emissions by usinga compressed recycle towards the main burner with either a compres-sor or a steam- or air-driven ejector. These options have significantdrawbacks. A compressor is expensive, a steam-driven ejector coolsthe main flame too much, and an air-driven ejector results in poorturndown on the ai r side of the main burner.

The conventional Shell sulphur degasser operates at near atmo-spheric pressure (see FIG. 1). The sulphur rundown lines from the

Claus unit (which also operate at atmospheric pressure) drain bygravity flow into the degasser. Traditionally, this was a concretepit, but in recent years there has been a design shift away from

the use of pits in favour of vessels. This is a crucial developmentbecause having a vessel unlocks the possibility of recycling the ventgas from the degasser to the front end of the Claus unit at a slightlyelevated pressure.

As the vessel is leak tight, sweep air is not required to preventuncontrolled leakage. Furthermore, the vessel facilitates more robustsafeguarding and tracing solutions for corrosion prevention.

This approach also offers the additional flexibility of off-plot installa-tion. The conventional atmospheric configuration requires the degasserto be placed near the sulphur condensers to minimise the pressuredrop in the rundown. In contrast, with the new pressurised line-up,the degasser vessel can be installed in another part of the Claus plot,which can result in more ef ficient use of the available plot space.

The new configuration for pressurised sulphur degassing (seeFIG. 2) requires a small Roots-type blower to create a pressure ofabout 0.9 barg in order to recycle the vent gas to the Claus unit’sfront end, as well as an additional small collecting vessel.

Shell carefully evaluated the effect of higher pressures on degas-sing performance. The tests confirmed that degassing is more effec-tive at a slightly elevated pressure. More oxygen can dissolve in the

sulphur, which enhances the decomposition of H2Sx. Therefore, forthe same efficiency, the residence time could be decreased or smallerunits could be used.

LC

Stripping columnwith separation bafe

Sulphur rom Claus plantSulphur to storage

Sweep gas

To incineratorLow-pressure steam

Air

Stripping columnwith separation bafe

Air

FIG. 1. Simplified flow scheme of the atmospheric Shell sulphur degassing process.

SPONSORED CONTENT

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SHELL GLOBAL SOLUTIONS

DELIVERING VALUE

World Bank standards specify that no more than 150 mgSO2/Nm3 (about 53 ppmv SO2) must leave the incinerator (dry basis and nooxygen). This is typically equivalent to 35 ppmv of SO2 in the actualstack gas. These limits, or even tighter ones, are increasingly beingspecified on projects all around the world and setting major challengesfor operators.

The pressurised Shell sulphur degassing process offers a safe,robust and cheap solution for achieving the required reductionsin SO2 emissions. The main modifications required for pressurisedoperations are:

• replacing the below-ground concrete pit with a below- orabove-ground vessel, if appropriate;

• recycling the degasser vent to the front end of the Claus unit; and

• installing a simple compressor.These changes require only minor capital expenditure. The advan-

tages include:• reduced SO2 emissions;• enhanced safety; and• plot flexibility.Refineries, gas plants and upstream facilities can all benefit, either

in grassroots installations or retrofit situations, and Shell expects thepressurised degasser to become the default configuration in futureprojects that have highly stringent SO2 emission requirements.

CONTACT INFORMATION

www.shell.com/gasprocessing

[email protected]

FIG. 2. The pressurised Shell sulphur degassing process.

Bubble

column

To/from sulphurrecovery unit coalescer

Air

Liquid sulphurfrom sulphur

locks

Sulphurcollecting

vessel

Concrete pit

Bubble

column

Liquid sulphurto storage

Sulphur degassingvessel

Vent air to Clausmain burner gun

LC

PG

PC

PC

SPONSORED CONTENT

7/22/2019 gulfpub_hp_201210.pdf


EVENT

October 30–31, 2012 • Hyatt Regency Houston • Houston, Texas USA

H

O U S T O N

H

O U S T O N2 0 1 2 W O M E N ’ S

Register online at WGLNetwork.comThe Women’s Global Leadership Conference in Energy and Technology (WGLC) isone of the largest women’s events in the industry, and the only one that focuses ondiscussing key environmental, economic and professional development issues in oiland gas.

This year, Houston Mayor Annise Parker will deliver a welcome address the morning of

Oct. 30 to open day one of the conference. The 2012 WGLC keynote speakers are:

This year, conference content will focus on the global impact of recent technologicaladvances in exploration and production. Presentations will also cover IOC/NOC

relationships, work force trends, shale energy in North America, challenges facingyoung professionals, global upstream activity, and more.

Additional speakers include:

• Melody Meyer, President, Chevron Asia Pacific Operation Company

• Cindy Yeilding, VP, Gulf of Mexico Exploration, BP

• Alexandra Roberts-Judd, Upstream Projects Public andGovernment Affairs Manager, ExxonMobil

• Denise Hamsher, Director, Planning-Major Projects, Enbridge Incorporated

• Stephanie Sterling, VP Business and JV Management, Shell

• Cristina Pinho, General Manager, Operations and Maintenance, Petrobras

To download the full conference agenda, please visit WGLNetwork.com.

Participate in the 2012 Women’s Global Leadership Conference

in Energy & Technology

Inquiries: Contact Gwen Hood, Events Manager, at +1 (713) 520-4402or [email protected]

Registration Fees: Single attendee: $880; Team of two: $1,595;Small group of 5: $3,300; Leadership pack of 10: $6,325

Henrietta H. Fore

Chairman and CEO

Holsman International

Mark P. Mills

CEO

Digital Power Group

Signage Sponsor:

Platinum Sponsor:

Silver Sponsors:

Wine-Tasting Sponsor:

Gold Sponsor:

Bronze Sponsor:

Bronze/Conference

Bag Sponsor:

IPAA Scholarship Sponsor:

7/22/2019 gulfpub_hp_201210.pdf


Heat TransferS. AHAMAD and R. VALLAVANATT,

Bechtel Corp., Houston, Texas

Identify and control excess airfrom process heaters

Process heaters are the largest consumers of energy in mostplants. A refinery, on average, burns approximately 2 billionBtu/hr of fuel in fired heaters. The total quantity of fuel burned(heat released) is so high that any improvement will result in

significant fuel savings. Although there are many ways to im-prove heater performance, including better design, operationand maintenance, excess air is the No. 1 contributor to poorheater efficiency and must be addressed.

High energy costs and tighter emissions regulations requireincreased understanding and control of excess air. Any reduc-tion in excess air will raise the efficiency of a heater and reducetotal emissions. NO X emissions are of the highest concern in afired heater, although excess air control will also reduce refin-ery CO2 emissions and boost heater efficiency.

Fuel efficiency in a fired heater is a function of heater de-sign, maintenance and operating parameters. Heaters must bedesigned for optimum efficiency, and providing an adequateheat-transfer area at the design stage will ensure better efficien-cy. It is recommended that the flue gas temperature approach(defined as flue gas temperature leaving convection, minus pro-cess inlet temperature) be between 50°F and 100°F, dependingon heater tube material and the cost of fuel. However, heaterefficiency may decline with the degradation of heater compo-nents. The degree of degradation is dependent on the quality of the maintenance program implemented at the refinery.

Excess air is defined as the amount of air above the stoichio-metric air requirement that is needed to complete the combus-tion process. Excess oxygen (O2) is the amount of O2 in the

incoming air not used during combustion.In an operating plant, the airflow rate can be adjusted at afixed absorbed-heat duty (constant feed flowrate and inlet/out-let conditions) until an optimum fuel-to-air ratio is achieved. Itis important to note that there is a limit on minimum possibleexcess O2. Below this level, combustibles can enter the flue gas,

which poses a safety hazard. Heater and burner manufacturersestablish this minimum limit during the design stage. Opera-tors should also keep a safe margin for upset conditions.

A frequently asked question is, “W hy do operators oftenrun heaters with higher excess air?” The answer is that addi-tional excess air reduces flame temperature, shortens flamelength and decreases tube flame impingement, thereby mak-

ing it easier for workers to operate the heater without over-heating the tube.

Excess O2 can be measured in flue gases, which can be cor-related with excess air. FIG. 1 provides a correlation betweenexcess air and flue gas O2 for a ty pical natural gas. Also, the fol-lowing equation can be used to calculate the excess air based

on flue gas O2:

(1) EA92 O

2

21 – O2

where: EA = excess air, %O2 = vol% of flue gas oxygen (dry).Higher excess O2 helps achieve a stable flame in the firebox.

At the same time, it reduces the efficiency of the heater. As ageneral rule, 3% O2 in flue gas is equivalent to 15% excess air.

Flue gas quantity increases with a rise in excess air, whichlowers heat and increases the fuel requirement. FIG. 2 provides

0

1

2

3

4

5

6

7

8

0 2 4 6 8 1 0

F l u e g a s O 2 ,

% w

e t

Flue gas O2, % dry

O2—dry vs. wet

0

10

20

30

40

50

60

0 2 4 6 8 10

E x c e s s a i r , %

Flue gas O2, % dry

Excess air vs. O2

FIG. 1.Correlation between excess air and flue gas O2 for a typicalnatural gas.

7/22/2019 gulfpub_hp_201210.pdf


Heat Transfer

a correlation between flue gas generated during combustion,and excess air.

The following equation can be used to calculate approxi-mate flue gas quantity for natural gas:

q f = 1 + 0.167ϫ (100 + EA)

or (2)q f = 17.7 +

15.4 O2

21 – O2

where: EA = excess air, %O2 = vol% of flue gas oxygen (dry)q f = flue gas quantity in lb/lb of fuel.

As a general rule, flue gas quantity is approximately 20 timesthe fuel quantity at 15% excess air.

The net efficiency of a fired heater is equal to the total heatabsorbed, divided by the total heat input. The heat absorbed

is equal to the total heat input, minus the total losses. The netthermal heater efficiency can be calculated using the followingequation:

(3)=Toal hea inpu – (sack + seting) losses

Toal hea inpu100

= LHV H a H f H m – H s – H L

LHV H aH f H m100

where:η = Net thermal efficiency, % LHV = Lower heating value of the fuel, Btu/lb of fuelH a = Sensible heat of air, Btu/lb of fuel

H f = Sensible heat of fuel, Btu/lb of fuelH m = Sensible heat of atomizing media, Btu/lb of fuelH s = Stack heat losses, Btu/lb of fuelH L = Setting loss, Btu/lb of fuel.For all practical purposes, we can assume H a and H f to be

negligible. H m is applicable for fuel oil firing. Setting (casing)

heat losses are in the range of 1.5%–2.5%, depending on thecapacity, design and size of the heater. Given these assump-tions, there are two parameters for the estimation of efficiency:excess air/flue gas O2 and stack temperature.

FIG. 3 depicts a graph for the estimation of fired heater ef-ficiency, based on flue gas O2 and stack temperature for a typi-cal natural gas with a setting heat loss of 1.5%. For heat losseshigher than 1.5%, additional heat loss should be reduced fromthe calculated eff iciency.

For example, consider a heater operating at a stack tem-perature of 400°F, with 4% O2 (dry), and a 1.5% setting loss.Using the graph in FIG. 3, the efficiency can be estimated at89%. For the same heater with a higher setting loss of 2.5%,

the efficiency is 88%.Knowledge of efficiency loss will clarify economic incen-

tives to lower the stack temperature or the percentage of excessO2. As a general rule, every 35°F increase in flue gas tempera-ture reduces the heater efficiency by 1%.

Natural draft heaters use the draft (buoyancy) effect of hotflue gases to draw combustion air into the heater. The net draftavailable is the draft created by the stack effect, minus frictionaland velocity losses. The net draft should be sufficient to obtaina negative pressure along the heater flue gas path.

It is important to maintain a safe draft level in a fired heat-er to achieve the best possible efficiency and operation. The

60

65

70

75

85

80

90

95

2 4 6 8 10 12

E

f c i e n c y ,

%

Flue gas O2 , vol% (dry)

Flue gas O2 vs. efciency

300

400

500

600

700

800

900

1,000

Flue gas stacktemperature, °F

FIG. 3. Estimation of fired heater efficiency.

16

18

20

22

24

26

28

0 10 20 30 40 50 60

l b o fl u e g a s

p e r l b o u e l

Excess air

Flue gas quantity

FIG. 2. Correlation between flue gas generated during combustion,and excess air.

7/22/2019 gulfpub_hp_201210.pdf


Heat Transfer

target draft of 0.1 inchWC is set at the heater arch. A higher value of draft will result in ingress of “tramp air” into the heater.Tramp air takes heat from the combustion process and exitsthe stack, reducing heater efficiency. The flue gas sample takenfrom the stack does not represent the actual volume of O2 avail-able for combustion. It is the sum of unused O2 from the fire-

box (actual excess O2 ) and O2 from tramp air. A positive draft value will result in the leakage of hot fluegases through openings in the heater. This is a hazardous op-eration that can overheat the steel structure, refractory andheater supports, and, consequently, shorten heater life.

FIG. 4 provides the value of draft generated in the heater forflue gas temperature and ambient air temperature. It should

be noted that stack effect decreases with an increase in site al-titude. The calculated draft should be amended using the cor-rection factor for site altitude. The following equation can beused to calculate the draft generated in a heater:

(4)Draft = 0.52 H P

atm

1

T amb

–1

T fg

where:H = Height, ft

Patm = Atmospheric pressure, psiaT amb = Ambient air temperature, °R T fg = Flue gas temperature, °R.

As a general rule, for every 10 ft of f irebox height, the draftincreases by 0.1 inchWC:

Draft at burner (inchWC) ≈ 0.1 + H fb ÷ 100 (5)

where:H fb = Firebox height, ft.

As an example, for a 50-ft-tall firebox, the draft at burner is0.6 inchWC (0.1 inchWC at arch, plus 0.5 inchWC as a stack effect). Generally, the stack effect decreases with an increasein site elevation. For example, a taller stack will be needed for aheater operating in Wyoming (altitude ~ 5,000 ft) than for oneoperating along the Texas Gulf Coast (altitude ~ 0 ft).

The typical combustion air preheater (APH) will in-crease the heater efficiency by approximately 10%. Fuel gasgenerally contains H2S or sulfur, which convert into SO2 andthen into SO3. The APH’s heat-transfer surface is subject tocold-end corrosion caused by condensation of sulfur trioxide(SO3 ), which results in APH leakage. Air preheater leakage is

one of the most common APH operating problems, and any such leakage results in a reduction in the overall efficiency of the heater.

In APH operation, the flue gas is generally at negative pres-sure, and the air is at positive pressure. Therefore, leakage oc-curs from air to the flue gas side. This reduces the quantity of air available for combustion, and it increases the quantity of flue gas leaving the APH.

This leakage can be detected by measuring the flue gas O 2 content at the APH inlet and outlet. Any leakage will result inhigher flue gas O2 at the APH exit, compared to the APH inlet.Generally, the APH is not equipped with a flue gas O2 analyzerat the inlet and the outlet; however, the inclusion of 2-in. con-

nections at the APH’s inlet and outlet will enable operators tomeasure O2 levels using a portable analyzer.

Another method of measuring leakage involves heat bal-ance. The flue gas/air heat balance across the APH can be de-scribed as follows:

(m ϫ Cp ∆T ) flue gas = (m ϫ Cp ∆T )air (6)

For a typical fuel gas at 15% excess air:

m flue gas ≈ 1.05ϫ mair Cp flue gas ≈ 1.15ϫ Cpair (7)

∆T air ≈ 1.2ϫ ∆T flue gas

where:m = FlowrateCp = Specific heat∆T = Temperature difference across the APH.

Any leakage in the APH will reduce the ratio of ∆T air to ∆T flue

gas . For example, for a 10% leakage in the APH, the ratio of tem-perature difference will be around 1.1.

FIG. 5 indicates the percentage of air leakage based on theratio of ∆T air to ∆T flue gas for a typical natural gas firing.

Air leakage through openings. A fired heater is not a 100%sealed unit; there are always openings through which air in-gress (tramp air) can move. The volume of tramp air dependson the opening size and the draft at the location of the opening.

After the draft at the opening location is estimated, the fol-lowing equation can be used to estimate the air leakage throughan opening:

∆P = C ϫ 0.003ϫ ρϫ v 2 (8)

0.70

0.75

0.80

0.85

0.90

0.95

1.00

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000

F a c t o r

Altitude, ft

Altitude correction actor

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

200 700 1,200 1,700 2,200

D r a

f t p e r 1 0 0 f t , i n c h W C

Flue gas temperature, °F

Stack efect (drat)

60708090100

110120130

Ambient airtemperature, °F

FIG. 4. Value of draft generated in the heater for flue gas and ambientair temperatures.

7/22/2019 gulfpub_hp_201210.pdf


Heat Transfer

This equation can be simplified for the leakage calculationpurpose based on the following data:

• Molecular weight (MW) of air = 28.96• Atmospheric pressure (psia) = 14.7• Velocity head (C) = taken as 1

The simplified equation reads:

(9)ql=115 ∆P

T where:

ΔP = Draft at opening location, inchWCρ = Density of air at ambient temperature, lb/ft3

v = Velocity of air through opening, ft/sC = Velocity headql = Air leakage, lb per ft2/sT = Ambient air temperature, °R.FIG. 6 provides the quantity of air leakage per ft2 of opening

size. This figure is based on an ambient air temperature of 60°F.Once the opening size is known, the amount of air leakage can

be estimated. The estimated air can be translated into the ad-ditional firing rate required.

Fuel savings. A commonly asked question in heater discus-sions is, “How much fuel can be saved if excess air is opti-mized?” The efficiency chart in FIG. 3, which shows operatingO2 and target O2 , helps calculate the savings.

However, there is a drawback. The absorbed heat duty of thefired heater is constant. Any increase in the O2 level will reducethe efficiency, resulting in a higher firing rate. This increase inthe firing rate will lead to a rise in stack temperature, which re-sults in another reduction in eff iciency. This reduction, in turn,demands a further increase in the firing rate.

For example, a 100-MM-Btu/hr fired heater is designed foroperating at a stack temperature of 600°F, with 84% efficiency at 3% O2. The operating efficiency at 6% O2 is around 80%(and not 82%, as shown in the efficiency chart).

The method of efficiency calculation for off-design operat-ing conditions presented in API-560 Appendix G can be used

to estimate the stack temperature when excess air is present.This method can be simplified for excess air as follows:

(10)

T S2T f 2 (T S1 T f 1)

100 EA2

100 EA1

n

n180

T S1 T f 1

0.35

where:T s = Flue gas stack temperature, °R

EA = Excess air, %T f = Feed inlet temperature, °R (T f1 = T f2)Φ = Excess air correction factor (subscripts 1 and 2 refer to

design and operating conditions, respectively).Once the new flue gas stack temperature at excess air is

known, then the heater efficiency can be estimated. FIG. 7

shows the estimated fuel savings for a reduction in the O2 levelto 3%. This graph is based on a fuel price of $6/MMBtu. Thedesign flue gas temperature lines indicate the baseline stack temperature (i.e., the flue gas stack temperature at 3% O2).

CO2 emissions reduction. The volume of CO2 emissionsgenerated in a fired heater is directly proportional to the fir ingrate. In combustion processes, fuel carbon converts into CO2.Therefore, excess air reduction will lower CO2 emissions.

0

5

10

15

20

25

30

35

40

0.6 0.7 0.8 0.9 1.0 1.1 1.2

A P H a i r l e a k a g e ,

%

ΔT air/ΔT flue gas

APH leakage

FIG. 5. Percentage of air leakage for a typical natural gas firing.

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

0.0 0.2 0.4 0.6 0.8 1.0

A i r l e a k a g e p e r f t 2

o f o p

e n i n g ,

l b / h r

Draft, inchWC

Air leakage

FIG. 6. Quantity of air leakage per ft2 of opening size.

7/22/2019 gulfpub_hp_201210.pdf


Heat Transfer

FIG. 8 provides estimated decreases in CO2 emissions througha reduction in the O2 level to 3%. The basis for this graph is thesame as that in FIG. 7.

Recommendations. Heater excess air control starts at the de-sign stage. Well-designed heaters have low tramp air. There are

three stages of excess air control:1. Design stage2. Maintenance3. Control.The following methods can be used to reduce excess air and

tramp air in the heater.Design stage. A heater has many potential leak points for

air ingress:• Clearance around the bottom coil guide (spigots)• Sight doors and peepholes• Header boxes, manholes and other openings for viewing

and access• Modules and duct splice joints• Terminals and crossover tubes• Weld joints on the heater casing• Soot-blower sleeves• The APH.These leak points must be designed for the lowest possible

leakage. Suggestions for designing a low-leakage heater includethe following:

• Seal the clearance space around the bottom tube guides by using a floor sleeve with an end cap, or seal boots

• Use sight doors, with safety glass, that are equipped withan interlock cover or flapper

• Use a self-closing peephole cover in the heater floor• Ensure that header box panels and other openings are air-

tight, and use gaskets between the gaps• Seal-weld all splice joints between modules from the

inside, or use high-temperature sealant; also, use closer-boltspacing (6 in. from center to center)

• Seal all terminals and crossover openings with flexible seals• Ensure that all header box drain points are plugged• Ensure that no leakage is occurring through instrument

mountings•

Limit leakage through the APH during the design stage,and perform an air-leakage test in the shop. Maintenance. Routine maintenance of the heaters is es-

sential, since corrosive agents can be present in flue gases. De-terioration from sulfur oxides occurs mostly on cold sectionsof the steel casing. Climate conditions can also lead to rustingon exposed surfaces of the heater casing. Suggested inspectionand maintenance methods include the following:

• Check for heater casing corrosion; if any leaks are discov-ered, they should be sealed to stop air ingress

• Ensure that observation doors (generally located in the bottom section of the radiant box) are closed after techniciansinspect the heater flame

• Check peepholes, access doors, etc., for proper closing• Check flue gas O2 content in the convection section and

on the APH; if there is any increase in O 2 content across theflue gas path, it indicates leakage

• Use a smoke test during heater shutdown to detect leakage• Use infrared scanning, while the heater is in operation, to

pinpoint locations with air leakage; these will have localized,lower heater casing temperatures

• To reduce leakage in burners, keep all burners in opera-tion, even during lower operating loads; and close the air regis-ter when a burner is taken out of service.

0

500,000

1,000,000

1,500,000

2,000,000

2 4 6 8 10 12

A n n u a l f u e l s a v i n g , U

S d o l l a r s

Flue gas O2, vol% (dry)

Fuel savings

400600

800

Design flue gastemperature, °F

Basis:đƫ!/%#*ƫý1%ƫ%*(!0

temperature = 300 °F

đƫ1!(ƫ,.%!ƫœƫĸćĥ01đƫ/+.!ƫ$!0ƫ105ƫœƫāĀĀƫ 01ĥ$.

FIG. 7. Estimated fuel savings for a reduction in the O2 level to 3%.

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2 4 6 8 10 12

A n n u a l

C O 2 r e d u c t i o n ,

M M l b

Flue gas O2, vol% (dry)

CO2 reduction

400

600

800

Design flue gastemperature, °F

Basis:đƫ!/%#*ƫý1%ƫ%*(!0

temperature = 300 °Fđƫ1!(ƫ,.%!ƫœƫĸćĥ01đƫ/+.!ƫ$!0ƫ105ƫœƫāĀĀƫ 01ĥ$.

FIG. 8. Estimated decreases in CO2 emissions through a reductionin the O2 level to 3%.

7/22/2019 gulfpub_hp_201210.pdf


Heat Transfer

Excess air control. Knowing the target flue gas O2 contentis the first step in excess air control. Each heater is unique in itsdesign. The O2 level required to achieve ideal combustion may

be anywhere from 1%–4% or higher, depending on the designand operating characteristics of the heater.

The following two instruments are necessary to control

excess air:• Flue gas O2 analyzer. This is the most important instru-

ment on the heater. It is recommended to install an O2 analyzerat the radiant section arch.

• Draft gauge. A draft gauge should be installed at theheater arch. The arch is the point of the highest flue gas pres-sure in the heater.

Heater O2 and draft at the radiant arch should be checkedand, if necessary, adjusted at least once per shift and wheneverthere is a change in process load. All operators should be fa-miliar with the heater controls. Often, heaters with air registersand stack dampers become jammed simply because they arenot used. FIG. 9 provides tactics for controlling excess air in a

natural draft heater. For controlling excess air in other types of heaters, TABLE 1 and TABLE 2 can be used alongside FIG. 7.

Automatic control. The basics of automatic heater control aresimilar to those described in the manual control method. In auto-matic control, reliable instrumentation is key. One reason for thesmall number of heaters with automatic control is a lack of confi-dence in reliable instrumentation. Also, artificial intelligence can

be built into the control system to account for all operating cases. A remote manual control for both O2 and draft is best suited

for the natural draft heater. A fully automated control can be safe-ly implemented on balanced draft heaters. Optimum heater per-formance can be achieved by controlling O2 and combustibles influe gas using an O2/CO analyzer and automatic dampers.

Case Study 1. In this case study, a vertical, cylindrical, naturaldraft heater with an absorbed heat duty of 100 MMBtu/hr in-cluded the following design parameters:

• Flue gas stack temperature: 600°F• Fluid inlet temperature: 300°F• Design excess air: 15%•

Design heat loss: 2%• Firebox height: 55 ft• Number of radiant tubes: 64• Flue gas O2 content at operating conditions: 6 vol% (dry)• Efficiency of heater at design conditions: 84.2% at 1.5%

heat loss (see FIG. 3)• Efficiency at 2% heat loss: 83.7%• Firing rate: 100/0.837 = 119.5 MMBtu/hr• Fuel gas flowrate: 5,770 lb/hr (using a fuel gas LHV of

20,700 Btu/lb)• Flue gas flowrate: 5,770 ϫ [1 + 0.167 ϫ (100 + 15)] =

116,582 lb/hr• Air flowrate (flue gas flowrate − fuel flowrate): 116,582 −

5,770 = 110,812 lb/hr.The heater operated under the following conditions:• Flue gas O2: 6 vol% (dry)• Excess air: (92ϫ 6)/(21 – 6) = 36.8% (also see FIG. 1)• Efficiency at higher excess air, design stack temperature

of 600°F and 2% heat loss = 81.3%; however, the revised ef-ficiency must be calculated based on operating stack tempera-ture, and if this measurement is not available, then the revisedstack temperature can be estimated as follows:

(11)

T S2 T f 2 (T S1 T f 1)

n180

600 300^ `

0.35

0.836

100 36.8

100 15

0.836

1.156

T S2 300 1.156 (600 300) 647qF

• Efficiency at revised stack temperature and operating fluegas excess air: 80.5% (from FIG. 3)

• Corrected efficiency for 2% heat loss: 80%• Operating firing rate: 100 ÷ 0.8 = 125 MMBtu/hr• Fuel savings potential: (125 – 119 .5) ϫ 24 ϫ 365 =

48,180 MMBtu/yr; at a fuel price of $6/MMBtu/hr, the an-nual fuel savings potential = $289,000 (this can also be esti-

mated using FIG. 7).

Case Study 2. In this case study, the heater experienced leak-age through the bottom guide and an open peephole. The coilguide and sleeve size were 2-in. Nominal Pipe Size (NPS)Schedule 80 and 3-in. NPS Schedule 80, respectively. The heat-er was not provided with a cap on the sleeve. The open area be-tween the sleeve and the guide included an inside cross-sectionof 3-in. NPS sleeve and an outside cross-section of 2-in. NPSguide (equal to 2.96 in.2). Other design parameters included:

• Number of guides: 32 (one guide for two radiant tubes)• Total opening area at guides: 32ϫ 2.96 ÷ 144 = 0.66 ft2

• Size of radiant section observation door: 5 in.ϫ 9 in.

• Opening area of observation door: 45 in.2 (0.31 ft2)• Total open area: 0.97 ft2

O2Draft

Close stackdamper

Open stackdamper

Close airregisters

Open airregisters

Start FinishOK

High

OK

Low

High

Low

FIG. 9. Tactics for controlling excess air in a natural draft heater.

TABLE 1 . Methods for controlling excess air

O2 level Natural/induced draft Forced/balanced draft

High Close burner air register Close fan/duct air damper

Low Open burner air register Open fan/duct air damper

TABLE 2. Methods for controlling draft

Draft level Natural/forced draft Induced/balanced draft

High Close stack damper Close induced-draft fan damper

Low Open stack damper Open induced-draft fan damper

7/22/2019 gulfpub_hp_201210.pdf


Heat Transfer

• Firebox height: 55 ft• Draft at opening (draft at heater floor): 0.1 + 55 ÷ 100 =

0.65 inchWC• Ambient air temperature: 60°F• Air leakage per ft2 of opening:

115 0.65

(460 + 60) = 4.07 lb/s/f

2

• Total air leakage: 4.07 ϫ 0.97 ϫ 3,600 = 14,212 lb/hr(this can also be estimated using FIG. 6)

• Excess air for the burner: 15%• Actual excess air, including leakage, can be calculated as

follows:

(Air leakage + air required)

Air required(100 EA) 100

(14,212 110,182)

110,182(10015) 100 29.8%

Based on revised excess air, a fuel savings can be calculatedas in Case Study 1:

• Calculated efficiency: 81.1%• Loss in efficiency due to air leakage: 83.7 − 81.1 = 2.5%• Annual fuel savings potential = $201,320.

Recommendations. Controlling excess air has many ben-efits, and opportunities exist to save fuel regardless of whether

the heater is old or new. Day-to-day monitoring significantly improves heater operation. The first visible benefit of excessair reduction is a decrease in fuel consumption. Reduction of emissions, including CO2 , is another benefit.

The heater must be provided with at least two instruments(an O2 analyzer and a draft gauge at the arch), both of which

are important for energy improvement. Additionally, propertraining should be provided for heater operators, and a simpleand straightforward heater tuning program must be imple-mented. It is unlikely that an operator will voluntarily adjustthe heater unless a plan is in place to do so.

SULTAN AHAMAD is a fired-heater equipment engineer at

Bechtel Corp. in Houston, Texas. He has more than 14 years of

experience in the design, engineering and troubleshooting of

fired heaters and combustion systems for the refining and

petrochemical industries. He graduated from the Indian Institute

of Technology in Roorkee, India, with a degree in chemical

engineering. He worked for eight years at Engineers India Ltd. in

New Delhi, India, and for five years at Furnace Improvements in Sugar Land, Texas.

RIMON VALLAVANATT is the senior principal engineer atBechtel Corp. in Houston, Texas. He has more than 37 years of

experience in the design, engineering and troubleshooting of

fired heaters, thermal oxidizers, boilers and flares. He

graduated from the University of Kerala in India with a degree

in mechanical engineering. He also received a degree in

industrial engineering from St. Mary’s University in San

Antonio, Texas. Mr. Vallavanatt is a registered professional engineer in the state

of Texas, and he has served on the American Petroleum Institute’s subcommittee

on heat transfer equipment for the past 27 years.

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Channelview, TX 832.452.2800

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7/22/2019 gulfpub_hp_201210.pdf


Rotating Equipment

K. BIHLER, Bihlertech, Inc. Chicago, Illinois;

D. DOMINIAK, Automate the World, Inc.,

Chicago, Illinois; B. KEITH, Toshiba International

Corp., Houston, Texas; and J. JOHNSON,

Hydro Inc., Chicago, Illinois

Apply new pump-drive software to test performance

Process control schemes involving fluid-flow machinery with traditional adjustable speed drives (ASDs) or modulesencounter limitations such as control flexibility and accuracy.

In this context, the traditional approach implies that propor-tional integral derivative (PID) methods can be used and thatthese methods can directly control frequency. However, ap-plying PID and directly controlling frequency on centrifugalpump drives restricts flowrates and pressures along a non-linear pump-performance curve. The widely known pump-performance curve shapes are determined by a particularmachine’s impeller design or fabrication details. With respectto controlling flowrate and/or pump discharge pressure, ASDmodules using traditional PID methods suffer from trying toapply a linear equation to solve a nonlinear problem.

In contrast, a newly developed pump performance algo-rithm (PPA) can indirectly solve for power in Eq. 1 of thePump Affinity Laws. As shown in FIG. 1, a PPA was developedfor modern centrifugal pump applications and test-stand du-ties where superior control is needed. The superior control isachieved when an algorithm “linearizes” a pump curve; it of-fers expanded new ASD-related control options and improvedenergy efficiency as compared to conventional PID methods.Extensive testing corroborated the developments, and testingresults will be described in this article.

Pump laws and equations. Consider the Pump Affinity Laws (Eq. 1), where the diameter of the impeller is held con-stant and:

Q = Flow P = PowerH = Pressure N = Impeller speed

Flow Pressure Power

(1)Q 1

Q 2

N 1

N 2

H

1

H 2

N 1

N 2

2

P1

P2

N 1

N 2

3

Note: The basic principle behind PPA modules and softwareused in these devices solve for power, P and indirectly solve forspeed, N .

COMPARING OLD VS. NEW CONTROL METHODS

Common PID software used in an ASD provides an estimat-ed speed to achieve a desired or targeted head vs. flow setpoint.

However, when the target speed is reached using this method,an exact answer is not available and the desired setpoint may have been missed. The correct answer lies on an unknown and

nonlinear pump performance curve. PID software must now guess the speed and, hopefully, decrease the error. This processcontinues until a reasonable closeness to (or deviation from)setpoint is reached. If any event or process variable causes thesystem curve to change, the whole control process must be re-attempted. The process of searching for the correct speed willconsume driver energy, even on a single machine.

Multiple machines. On a fluid-flow system or fluid-process-ing unit with multiple machines operating either in series orin parallel, a second and more serious problem—balancing theload—presents itself. Even if the machines in a multi-machineflow loop or fluid-moving unit are built to the same specifica-tions, there will be differences in motor performance, impellerclearances, internal wear, surface roughness, and perhaps otherparameters. Some or all of these conditions can affect the re-lationship (or constancy and accuracy) of pump speed and itsassociated head vs. flow performance.

Using conventional frequency control, multiple fluid-flow devices (pumps) are operated at the same speed when runningtogether. For the reasons listed above, this will inevitably pro-

FIG. 1. Modern pump test stand with ASD drive modules (cabinets)

on the right side of the picture. Photo courtesy of Hydro Inc., Chicago,Illinois, and Toshiba International Corp., Houston, Texas.

7/22/2019 gulfpub_hp_201210.pdf


Rotating Equipment

duce different flows and pressures from each machine. Result:

While in parallel operation, one pump will (usually) producemost of the output and require a correspondingly higher elec-tric current flow or amperage. Meanwhile, the other pump orpumps will demand a lesser, but still high-power draw whileadding very little to the total fluid-flow output. Using conven-

tional control approaches, it will not be possible to balance aload using frequency directly. Again, this inability exists be-cause even the smallest of physical differences will cause a shiftin proportional power demand to the fluid device with thehighest pressure-to-flow ratio.

TEST OVERVIEW AND PPA DEMONSTRATION

As part of the development work, the deficiencies of simplespeed control algorithms were addressed; the difference be-tween traditional ASDs and new PPAs had to be quantified.Extensive testing at a state-of-the-art facility (FIG. 1) werescheduled and conducted.1 The results were analyzed andformally reported. It was ascertained that the testing facility

was designed in compliance with the Hydraulic Institute and API-610 standards. Instrumentation included a modern data-collection system with electronic flowmeters, torque metersand remote valve controls. Modern PPA drives were used in

the testing and two pumps were operated in parallel and seriesconfigurations. The various testing sequences involved bothstandard ASD control and also the new PPA.

During a straightforward test with a single pump, many of the different capabilities of PPA software were demonstrated.This software maintained constant system pressure as pumps

were added or shut down to modulate flow, or, as was done inFIG. 2, by modifying the flow through a single pump by par-tially closing a discharge valve and purposefully altering thepump speed. Likewise and by holding a particular PPA num-

ber, the specifically developed software maintained constantpower usage. Power usage corresponds to the PPA number by altering the frequency in response to ex-ternally imposed flow changes.

The advanced PPA software balanced loads andeliminated the process of searching for a setpoint.The PPA starts with a fixed PPA number. If the out-put electrical current is less than the PPA number,then the frequency is increased. Otherwise, if the

output current is greater than the PPA number, thenthe frequency is decreased. The frequency (in Hz)is directly proportional to driver rpm ( N in Eq. 1)and is adjusted to meet the driver’s electric current(amperage, or amp) draw. On centrifugal processpumps, amp draw is linear to both pressure and flow,

and nonlinear to N . This then differs from the PPA algorithm, which controls power directly to meet pressure, flow or a cho-sen pressure vs. f low intersection.

SETTING UP PPA

The PPA number is a percentage of the total amperageavailable from a specific ASD. When a motor/pump is first setup in the PPA wizard, the user is instructed to enter the motorfull-load amps into the drive. The ASD temporarily sets the“PPA Max” variable to the entered motor amps divided by the

ASD available output amps. The operator can then adjust the“PPA Max” number to achieve the maximum desired setpointfor flow, pressure, etc. Once this is done, the operator will setthe “PPA Min” variable to find the lower limit, or motor stallpoint. At this time, the ASD has stored the limits within whichthe pump is allowed to operate. On multiple pump systems,this is repeated so each machine has the same operational set-points. The PPA numbers, which also affect the correspondingamperage draw and frequencies at any given operating point,

will differ among pumps. Mechanical differences in piping,impeller wear, or trim and motor efficiency are responsible forthe differences in PPA numbers.

Virtual pump curves. Next, a virtual linear pump curve iscreated in software; it describes a power percentage that will

be compared to the other pumps. The PPA makes it possibleto compare power draws and make speed adjustments until allpower draws match each other.

If controlled from a common external analog signal, a PPA Min of 0% will cause all the pumps to operate at the PPA Minsetpoint. The same is true at 100%, where all pumps will berunning at their individual PPA Max setpoints. What is im-

portant is that, for each change in setpoint, the resulting flow or pressure will be linear, whereas the frequencies and amp

-400

8 8 4

1 7 6 7

2 6 5 0

3 5 3 3

4 4 1 6

5 2 9 9

6 1 8 2

7 0 6 5

7 9 4 8

8 8 3 1

9 7 1 4

1 0 5 9 7

1 1 4 8 0

1 2 3 6 3

1 3 2 4 6

1 4 1 2 9

1 5 0 1 2

1 5 8 9 5

1 6 7 7 8

1 7 6 6 1

1 8 5 4 4

1 9 4 2 7

2 0 3 1 0

2 1 1 9 3

2 2 0 7 6

2 2 9 5 9

2 3 8 4 2

2 4 7 2 5

2 5 6 0 8

2 6 4 9 1

2 7 3 7 4

2 8 2 5 7

2 9 1 4 0

-200

0

200

P r e s s u r e ,

p s i

F l o w ,

g p m

400

600

800

1,000

1,200

1,400

1,600

1,800

Total, flowSystem, psi

FIG. 2. Testing verified that PPA software is capable of maintaining

constant pressure even if wide flow variations occur. Source: Hydro,Inc., Chicago, Illinois.

Each pump is tuned during

commissioning to produce a specific

result, such as a flowrate or pressure.

Each motor/pump combination is unique

and requires slightly different frequencies

and power requirements.

7/22/2019 gulfpub_hp_201210.pdf


Rotating Equipment

draws will be nonlinear. Whenever the input frequency to asingle machine is changed in a standard ASD, the output isnonlinear, and energy is wasted searching to find the speedneeded to satisfy the control loop. Because PPA produces a virtual linear performance curve, even the first calculationfrom an external PID controller will likely be the correct and

most precise calculation.The PPA software apportions power to the motor to pro-duce the desired pressure or flow. No time or energy is wastedaccelerating and decelerating past the needed frequency. Whenthe internal PPA process hold loop is used with an externalfeedback signal from a pressure transducer or flowmeter, thecontrol loop process is greatly enhanced because there is nocommunication lag, and the variables can be tested and satis-fied at CPU clock speed.

Calculating pump speed. Another relevant characteristic of PPA is that, for each ASD actually operating, the software cancalculate at what speed to run to hold the PPA number inde-

pendently. This would be impossible for separate drives run-ning speed-control PID because each drive would be fightingthe other while hunting errors until the whole system becameunbalanced. Because PPA software provides a virtual and lin-ear line of performance, each ASD can simply select an individual point that represents exactly the same flow-pressureintersect as every other ASD. This means that the total con-trol system is greatly simplified. Therefore, an external PLC orDCS system needs only to tell each PPA-equipped ASD whento run and what setpoint to hold, and to provide the feedback reference signal. The important duty of calculating the spe-cific power requirements to maintain a setpoint is distributedacross all of the individual machines that are online.

In this scenario, each PPA-equipped ASD that is online, whether the driver is operating or not, is continuously calculat-ing what power it needs to maintain the desired setpoint basedon its initial stored setup values. When called, the next drive will ramp up and recalculate the feedback to find its point onthe performance line. At the same time, the lead pump will be backing down because the additional flow will be changing itsreference signal. Eventually, all pumps will reach the needed fre-quency to meet the virtual pump performance setpoint, whilethe PPA software runs in the background to find the requiredpower. This process occurs very quickly because each estimatefinds a known performance point. It generally happens faster

than the mechanical force variations can cause any pressure orflow changes. This leads to the most important function of PPA software: balancing the load between multiple pumps.

Tuning. Each pump is tuned during commissioning to pro-duce a specific result, such as a flowrate or pressure at bothPPA Min and PPA Max. Each motor/pump combination isunique and requires slightly different frequencies and powerrequirements at both end points and at every point in between. As a percentage, they are all the same. Since all PPA-equipped ASDs share the same common reference signal, they can eachindependently calculate the power needed to match the flow-pressure intersect of all of the pumps online. In a series opera-

tion, this effect is even more pronounced. If series pumps arerun at the same speed, then they have different fluid velocities.

This is analogous to a traffic jam on an expressway where thecars are stopping and starting. Using PPA, the “cars” are allmoving at exactly the same velocity. Without PPA, differencesin velocities between pumps can result in overpressure wavesthat amplify and resonate. This causes mechanical stress, which, in turn, consumes more power.

With PPA, the frequency can range to satisfy changes inthe system curve. An example of this may be found in a com-mon lift station connected to a force main that is shared by other pumping stations. In this case, a transducer would provide feedback to keep the wet well at a constant level. As theflowrate changes, PPA would increase and decrease powerto achieve this, just as a standard ASD would range the fre-quency. In contrast, the different PPA machines solve for P of the Power Affinity Laws simultaneously. At a given power set-ting on a pump with an increasing power curve, PPA increasesthe frequency to maintain the specified power when the forcemain pressure increases as other stations come online. Whenrunning in PPA “process hold mode,” the PPA software will do

it independently, and, each time the feedback changes the PPA output number. The result is that, unlike with a simple speed-control system, the PPA software corrects the frequency basedon power before any change comes from the feedback loop.This has a two-fold advantage: more accurate process controland, consequently, less power used by the pump.

-20

0

20

40

60

80

100

120

140

H e r t z

-20

0

20

40

60

80

100

120

140

P o w e r , k W

1 0 : 5 6 : 5 4

1 0 : 5 6 : 5 4

1 0 : 5 7 : 2 1

1 0 : 5 7 : 4 7

1 0 : 5 8 : 1 3

1 0 : 5 8 : 3 9

1 0 : 5 9 : 0 6

1 0 : 5 9 : 3 2

1 0 : 5 9 : 5 8

1 1 : 0 0 : 2 4

1 1 : 0 0 : 5 1

1 1 : 0 1 : 1 7

1 1 : 0 1 : 4 3

1 1 : 0 2 : 0 9

1 1 : 0 2 : 3 6

1 1 : 0 3 : 0 2

1 1 : 0 3 : 2 8

1 1 : 0 3 : 5 5

1 1 : 0 4 : 2 1

1 1 : 0 4 : 4 7

1 1 : 0 5 : 1 3

1 1 : 0 5 : 4 0

1 1 : 0 6 : 0 6

1 0 : 5 7 : 1 9

1 0 : 5 7 : 4 3

1 0 : 5 8 : 0 7

1 0 : 5 8 : 3 1

1 0 : 5 8 : 5 6

1 0 : 5 9 : 2 0

1 0 : 5 9 : 4 4

1 0 : 0 0 : 0 8

1 0 : 0 0 : 3 3

1 0 : 0 0 : 5 7

1 0 : 0 1 : 2 1

1 0 : 0 1 : 4 5

1 0 : 0 2 : 0 9

1 0 : 0 2 : 3 4

1 0 : 0 2 : 5 8

1 0 : 0 3 : 2 2

1 0 : 0 3 : 4 6

1 0 : 0 4 : 1 1

1 0 : 0 4 : 3 5

1 0 : 0 4 : 5 9

1 0 : 0 5 : 2 3

1 0 : 0 5 : 4 8

P r e s s u r e ,

p s i

Pressure, psiHzHz

kWkWTotal

FIG. 3. Two pumps (on common headers), using PID. Their respectivespeeds lag. Also, maintaining the setpoint pressure (95 psi) is difficult.

7/22/2019 gulfpub_hp_201210.pdf


Rotating Equipment

MORE ABOUT THE TESTS

Among the tests conducted was Test A, also known as thePID lead-pump test. It involved settings and findings summa-rized as:

• 95 psi setpoint (blue pump)• Speed follower lag pump (red pump)

• Average kW usage from 10:59:32 to 11:05:49 = 70.88. As shown in FIG. 3, this test shows the traditional methodof using two pumps on a common header. A PID algorithm

with feedback is used on the first pump. (Note: PID cannot beused on more than one pump in a system.) The second pumpis set to follow the speed reference from the lead machine. Theresponse lag from FIG. 3 is attributable to the acceleration time.

With traditional PID, significant energy is wasted in the un- balanced systems. Although operating in parallel, one pump will take over and produce the majority of the flow when allpumps are running at the same speed. This occurs whetheron an ASD or across the line. All of the other pumps will draw a considerable amount of power, but will contribute little to

the total flow. By contrast, in a PPA system, each machine willprecisely produce its portion of the flow and use the sameamount of energy. With PPA, all of the pumps in the system

become one “v irtual” machine.

Test B involved settings and findings labeled IndependentPPA operation:

• 95 psi setpoint• Average kW usage from 11:57:30 to 12:11:19 = 65.93.

As shown in FIG. 4, this test, i.e., Test B, uses the same set-points as Test A, but places both drives in independent PPA

process hold modes. Of note is the smoothness in pressure andflow, and that the drives do not get out of synchronism andfight each other, as shown in the earlier Test A.

One additional point of interest is that, in Test A, the PIDloop was tuned by a professional application engineer. By con-trast, in Test B, the drives, as shown in FIG. 4, were simply oper-ated through the PPA setup wizard, and no tuning was done.Instead, all the values were the drive defaults.

From FIG. 4 and comparing it to Test A (FIG. 3), it is clearly demonstrated how PPAs can save energy. Precise control of theprocess and balancing of the load reduces energy demand thatis otherwise converted into heat and mechanical stress.

Pressure, psiHzHz

kWkWTotal

-20

0

20

40

60

80

100

120

140

H e r t z

P r e s s u r e , p s i

1 1 : 2 9 : 5 1

-20

0

20

40

60

80

100

120

140

1 1 : 2 9 : 5 1

1 1 : 3 1 : 5 2

1 1 : 3 3 : 5 3

1 1 : 3 5 : 5 4

1 1 : 3 7 : 5 5

1 1 : 3 9 : 5 6

1 1 : 4 1 : 5 7

1 1 : 4 3 : 5 8

1 1 : 4 5 : 2 9

1 1 : 4 8 : 0 0

1 1 : 5 0 : 0 1

1 1 : 5 2 : 0 2

1 1 : 5 4 : 0 3

1 1 : 5 6 : 0 3

1 1 : 5 8 : 0 4

1 2 : 0 0 : 0 5

1 2 : 0 2 : 0 6

1 2 : 0 4 : 0 7

1 2 : 0 6 : 0 8

1 2 : 0 8 : 0 9

1 2 : 1 0 : 1 0

1 2 : 1 2 : 1 1

1 1 : 3 2 : 0 1

1 1 : 3 4 : 1 0

1 1 : 3 6 : 2 0

1 1

: 3 8 : 2 9

1 1 : 4 0 : 3 9

1 1 : 4 2 : 4 9

1 1 : 4 4 : 5 8

1 1 : 4 7 : 0 8

1 1 : 4 9 : 1 7

1 1 : 5 1 : 2 7

1 1 : 5 3 : 3 7

1 1 : 5 5 : 4 6

1 1

: 5 7 : 5 6

1 2 : 0 0 : 0 5

1 2

: 0 2 : 1 5

1 2 : 0 4 : 2 5

1 2 : 0 6 : 3 4

1 2 : 0 8 : 4 4

1 2

: 1 0 : 5 3

1 2 : 1 3 : 1 3

1 2 : 1 5 : 1 3

P o w e r , k W

FIG. 4. Test B, same setpoints as Test A but using PPA. Note smoothness.

-20

-20

0

0

20

40

60

80

100

120

140

Booster start

20

40

60

80

100

120

140

H e r t z

P r e s s u r e ,

p s i

P o w e r , k W

0 9

: 2 0 . 7

1 0 : 1 5 . 8

1

1 : 1 0 . 9

1 2

: 0 5 . 9

1 3 : 0 1 . 0

1 3 : 5 6 . 1

1 4 : 5 1 . 2

1 5

: 4 6 . 3

1 6 : 4 1 . 3

1 7 : 3 6 . 4

1 8 : 3 1 . 5

1 9

: 2 6 . 6

2 0 : 2 1 . 7

2

1 : 1 6 . 7

2

2 : 1 1 . 8

2 3

: 0 6 . 9

2 4

: 0 2 . 0

2

4 : 5 7 . 1

2 5 : 5 4 . 2

2 6

: 4 9 . 3

2 7 : 4 4 . 3

2 8

: 3 9 . 4

0 9 : 2 0 . 7

1 0 : 1 5 . 8

1 1 : 1 0 . 9

1 2 : 0 5 . 9

1 3 : 0 1 . 0

1 3 : 5 6 . 1

1 4 : 5 1 . 2

1 5 : 4 6 . 3

1 6 : 4 1 . 3

1 7 : 3 6 . 4

1 8 : 3 1 . 5

1 9 : 2 6 . 6

2 0 : 2 1 . 7

2 1 : 1 6 . 7

2 2 : 1 1 . 8

2 3 : 0 6 . 9

2 4 : 0 2 . 0

2 4 : 5 7 . 1

2 5 : 5 4 . 2

2 6 : 4 9 . 3

2 7 : 4 4 . 3

2 8 : 3 9 . 4

Pressure, psiHzHz

kWkWTotal

FIG. 5. PPA on one of two pumps operating in series. Header pressureis set at 95 psi.

7/22/2019 gulfpub_hp_201210.pdf


Rotating Equipment

PPA with across the line booster vs. load share. The blue pump drive in FIG. 5 was configured for PPA operation tocontrol pressure at a setpoint of 95 psi. The pressure setpoint

was chosen because it was obtainable by the 10-hp pump andmotor, but it would cause the pump to operate at an undesir-able efficiency level. The red pump drive was configured to

emulate a soft-start device—accelerating to 60 Hz, using a7.5 second acceleration time. At the top chart, the green lineshows the pressure on the common header, while the blue andred lines show the output frequency on the respective drives.The lower chart indicates kW consumed for each drive, as

well as total kW. In this example, the total power consumption(with both pumps running) is 118 kW.

FIG. 5 confirms, in the case of the pumps operating in seriesand running one at a fixed-line frequency is 36% less efficientthan an ASD with PPA for each pump. Operating one pumpat a fixed-line frequency and one with an ASD with PID soft-

ware would be 31% less efficient than an ASD with PPA foreach pump. The initial incremental cost of installing an ASD

with PPA for each pump would be quickly returned. Ineffi-ciencies will manifest themselves in the form of heat loss, vi-

bration energ y and mechanical stress. PPA software will, as inthis test case, be about 5% more energy efficient than a tradi-tional speed-control PID.

One ASD with PPA for each pump represents the lowestcost of ownership over the service life of the facility. The testresults, as shown in FIG. 6, demonstrate both pumps in PPA direct mode reacting to changes imposed by increasing or de-creasing the system pressure. The power does not change, andthe flows are balanced. In operations similar to this but withoutPPA, one pump would use most of the power and produce themajority of the flow; the second pump would use somewhatless electric power but contribute very little to the total flow.

Direct-mode load balance with an empty pipeline. Twoimportant pump control issues addressed by PPA software areillustrated in FIG. 7. First, PPA will limit pump overload thatnormally occurs when starting a pump on an empty pipeline.In this case, the pump having no restriction on flow would elec-trically overload. The PPA algorithm will, however, limit theoutput frequency to limit the output amperage. Also, preciseprocess control eliminates wasted energy. This is the key to en-

ergy savings. PPA cannot change pump efficiency or processpiping geometry, but it can limit wasted power due to mistakesin the process control introduced by traditional speed control.Second, this test demonstrated that the PPA software is also ca-pable of achieving identical power consumption by two pumpsoperating in parallel and feeding into a zero back-pressure

downstream environment—an empty pipeline.

-200

5 5 3

1 6 5 7

2 7 6 1

3 8 6 5

4 9 6 9

6 0 7 3

7 1 7 7

8 2 8 1

9 3 8 5

1 0 4 8 9

1 1 5 9 3

1 2 6 9 7

1 3 8 0 1

1 4 9 0 5

1 6 0 0 9

1 7 1 1 3

1 8 2 1 7

1 9 3 2 1

2 0 4 2 5

2 1 5 2 9

2 2 6 3 3

2 3 7 3 7

2 4 8 4 1

2 5 9 4 5

2 7 0 4 9

2 8 1 5 3

2 9 2 5 7

3 0 3 6 1

3 1 4 6 5

200

400

600

800

1,000

0

PowerPowerFlowFlow

P o w e r , k W

F l o w r a t e

, g p m

FIG. 6. Two pumps in PPA direct mode reacting to changing dischargeheader pressures imposed by manipulating a traditional control valve.

Pressure, psiHzHz

0

20

40

60

80

100

120

140

P o w e r ,

k W

P r e s s u r e

, p s i

0 6 : 3

6 . 8

0 6 : 4

4 . 9

0 6 : 5

2 . 9

0 7 : 0

1 . 0

0 7 : 0

9 . 0

0 7 : 1 7 .

0

0 7 : 2

5 . 1

0 7 : 3

3 . 1

0 7 : 4

5 . 2

0 7 : 5

7 . 2

0 8 : 2

1 . 4

0 8 : 4

9 . 5

0 9 : 0

5 . 6

1 0 : 3

0 . 1

1 0 : 5

8 . 2

0 9 : 4

0 . 6

1 0 : 3

3 . 1

1 1 : 0 3

. 4

1 1 : 1 9 . 6

1 1 : 2 3

. 6

FIG. 7. Pump startup without restriction on flow is made possible by PPA.

-400

-200

0

200

400

600

800

1,000

1,200

1,400

P r e s s u r e

, p s

i

P o w e r ,

k W

F l o w r a

t e ,

g p m

2 8 : 1 9 .

2

2 8 : 4

8 . 3

2 9 : 1 7 .

4

2 9 : 4

6 . 5

3 0 : 1 5 .

6

3 0 : 4

4 . 7

3 1 : 1 3 . 8

3 1 : 4 2 . 9

3 2 : 1 2 .

0

3 2 : 4 1 .

1

3 3 : 1 0 .

2

3 3 : 3 9 .

3

3 4 : 0

8 . 4

3 4 : 3 7 .

5

3 5 : 0

6 . 6

3 5 : 3 5 .

7

3 6 : 0

4 . 8

3 6 : 3 3 .

9

3 7 : 0

3 . 0

3 7 : 3 2 .

1

3 8 : 0 1 .

2

3 8 : 3 0 .

3

-20

0

20

40

60

80

100

120

2 8 : 1 9

. 2

2 8 : 4

8 . 3

2 9 : 1 7 .

4

2 9 : 4

6 . 5

3 0 : 1 5

. 6

3 0 : 4

4 . 7

3 1 : 1 3

. 8

3 1 : 4 2

. 9

3 2 : 1 2

. 0

3 2 : 4

1 . 1

3 3 : 1 0

. 2

3 3 : 3

9 . 3

3 4 : 0

8 . 4

3 4 : 3

7 . 5

3 5 : 0

6 . 6

3 5 : 3

5 . 7

3 6 : 0

4 . 8

3 6 : 3

3 . 9

3 7 : 0

3 . 0

3 7 : 3

2 . 1

3 8 : 0

1 . 2

3 8 : 3

0 . 3

kWkWTotal

Pressure, psiFlowrate

FIG. 8. In the direct-mode PPA series both the red-lined and blue-lined

pumps consume approximately the same amount of energy. Note: Thewide variations in flow and system pressure allowed in this test.

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Rotating Equipment

Series direct mode. As illustrated in FIG. 8, the PPA seriesdirect-mode test shows that, with PPA and system pressure in-creasing, the power remains balanced. Pressure is representedas the jagged bottom green line in FIG. 8, while power draws foreach of the two pumps remain close to identical (red and bluelines). The total power consumed is shown as the black line on

the kW vs. time graph.

MORE EFFICIENT PUMP OPERATIONS

Over time, pump manufacturers have improved the fluidmechanics in pump designs v ia increasingly more sophisticat-ed computer CAD/CAM modeling and automated machin-ing capabilities. This is the first advancement step. For thesecond advancement step, standard ASDs represent notableadvantages or innovations. In particular, ASDs achieve betterenergy efficiency because plain kW usage drops off along withthe voltage/frequency ratio.

PPAs represent another quantum step forward; it is poten-tially the third major development benefiting industry. The

PPA algorithm enables solving indirectly for the power draw of each individual machine, whether the machine(s) operatealone or in series. Solving indirectly for power in the Pump

Affinity Laws or in parallel has been missing from all conven-tional or traditional ASD methods. The new state-of-the-artPPA software addresses this issue and solves the problem.

Enabled by the PPA algorithm, a modern pump drive canquickly reach the desired setpoint. Among the many important

gains are enhanced energy efficiency and more rapid configura-tion of complex systems. In addition, operator training is simpli-fied. There is reduced damage potential for fluid machines.

Process control via traditional ASDs with centrifugal devices is encumbered by attempting to use a linear equation tosolve a nonlinear problem. By contrast, PPA software corrects

the power needed before any change is announced from thefeedback loop. This rapid before-the-fact correction yields atwo-fold advantage: more accurate process control and, conse-quently, less power consumed by the pump.

NOTES

1 Tests conducted at the Hydro, Inc., facilities in Chicago, Illinois. Extensive test-ing conducted at Hydro accurately measured every relevant parameter and thenassisted in defining the important differences between traditional approaches andthe PPA algorithms. All involved parties reached the conclusion that PPA softwareoffers unprecedented savings to owner-operators wishing to pursue optimizedand reliability-focused pump control.

NOMENCLATURE

ASD Adjustable speed driveCAD Computer aided designDCS Distributed control systemP Power, as represented by the Pump Affinity LawsPID Proportional integral derivativePLC Programmable logic controllerPPA Pump performance algorithm (a newly developed linear pump

performance algorithm)

ACKNOWLEDGMENT

This article was edited and refocused by Hydrocarbon Processing’s Equipmentand Reliability Editor, Heinz Bloch, P.E. His latest books, Pump Wisdom and the

widely read co-authored Pump User’s Handbook (3rd Ed., 2010), are among his 18comprehensive reliability textbooks.

KURT BIHLER has over 30 years of experience in industrial

controls. His past work experiences includes programming inthe US and Japan for SORD Computer Corp. Since 1993, he has

been president of Bihlertech, Inc., a company that specializes in

building pump station controls. Mr. Bihler is presently a

consultant to Toshiba, and is one of the co-inventors of an

advanced PPA algorithm.

DANA DOMINIAK holds a PhD in computer science from the

Illinois Institute of Technology. With programming experience in

many languages, including C and C++, she specializes in

advanced automation programming. In addition, she has

extensive experience programming graphical interfaces of

energy analysis systems for institutions such as Argonne

National Laboratory and the International Atomic Energy

Agency. Dr. Dominiak serves as an adjunct professor at Lewis University,

where she teaches courses in computer graphics and C/C++ Programming.

BRIAN KEITH has over 25 years of experience in industrial

automation and controls. Starting in the pharmaceutical

industry, he has studied under Dr. Melvin First at the Harvard

School of Public Health for specialized biological, chemical and

radiological containment systems. In 2007, he completed the

Georgia Tech Executive Management Training Program. Over

the past 15 years, he has focused mainly on the development

and marketing of adjustable speed drives for both industrial and commercial

markets. Mr. Keith was instrumental in the development and implementation of

PPA Technology into the Toshiba ADS family.

JEFF JOHNSON has 36 years of experience in the pump service

industry covering numerous markets. Having worked with

major OEMs around the world including, Sulzer and Flowserve,

he joined Hydro in 2009 and was appointed vice president of

Hydro’s petroleum and pipeline division. Supporting pump

users nationwide, he was instrumental in the design and

construction of Hydro’s 5000 HP Test Lab.

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ADVERTISER INDEX / HydrocarbonProcessing.com

The first number after the company name is the page on which an advertisement appears. The second number, appearing in parentheses, after the company

name, is the Reader Service Number. There are two ways readers can obtain product and service information:

1. Go to www.HydrocarbonProcessing.com/RS. Follow the instructions on the screen, and your request will be forwarded for immediate action.

2. Go online to the advertiser's Website listed below.

Company Page RS#Website



ae Solutions.............................................................101 (77)www.info.hotims.com/41433-77

Air Products & Chemicals Inc. ............................ .........27 (67)www.info.hotims.com/41433-67

AMACS ............................. ............................. ............25 (65)www.info.hotims.com/41433-65

Ametek Process Instruments ........................... .......... 60 (96)www.info.hotims.com/41433-96

Axens ............................. .............................. ..........104 (53)www.info.hotims.com/41433-53

BIC Alliance...............................................................17 (154)www.info.hotims.com/41433-154

Bryan Research & Engineering .......................... ........ 40 (71)www.info.hotims.com/41433-71

Burckhardt Compression AG ........................... ............ 13 (79)www.info.hotims.com/41433-79

Cameron ............................. ............................ ........ 50 (55)www.info.hotims.com/41433-55

Cashco Inc. ........................... ............................. ....... 12 (153)

www.info.hotims.com/41433-153CB&I .......................... ............................ ....... S-74–S-75 (97)

www.info.hotims.com/41433-97

Chemstations Inc........................................ ...............22 (157)www.info.hotims.com/41433-157

Colfax Americas ............................ ............................ 14 (86)www.info.hotims.com/41433-86

Cudd Energy Services ......................... ...................... 89 (166)www.info.hotims.com/41433-166

Emerson Process Mgmt (DeltaV) ........................... ...... 2 (63)www.info.hotims.com/41433-63

Enersul .......................... ............................ ...S-76–S-77 (68)www.info.hotims.com/41433-68

Flexim Americas Corp. .......................... .................... 20 (155)www.info.hotims.com/41433-155

Flexitallic LP .......................... ............................. ....... 5 (93)www.info.hotims.com/41433-93

Foster Wheeler ............................ .................S-78–S-79 (83)www.info.hotims.com/41433-83

FourQuest Energy............................ ......................... 24 (159)www.info.hotims.com/41433-159

Gulf Publishing CompanyConstruction Boxscore...........................................S-72

Events—EMGC .............................................S-68, S-73Events—WGLC ........................... .......................... S-82

HPI Market Data 2013 ............................................S-71HPI Marketplace ............................................... 98–99

Hydro, Inc. ............................. ............................. ..... 28 (72)www.info.hotims.com/41433-72

HyTorc .......................... ............................ ................37 (162)www.info.hotims.com/41433-162

Invensys ........................... ............................ ............ 18 (69)www.info.hotims.com/41433-69

KBR .......................... ............................. .................. 30 (59)www.info.hotims.com/41433-59

LA Turbine ............................. ............................. ....... 4 (151)www.info.hotims.com/41433-151

LAR Process Analysers .......................... .................... 49 (163)www.info.hotims.com/41433-163

Linde Process Plants ............................. ................... 103 (85)www.info.hotims.com/41433-85

Michell Instruments Inc. ........................... ................ 54 (164)www.info.hotims.com/41433-164

Milliken Workwear ......................... .......................... 46 (61)www.info.hotims.com/41433-61

PARCOL SpA ......................... ............................ ......... 11 (62)www.info.hotims.com/41433-62

Pittsburgh Corning Corporation ............................. .... 90 (91)www.info.hotims.com/41433-91

RC Systems ........................... .............................. ..... 26 (160)www.info.hotims.com/41433-160

Samson GmbH .......................... ............................ .... 31 (161)www.info.hotims.com/41433-161

Servomex Ltd................................ ............................ 21 (156)www.info.hotims.com/41433-156

Shell Global Solutions ................................... S-80–S-81

Sherwin Williams ............................ .......................... 32 (94)www.info.hotims.com/41433-94

Spraying Systems Co .......................... ........................ 8 (66)

www.info.hotims.com/41433-66Trachte USA ............................. ............................. ... 58 (165)

www.info.hotims.com/41433-165

Velan ......................... ............................ .................. 10 (152)www.info.hotims.com/41433-152

Winsted Corporation ............................. ....................23 (158)www.info.hotims.com/41433-158

Wood Group Mustang ......................... ...................... 97 (89)www.info.hotims.com/41433-89

ZymeFlow Decon Technology ......................... ........... 39 (92)www.info.hotims.com/41433-92

This Index and procedure for securing additional information is provided as a service to Hydrocarbon Processing advertisers and a convenience to our readers. Gulf Publishing Company is not responsible for omissions or errors.

Bret Ronk, Publisher

Phone: +1 (713) 529-4301Fax: +1 (713) 520-4433E-mail: [email protected]

SALES OFFICES—NORTH AMERICA

IL, LA, MO, OK, TXJosh MayerPhone: +1 (972) 816-6745, Fax: +1 (972) 767-4442E-mail: [email protected]

AK, AL, AR, AZ, CA, CO, FL, GA, HI, IA, ID, IN,KS, KY, MI, MN, MS, MT, ND, NE, NM, NV, OR,SD, TN, TX, UT, WA, WI, WY,WESTERN CANADA

Laura Kane

Phone: +1 (713) 520-4449, Fax: +1 (713) 520-4459Mobile: +1 (713) 412-2389E-mail: [email protected]

CT, DC, DE, MA, MD, ME, NC, NH, NJ, NY, OH,PA, RI, SC, VA, VT, WV,EASTERN CANADA

Merrie LynchPhone: +1 (617) 357-8190, Fax: +1 (617) 357-8194Mobile: +1 (617) 594-4943E-mail: [email protected]

CLASSIFIED SALES

Gerry MayerPhone: +1 (972) 816-3534, Fax: +1 (972) 767-4442E-mail: [email protected]

DATA PRODUCTS

Lee Nichols

Phone: +1 (713) 525-4626, Fax: +1 (713) 520-4433E-mail: [email protected]

SALES OFFICES—EUROPE

FRANCE, GREECE, NORTH AFRICA, MIDDLE EAST,

SPAIN, PORTUGAL, SOUTHERNBELGIUM, LUXEMBOURG, SWITZERLAND,GERMANY, AUSTRIA, TURKEY

Catherine Watkins

Tél.: +33 (0)1 30 47 92 51Fax: +33 (0)1 30 47 92 40

E-mail: [email protected]

ITALY, EASTERN EUROPEFabio Potestá

Mediapoint & Communications SRLPhone: +39 (010) 570-4948Fax: +39 (010) 553-0088E-mail: [email protected]

RUSSIA/FSULilia Fedotova

Anik International & Co. Ltd.Phone: +7 (495) 628-10-333E-mail: [email protected]

UNITED KINGDOM/SCANDINAVIA,NORTHERN BELGIUM, THE NETHERLANDS

Michael BrownPhone: +44 161 440 0854Mobile: +44 79866 34646E-mail: [email protected]

SALES OFFICES—OTHER AREAS

AUSTRALIA—PerthBrian Arnold

Phone: +61 (8) 9332-9839Fax: +61 (8) 9313-6442E-mail: [email protected]

CHINA—Hong KongIris Yuen

Phone: +86 13802701367, (China)Phone: +852 69185500, (Hong Kong)E-mail: [email protected]

BRAZIL—São PauloAlfred Bilyk

Phone/Fax: 11 23 37 42 40Mobile: 11 85 86 52 59E-mail: [email protected]

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JAPAN—TokyoYoshinori Ikeda

Pacific Business Inc.Phone: +81 (3) 3661-6138Fax: +81 (3) 3661-6139E-mail: [email protected]

KOREAD. S. Chai

Dongmyung Communications, Inc.Phone: +82 (2) 391 4254Fax: +82 (2) 391 4255E-mail: [email protected]

PAKISTAN—KarachiS. E. Ahmed

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WaterManagement

LORAINE A. HUCHLER, CONTRIBUTING [email protected]


Consider software tools for water reuse projects

The hydrocarbon processing industry needs reliable and economic sources of

water for present and future operations.Ensuring a sustainable water supply re-quires a focused effort to evaluate the qual-ity and quantity of alternative water sourc-es, reuse of individual water streams or thecombined outfall stream, and/or changingregulatory requirements.

Modeling. The most common method-ologies to analyze water circuits are pinchtechnology and mass balance/solutionmodeling. Application of classic pinchtechnology for water systems, as shownin FIG. 1, evaluates only the hydraulic de-mands for water.

Better option. A better solution is toconstruct a sophisticated computerizedmodel of the facility’s water systems thatincorporates hydraulic information, along

with ionic equilibria of soluble contami-nants. Like pinch technology, this ap-proach requires an accurate water balance.

FIG. 2 is a sample flow diagram withcolor-coded streams: steams—red, wa-ter—blue, recycled water—green and

wastewater—brown. This approach mod-els the ionic equilibria of the soluble con-taminants, providing information about

water quality for each unit operation.Modeling a water system also requires

creating a “salt” or contaminant balance.

The optimal approach is to profile water

quality throughout the system by analyz-ing numerous samples at every location,and then compare the actual water quality to the predicted value in the model. Whenthe actual water quality and flowrates close-ly match the predicted values, the modelis considered “validated” for the presentplant conditions—the baseline case.

A validated model allows the facility

to hypothetically reprocess water to meetthe specification limits for individual pro-cess units and to identify candidate waterstreams for reuse or retreatment (recy-cling). The model also provides insightinto the hydraulic and chemical impactson the unit and the total system balancesfor mass and salt concentrations.

This computerized modeling providesan accurate assessment of options: dif-ferent configurations and/or operatingscenarios to improve system operability,

justification capital improvement projects,optimization system reliability and mini-mization of the risk of off-spec or lost pro-duction. Embedded within this analysis is aprojection of the chemistry change for thecooling water. The only remaining analysisfor this unit operation is a separate model-ing task using a different software programto design an appropriate chemical-treat-ment program to control the corrosion,

deposition and microbiological popula-tions within the cooling water circuit.

Quality repurposing. As the quantity and quality of water decreases, industrialusers will need to increase their efforts toconserve, recycle water and conform toeven stricter regulatory requirements for

withdrawal and discharge. Software tools

can provide methods for plant personnelto quickly and economically analyze nu-merous system configurations providing ahigh level of confidence about the optionthat best meets their objectives.

LITERATURE CITED

1 EPRI document TA-114453, Electric Power ResearchInstitute, Inc., 1999.

2 Data Mobility Systems, a business of Nalco, www.datamobility.com, 2011.

Internal source

Fresh water

Purewater

Purity

Water sources

Water demands

Water pinch

Internalsink

Water flow

Wastewater

FIG. 1. Sample water-pinch diagram.1

City water

P re tre atme nt D ea era tor

Pretreatment Degasifier

Eastplant

Westplant

Process/letdown

Saetyshower/eyewash

Complex 5

tank farm

Wastetreatment

Wastetreatment

Processwaste

Truck ofsite

Sludgestorage

DWSD

DA

Eightcoolingtowers

Eastcomplexboilers

Westcomplexboilers

550/150/50psig

Process/letdown

600/150 psig

Limesotener

FIG. 2. Refinery water flow schematic.2

LORAINE A. HUCHLER

is president of MarTech

Systems, Inc., a consulting

firm that provides technicaladvisory services to

manage risk and optimize

energy- and water-related

systems including steam,

cooling and wastewater

in refineries and

petrochemical plants.

She holds a BS degree

in chemical engineering, along with professional

engineering licenses in New Jersey and Maryland,

and is a certified management consultant.

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LeadIng - Our People Create our Success

&XVWRPHUVDQGSHRSOHGULYH/LQGH3URFHVV3ODQWV,QFWREH/HDG,QJLQRXUľHOG2XUSHRSOHWDNHon challenges and create innovative solutions for our customers every day.

/RRNLQJIRUQHZFKDOOHQJHV",QDGGLWLRQWRRXUSURSULHWDU\WHFKQRORJLHVZHVXSSO\WKHRLODQGJDVUHľQLQJDQGSHWURFKHPLFDOLQGXVWULHVZLWKHQJLQHHULQJGHVLJQPDQXIDFWXULQJDQGconstruction.

Consider Linde Process Plants, Inc. for your next process plant or career.

Linde Process Plants, Inc.

6100 South Yale Avenue, Suite 1200, Tulsa, Oklahoma 74136, USA

Phone: +1.918.477.1200, Fax: +1.918.477.1100, www.LPPUSA.com, e-mail: [email protected]

Linde Process Plants, Inc. is an Equal Employment Opportunity Employer

Linde Process Plants, Inc.Accepting Challenges. Creating Solutions.

A member of The Linde Group


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